Below, you are given facts from the annual report for "VEOLIA ENVIRONNEMENT" for the fiscal year ended December 31, 2022. Based on these facts, your task will be to assess the suitability of the entity for the issuance of hybrid bonds (Strongly Suitable, Marginally Suitable, Not Suitable). -------------------- "Goodwill" 2022-01-01: 6201200000 EUR "Goodwill" 2023-01-01: 11637500000 EUR "Concession Intangible Assets" 2022-01-01: 3733800000 EUR "Concession Intangible Assets" 2023-01-01: 5291700000 EUR "Other Intangible Assets" 2022-01-01: 1300800000 EUR "Other Intangible Assets" 2023-01-01: 3142300000 EUR "Property Plant And Equipment" 2022-01-01: 8701900000 EUR "Property Plant And Equipment" 2023-01-01: 16569000000 EUR "Rightofuse Assets That Do Not Meet Definition Of Investment Property" 2022-01-01: 1562400000 EUR "Rightofuse Assets That Do Not Meet Definition Of Investment Property" 2023-01-01: 1997100000 EUR "Investments In Joint Ventures Accounted For Using Equity Method" 2022-01-01: 1238500000 EUR "Investments In Joint Ventures Accounted For Using Equity Method" 2023-01-01: 1197900000 EUR "Investments In Associates Accounted For Using Equity Method" 2022-01-01: 354200000 EUR "Investments In Associates Accounted For Using Equity Method" 2023-01-01: 786900000 EUR "Noncurrent Investments Other Than Investments Accounted For Using Equity Method" 2022-01-01: 3770300000 EUR "Noncurrent Investments Other Than Investments Accounted For Using Equity Method" 2023-01-01: 112500000 EUR "Actifs Financiers Operationnels Non Courants" 2022-01-01: 1191400000 EUR "Actifs Financiers Operationnels Non Courants" 2023-01-01: 1193800000 EUR "Noncurrent Derivative Financial Assets" 2022-01-01: 88500000 EUR "Noncurrent Derivative Financial Assets" 2023-01-01: 127800000 EUR "Other Noncurrent Financial Assets" 2022-01-01: 431200000 EUR "Other Noncurrent Financial Assets" 2023-01-01: 483200000 EUR "Deferred Tax Assets" 2022-01-01: 1059200000 EUR "Deferred Tax Assets" 2023-01-01: 2050800000 EUR "Noncurrent Assets" 2022-01-01: 29633400000 EUR "Noncurrent Assets" 2023-01-01: 44590500000 EUR "Inventories" 2022-01-01: 816300000 EUR "Inventories" 2023-01-01: 1486200000 EUR "Operating Receivables" 2022-01-01: 10015300000 EUR "Operating Receivables" 2023-01-01: 14533500000 EUR "Actifs Financiers Operationnels Courants" 2022-01-01: 129000000 EUR "Actifs Financiers Operationnels Courants" 2023-01-01: 182800000 EUR "Other Current Financial Assets" 2022-01-01: 1521000000 EUR "Other Current Financial Assets" 2023-01-01: 2213500000 EUR "Current Derivative Financial Assets" 2022-01-01: 344900000 EUR "Current Derivative Financial Assets" 2023-01-01: 634400000 EUR "Cash And Cash Equivalents" 2022-01-01: 10518700000 EUR "Cash And Cash Equivalents" 2023-01-01: 9012200000 EUR "Noncurrent Assets Or Disposal Groups Classified As Held For Sale" 2022-01-01: 98700000 EUR "Noncurrent Assets Or Disposal Groups Classified As Held For Sale" 2023-01-01: 651000000 EUR "Current Assets" 2022-01-01: 23443900000 EUR "Current Assets" 2023-01-01: 28713600000 EUR "Assets" 2022-01-01: 53077300000 EUR "Assets" 2023-01-01: 73304100000 EUR "Nonconsolidated Other Securities" 2023-01-01: 112500000 EUR "Nonconsolidated Suez Shares" 2022-01-01: 3721000000 EUR "Nonconsolidated Other Securities" 2022-01-01: 49000000 EUR "Issued Capital" 2022-01-01: 3498600000 EUR "Issued Capital" 2023-01-01: 3572900000 EUR "Additional Paidin Capital" 2022-01-01: 9309500000 EUR "Additional Paidin Capital" 2023-01-01: 9470200000 EUR "Titres Super Subordonnes ADuree Indeterminee" 2022-01-01: 2460700000 EUR "Titres Super Subordonnes ADuree Indeterminee" 2023-01-01: 3496300000 EUR "Reserves And Retained Earnings Attributable To Owners Of The Company" 2022-01-01: -3750800000 EUR "Reserves And Retained Earnings Attributable To Owners Of The Company" 2023-01-01: -4284700000 EUR "Equity Attributable To Owners Of Parent" 2022-01-01: 11518000000 EUR "Equity Attributable To Owners Of Parent" 2023-01-01: 12254700000 EUR "Noncontrolling Interests" 2022-01-01: 1252100000 EUR "Noncontrolling Interests" 2023-01-01: 2612200000 EUR "Equity" 2022-01-01: 12770000000 EUR "Equity" 2023-01-01: 14866900000 EUR "Noncurrent Provisions" 2022-01-01: 1876600000 EUR "Noncurrent Provisions" 2023-01-01: 2844400000 EUR "Noncurrent Financial Liabilities Excluding Concession Liabilities" 2022-01-01: 10462500000 EUR "Noncurrent Financial Liabilities Excluding Concession Liabilities" 2023-01-01: 19692100000 EUR "Noncurrent Lease Liabilities" 2022-01-01: 1298100000 EUR "Noncurrent Lease Liabilities" 2023-01-01: 1656200000 EUR "Noncurrent Derivative Financial Liabilities" 2022-01-01: 68800000 EUR "Noncurrent Derivative Financial Liabilities" 2023-01-01: 720200000 EUR "Noncurrent Concession Liabilities" 2022-01-01: 1588400000 EUR "Noncurrent Concession Liabilities" 2023-01-01: 1680500000 EUR "Deferred Tax Liabilities" 2022-01-01: 1196400000 EUR "Deferred Tax Liabilities" 2023-01-01: 2640100000 EUR "Noncurrent Liabilities" 2022-01-01: 16490800000 EUR "Noncurrent Liabilities" 2023-01-01: 29233500000 EUR "Operating Payables" 2022-01-01: 13548900000 EUR "Operating Payables" 2023-01-01: 19475200000 EUR "Current Concession Liabilities" 2022-01-01: 169400000 EUR "Current Concession Liabilities" 2023-01-01: 243200000 EUR "Current Provisions" 2022-01-01: 538500000 EUR "Current Provisions" 2023-01-01: 1015300000 EUR "Current Financial Liabilities Excluding Concession Liabilities" 2022-01-01: 8624300000 EUR "Current Financial Liabilities Excluding Concession Liabilities" 2023-01-01: 6521400000 EUR "Current Lease Liabilities" 2022-01-01: 410600000 EUR "Current Lease Liabilities" 2023-01-01: 496500000 EUR "Current Derivative Financial Liabilities" 2022-01-01: 261500000 EUR "Current Derivative Financial Liabilities" 2023-01-01: 883400000 EUR "Bank Overdrafts And Other Cash Position Items" 2022-01-01: 241900000 EUR "Bank Overdrafts And Other Cash Position Items" 2023-01-01: 213600000 EUR "Liabilities Included In Disposal Groups Classified As Held For Sale" 2022-01-01: 21400000 EUR "Liabilities Included In Disposal Groups Classified As Held For Sale" 2023-01-01: 355100000 EUR "Current Liabilities" 2022-01-01: 23816500000 EUR "Current Liabilities" 2023-01-01: 29203700000 EUR "Equity And Liabilities" 2022-01-01: 53077300000 EUR "Equity And Liabilities" 2023-01-01: 73304100000 EUR "Revenue From Contracts With Customers" 2021-01-01 - 2022-01-01: 28508100000 EUR "Revenue From Contracts With Customers" 2022-01-01 - 2023-01-01: 42885300000 EUR "Cost Of Sales" 2021-01-01 - 2022-01-01: 23905900000 EUR "Cost Of Sales" 2022-01-01 - 2023-01-01: 35739800000 EUR "Selling Expense" 2021-01-01 - 2022-01-01: 584000000 EUR "Selling Expense" 2022-01-01 - 2023-01-01: 954200000 EUR "General And Administrative Expense" 2021-01-01 - 2022-01-01: 2308600000 EUR "General And Administrative Expense" 2022-01-01 - 2023-01-01: 3215800000 EUR "Other Operating Income Expense" 2021-01-01 - 2022-01-01: -496900000 EUR "Other Operating Income Expense" 2022-01-01 - 2023-01-01: -769200000 EUR "Operating Income Before Share Of Net Income Loss Of Equity Accounted Entities" 2021-01-01 - 2022-01-01: 1212700000 EUR "Operating Income Before Share Of Net Income Loss Of Equity Accounted Entities" 2022-01-01 - 2023-01-01: 2206300000 EUR "Share Of Net Income Loss Of Core Equity Accounted Entities" 2021-01-01 - 2022-01-01: 104800000 EUR "Share Of Net Income Loss Of Core Equity Accounted Entities" 2022-01-01 - 2023-01-01: 127000000 EUR "Share Of Net Income Loss Of Core Joint Ventures" 2021-01-01 - 2022-01-01: 74000000 EUR "Share Of Net Income Loss Of Core Joint Ventures" 2022-01-01 - 2023-01-01: 56500000 EUR "Share Of Net Income Loss Of Core Associates" 2021-01-01 - 2022-01-01: 30800000 EUR "Share Of Net Income Loss Of Core Associates" 2022-01-01 - 2023-01-01: 70500000 EUR "Resultat Operationnel Apres Quote Part De Resultat Net Dans Les Entites Mises En Equivalence" 2021-01-01 - 2022-01-01: 1317500000 EUR "Resultat Operationnel Apres Quote Part De Resultat Net Dans Les Entites Mises En Equivalence" 2022-01-01 - 2023-01-01: 2333300000 EUR "Net Finance Costs" 2021-01-01 - 2022-01-01: -342600000 EUR "Net Finance Costs" 2022-01-01 - 2023-01-01: -632700000 EUR "Other Finance Income Cost" 2021-01-01 - 2022-01-01: -74200000 EUR "Other Finance Income Cost" 2022-01-01 - 2023-01-01: -204600000 EUR "Profit Loss Before Tax" 2021-01-01 - 2022-01-01: 900700000 EUR "Profit Loss Before Tax" 2022-01-01 - 2023-01-01: 1496000000 EUR "Income Tax Expense Continuing Operations" 2021-01-01 - 2022-01-01: 345800000 EUR "Income Tax Expense Continuing Operations" 2022-01-01 - 2023-01-01: 419800000 EUR "Profit Loss From Continuing Operations" 2021-01-01 - 2022-01-01: 554900000 EUR "Profit Loss From Continuing Operations" 2022-01-01 - 2023-01-01: 1076200000 EUR "Profit Loss From Discontinued Operations" 2021-01-01 - 2022-01-01: 0 EUR "Profit Loss From Discontinued Operations" 2022-01-01 - 2023-01-01: -78600000 EUR "Profit Loss" 2021-01-01 - 2022-01-01: 554900000 EUR "Profit Loss" 2022-01-01 - 2023-01-01: 997600000 EUR "Profit Loss Attributable To Owners Of Parent" 2021-01-01 - 2022-01-01: 404300000 EUR "Profit Loss Attributable To Owners Of Parent" 2022-01-01 - 2023-01-01: 715800000 EUR "Profit Loss Attributable To Noncontrolling Interests" 2021-01-01 - 2022-01-01: 150600000 EUR "Profit Loss Attributable To Noncontrolling Interests" 2022-01-01 - 2023-01-01: 281800000 EUR "Basic Earnings Loss Per Share" 2021-01-01 - 2022-01-01: 0.68 EUR/shares "Basic Earnings Loss Per Share" 2022-01-01 - 2023-01-01: 1.04 EUR/shares "Diluted Earnings Loss Per Share" 2021-01-01 - 2022-01-01: 0.65 EUR/shares "Diluted Earnings Loss Per Share" 2022-01-01 - 2023-01-01: 1 EUR/shares "Basic Earnings Loss Per Share From Continuing Operations" 2021-01-01 - 2022-01-01: 0.68 EUR/shares "Basic Earnings Loss Per Share From Continuing Operations" 2022-01-01 - 2023-01-01: 1.15 EUR/shares "Diluted Earnings Loss Per Share From Continuing Operations" 2021-01-01 - 2022-01-01: 0.65 EUR/shares "Diluted Earnings Loss Per Share From Continuing Operations" 2022-01-01 - 2023-01-01: 1.11 EUR/shares "Basic Earnings Loss Per Share From Discontinued Operations" 2021-01-01 - 2022-01-01: 0 EUR/shares "Basic Earnings Loss Per Share From Discontinued Operations" 2022-01-01 - 2023-01-01: -0.11 EUR/shares "Diluted Earnings Loss Per Share From Discontinued Operations" 2021-01-01 - 2022-01-01: 0 EUR/shares "Diluted Earnings Loss Per Share From Discontinued Operations" 2022-01-01 - 2023-01-01: -0.11 EUR/shares "Other Comprehensive Income Before Tax Gains Losses On Remeasurements Of Defined Benefit Plans" 2021-01-01 - 2022-01-01: 68200000 EUR "Other Comprehensive Income Before Tax Gains Losses On Remeasurements Of Defined Benefit Plans" 2022-01-01 - 2023-01-01: 125200000 EUR "Income Tax Relating To Remeasurements Of Defined Benefit Plans Of Other Comprehensive Income" 2021-01-01 - 2022-01-01: 5500000 EUR "Income Tax Relating To Remeasurements Of Defined Benefit Plans Of Other Comprehensive Income" 2022-01-01 - 2023-01-01: 9100000 EUR "Other Comprehensive Income Net Of Tax Gains Losses On Remeasurements Of Defined Benefit Plans" 2021-01-01 - 2022-01-01: 62700000 EUR "Other Comprehensive Income Net Of Tax Gains Losses On Remeasurements Of Defined Benefit Plans" 2022-01-01 - 2023-01-01: 116100000 EUR "Other Comprehensive Income Before Tax Gains Losses From Investments In Equity Instruments" 2021-01-01 - 2022-01-01: 662100000 EUR "Other Comprehensive Income Before Tax Gains Losses From Investments In Equity Instruments" 2022-01-01 - 2023-01-01: 5800000 EUR "Income Tax Relating To Investments In Equity Instruments Of Other Comprehensive Income" 2021-01-01 - 2022-01-01: -2700000 EUR "Income Tax Relating To Investments In Equity Instruments Of Other Comprehensive Income" 2022-01-01 - 2023-01-01: -200000 EUR "Other Comprehensive Income Net Of Tax Gains Losses From Investments In Equity Instruments" 2021-01-01 - 2022-01-01: 664800000 EUR "Other Comprehensive Income Net Of Tax Gains Losses From Investments In Equity Instruments" 2022-01-01 - 2023-01-01: 6000000 EUR "Other Comprehensive Income That Will Not Be Reclassified To Profit Or Loss Net Of Tax" 2021-01-01 - 2022-01-01: 727500000 EUR "Other Comprehensive Income That Will Not Be Reclassified To Profit Or Loss Net Of Tax" 2022-01-01 - 2023-01-01: 122100000 EUR "Other Items Of Comprehensive Income Not Subsequently Released To Net Income Attributable To Joint Ventures" 2021-01-01 - 2022-01-01: -9700000 EUR "Other Items Of Comprehensive Income Not Subsequently Released To Net Income Attributable To Joint Ventures" 2022-01-01 - 2023-01-01: 400000 EUR "Other Items Of Comprehensive Income Not Subsequently Released To Net Income Attributable To Associates" 2021-01-01 - 2022-01-01: 100000 EUR "Other Items Of Comprehensive Income Not Subsequently Released To Net Income Attributable To Associates" 2022-01-01 - 2023-01-01: 0 EUR "Ajustements De Valeur Sur Cout De La Couverture" 2021-01-01 - 2022-01-01: 50300000 EUR "Ajustements De Valeur Sur Cout De La Couverture" 2022-01-01 - 2023-01-01: -40800000 EUR "Impots" 2021-01-01 - 2022-01-01: 0 EUR "Impots" 2022-01-01 - 2023-01-01: 0 EUR "Montant Net Dimpots" 2021-01-01 - 2022-01-01: 50300000 EUR "Montant Net Dimpots" 2022-01-01 - 2023-01-01: -40800000 EUR "Other Comprehensive Income Before Tax Financial Assets Measured At Fair Value Through Other Comprehensive Income" 2021-01-01 - 2022-01-01: 0 EUR "Other Comprehensive Income Before Tax Financial Assets Measured At Fair Value Through Other Comprehensive Income" 2022-01-01 - 2023-01-01: 0 EUR "Income Tax Relating To Financial Assets Measured At Fair Value Through Other Comprehensive Income" 2021-01-01 - 2022-01-01: 0 EUR "Income Tax Relating To Financial Assets Measured At Fair Value Through Other Comprehensive Income" 2022-01-01 - 2023-01-01: 0 EUR "Other Comprehensive Income Net Of Tax Financial Assets Measured At Fair Value Through Other Comprehensive Income" 2021-01-01 - 2022-01-01: 0 EUR "Other Comprehensive Income Net Of Tax Financial Assets Measured At Fair Value Through Other Comprehensive Income" 2022-01-01 - 2023-01-01: 0 EUR "Other Comprehensive Income Before Tax Cash Flow Hedges" 2021-01-01 - 2022-01-01: 140600000 EUR "Other Comprehensive Income Before Tax Cash Flow Hedges" 2022-01-01 - 2023-01-01: -163400000 EUR "Income Tax Relating To Cash Flow Hedges Of Other Comprehensive Income" 2021-01-01 - 2022-01-01: 37400000 EUR "Income Tax Relating To Cash Flow Hedges Of Other Comprehensive Income" 2022-01-01 - 2023-01-01: -56600000 EUR "Other Comprehensive Income Net Of Tax Cash Flow Hedges" 2021-01-01 - 2022-01-01: 103200000 EUR "Other Comprehensive Income Net Of Tax Cash Flow Hedges" 2022-01-01 - 2023-01-01: -106800000 EUR "Other Comprehensive Income Before Tax Exchange Differences On Translation" 2021-01-01 - 2022-01-01: 235400000 EUR "Other Comprehensive Income Before Tax Exchange Differences On Translation" 2022-01-01 - 2023-01-01: 214400000 EUR "Other Comprehensive Income Net Of Tax Exchange Differences On Translation" 2021-01-01 - 2022-01-01: 235400000 EUR "Other Comprehensive Income Net Of Tax Exchange Differences On Translation" 2022-01-01 - 2023-01-01: 214400000 EUR "Other Comprehensive Income Before Tax Hedges Of Net Investments In Foreign Operations" 2021-01-01 - 2022-01-01: -53100000 EUR "Other Comprehensive Income Before Tax Hedges Of Net Investments In Foreign Operations" 2022-01-01 - 2023-01-01: 23800000 EUR "Income Tax Relating To Hedges Of Net Investments In Foreign Operations Of Other Comprehensive Income" 2021-01-01 - 2022-01-01: 200000 EUR "Income Tax Relating To Hedges Of Net Investments In Foreign Operations Of Other Comprehensive Income" 2022-01-01 - 2023-01-01: 4300000 EUR "Other Comprehensive Income Net Of Tax Hedges Of Net Investments In Foreign Operations" 2021-01-01 - 2022-01-01: -53300000 EUR "Other Comprehensive Income Net Of Tax Hedges Of Net Investments In Foreign Operations" 2022-01-01 - 2023-01-01: 19500000 EUR "Other Comprehensive Income That Will Be Reclassified To Profit Or Loss Net Of Tax" 2021-01-01 - 2022-01-01: 335600000 EUR "Other Comprehensive Income That Will Be Reclassified To Profit Or Loss Net Of Tax" 2022-01-01 - 2023-01-01: 86300000 EUR "Other Items Of Comprehensive Income Subsequently Released To Net Income Attributable To Joint Ventures" 2021-01-01 - 2022-01-01: 64300000 EUR "Other Items Of Comprehensive Income Subsequently Released To Net Income Attributable To Joint Ventures" 2022-01-01 - 2023-01-01: -70000000 EUR "Other Items Of Comprehensive Income Subsequently Released To Net Income Attributable To Associates" 2021-01-01 - 2022-01-01: 8700000 EUR "Other Items Of Comprehensive Income Subsequently Released To Net Income Attributable To Associates" 2022-01-01 - 2023-01-01: 14800000 EUR "Other Comprehensive Income" 2021-01-01 - 2022-01-01: 1063000000 EUR "Other Comprehensive Income" 2022-01-01 - 2023-01-01: 208400000 EUR "Comprehensive Income" 2021-01-01 - 2022-01-01: 1617900000 EUR "Comprehensive Income" 2022-01-01 - 2023-01-01: 1206000000 EUR "Comprehensive Income Attributable To Owners Of Parent" 2021-01-01 - 2022-01-01: 1383000000 EUR "Comprehensive Income Attributable To Owners Of Parent" 2022-01-01 - 2023-01-01: 972200000 EUR "Comprehensive Income Attributable To Noncontrolling Interests" 2021-01-01 - 2022-01-01: 234900000 EUR "Comprehensive Income Attributable To Noncontrolling Interests" 2022-01-01 - 2023-01-01: 233800000 EUR "Fair Value Adjustments On Financial Instruments At Fair Value Through Equity Not Subsequently Released To Net Income Relating To The Acquisition Of Suez" 2021-01-01 - 2022-01-01: 672000000 EUR "Operating Depreciation Amortization Provisions And Impairment Losses" 2021-01-01 - 2022-01-01: 2117200000 EUR "Operating Depreciation Amortization Provisions And Impairment Losses" 2022-01-01 - 2023-01-01: 3178600000 EUR "Financial Amortization And Impairment Losses" 2021-01-01 - 2022-01-01: 3800000 EUR "Financial Amortization And Impairment Losses" 2022-01-01 - 2023-01-01: 14800000 EUR "Gains Losses On Disposal Of Operating Assets" 2021-01-01 - 2022-01-01: -39200000 EUR "Gains Losses On Disposal Of Operating Assets" 2022-01-01 - 2023-01-01: -299000000 EUR "Plus Ou Moins Values De Cessions Dactifs Financiers" 2021-01-01 - 2022-01-01: 1200000 EUR "Plus Ou Moins Values De Cessions Dactifs Financiers" 2022-01-01 - 2023-01-01: -370000000 EUR "Share Of Net Income Loss Of Joint Ventures" 2021-01-01 - 2022-01-01: 74100000 EUR "Share Of Net Income Loss Of Joint Ventures" 2022-01-01 - 2023-01-01: 56500000 EUR "Adjustments For Undistributed Profits Of Associates" 2021-01-01 - 2022-01-01: 30800000 EUR "Adjustments For Undistributed Profits Of Associates" 2022-01-01 - 2023-01-01: 70500000 EUR "Adjustments For Dividend Income" 2021-01-01 - 2022-01-01: 124200000 EUR "Adjustments For Dividend Income" 2022-01-01 - 2023-01-01: 4100000 EUR "Net Finance Costs Adjustments" 2021-01-01 - 2022-01-01: 342600000 EUR "Net Finance Costs Adjustments" 2022-01-01 - 2023-01-01: 632700000 EUR "Adjustments For Income Tax Expense" 2021-01-01 - 2022-01-01: 345800000 EUR "Adjustments For Income Tax Expense" 2022-01-01 - 2023-01-01: 419800000 EUR "Other Adjustments To Reconcile Profit Loss" 2021-01-01 - 2022-01-01: 116000000 EUR "Other Adjustments To Reconcile Profit Loss" 2022-01-01 - 2023-01-01: 282300000 EUR "Cash Flows From Used In Operations Before Changes In Working Capital" 2021-01-01 - 2022-01-01: 3213200000 EUR "Cash Flows From Used In Operations Before Changes In Working Capital" 2022-01-01 - 2023-01-01: 4804300000 EUR "Change In Operating Working Capital Requirements" 2021-01-01 - 2022-01-01: -382500000 EUR "Change In Operating Working Capital Requirements" 2022-01-01 - 2023-01-01: -48000000 EUR "Change In Concession Working Capital Requirements" 2021-01-01 - 2022-01-01: 146300000 EUR "Change In Concession Working Capital Requirements" 2022-01-01 - 2023-01-01: 190500000 EUR "Income Taxes Paid Refund Classified As Operating Activities" 2021-01-01 - 2022-01-01: 285600000 EUR "Income Taxes Paid Refund Classified As Operating Activities" 2022-01-01 - 2023-01-01: 557400000 EUR "Cash Flows From Used In Operating Activities Continuing Operations" 2021-01-01 - 2022-01-01: 3163800000 EUR "Cash Flows From Used In Operating Activities Continuing Operations" 2022-01-01 - 2023-01-01: 4104400000 EUR "Cash Flows From Used In Operating Activities Discontinued Operations" 2021-01-01 - 2022-01-01: -16600000 EUR "Cash Flows From Used In Operating Activities Discontinued Operations" 2022-01-01 - 2023-01-01: 43800000 EUR "Cash Flows From Used In Operating Activities" 2021-01-01 - 2022-01-01: 3147200000 EUR "Cash Flows From Used In Operating Activities" 2022-01-01 - 2023-01-01: 4148200000 EUR "Investissements Industriels Nets De Subvention" 2021-01-01 - 2022-01-01: 1728800000 EUR "Investissements Industriels Nets De Subvention" 2022-01-01 - 2023-01-01: 2783600000 EUR "Cessions Dactifs Industriels" 2021-01-01 - 2022-01-01: 316400000 EUR "Cessions Dactifs Industriels" 2022-01-01 - 2023-01-01: 598000000 EUR "Purchase Of Financial Instruments Classified As Investing Activities" 2021-01-01 - 2022-01-01: 327200000 EUR "Purchase Of Financial Instruments Classified As Investing Activities" 2022-01-01 - 2023-01-01: 4009400000 EUR "Proceeds From Sales Or Maturity Of Financial Instruments Classified As Investing Activities" 2021-01-01 - 2022-01-01: 470100000 EUR "Proceeds From Sales Or Maturity Of Financial Instruments Classified As Investing Activities" 2022-01-01 - 2023-01-01: 9995100000 EUR "New Operating Financial Assets" 2021-01-01 - 2022-01-01: -166600000 EUR "New Operating Financial Assets" 2022-01-01 - 2023-01-01: -182400000 EUR "Principal Payments On Operating Financial Assets" 2021-01-01 - 2022-01-01: 251400000 EUR "Principal Payments On Operating Financial Assets" 2022-01-01 - 2023-01-01: 195400000 EUR "Dividends Received Classified As Investing Activities" 2021-01-01 - 2022-01-01: 223100000 EUR "Dividends Received Classified As Investing Activities" 2022-01-01 - 2023-01-01: 128600000 EUR "New Noncurrent Loans Granted" 2021-01-01 - 2022-01-01: 141800000 EUR "New Noncurrent Loans Granted" 2022-01-01 - 2023-01-01: 105200000 EUR "Principal Payments On Noncurrent Loans" 2021-01-01 - 2022-01-01: 224600000 EUR "Principal Payments On Noncurrent Loans" 2022-01-01 - 2023-01-01: 109200000 EUR "Net Decrease Increase In Current Loans" 2021-01-01 - 2022-01-01: 28200000 EUR "Net Decrease Increase In Current Loans" 2022-01-01 - 2023-01-01: 484000000 EUR "Cash Flows From Used In Investing Activities Continuing Operations" 2021-01-01 - 2022-01-01: -850600000 EUR "Cash Flows From Used In Investing Activities Continuing Operations" 2022-01-01 - 2023-01-01: 4429700000 EUR "Cash Flows From Used In Investing Activities Discontinued Operations" 2021-01-01 - 2022-01-01: 0 EUR "Cash Flows From Used In Investing Activities Discontinued Operations" 2022-01-01 - 2023-01-01: 93800000 EUR "Cash Flows From Used In Investing Activities" 2021-01-01 - 2022-01-01: -850600000 EUR "Cash Flows From Used In Investing Activities" 2022-01-01 - 2023-01-01: 4523500000 EUR "Cash Flows From Used In Increase Decrease In Current Borrowings" 2021-01-01 - 2022-01-01: -38600000 EUR "Cash Flows From Used In Increase Decrease In Current Borrowings" 2022-01-01 - 2023-01-01: -4138100000 EUR "Change In Current Lease Debt Ifrs16" 2021-01-01 - 2022-01-01: 455200000 EUR "Change In Current Lease Debt Ifrs16" 2022-01-01 - 2023-01-01: 552900000 EUR "Repayment Of New Noncurrent Lease Debt" 2021-01-01 - 2022-01-01: 123300000 EUR "Repayment Of New Noncurrent Lease Debt" 2022-01-01 - 2023-01-01: 130400000 EUR "Proceeds From Borrowings Classified As Financing Activities" 2021-01-01 - 2022-01-01: 931400000 EUR "Proceeds From Borrowings Classified As Financing Activities" 2022-01-01 - 2023-01-01: 879400000 EUR "Repayments Of Borrowings Classified As Financing Activities" 2021-01-01 - 2022-01-01: 51200000 EUR "Repayments Of Borrowings Classified As Financing Activities" 2022-01-01 - 2023-01-01: 1650300000 EUR "Change In Liquid Assets And Financing Financial Assets" 2021-01-01 - 2022-01-01: -135500000 EUR "Change In Liquid Assets And Financing Financial Assets" 2022-01-01 - 2023-01-01: -705100000 EUR "Proceeds From Issuing Shares" 2021-01-01 - 2022-01-01: 2672300000 EUR "Proceeds From Issuing Shares" 2022-01-01 - 2023-01-01: 226700000 EUR "Share Capital Reduction" 2021-01-01 - 2022-01-01: 0 EUR "Share Capital Reduction" 2022-01-01 - 2023-01-01: 0 EUR "Payments From Changes In Ownership Interests In Subsidiaries" 2021-01-01 - 2022-01-01: 2700000 EUR "Payments From Changes In Ownership Interests In Subsidiaries" 2022-01-01 - 2023-01-01: 1769500000 EUR "Proceeds From Changes In Ownership Interests In Subsidiaries" 2021-01-01 - 2022-01-01: 500000 EUR "Proceeds From Changes In Ownership Interests In Subsidiaries" 2022-01-01 - 2023-01-01: 7900000 EUR "Issue Repayment Of Deeply Subordinated Securities" 2021-01-01 - 2022-01-01: 497500000 EUR "Issue Repayment Of Deeply 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Distributions To Owners Per Share" 2021-01-01 - 2022-01-01: 0.7 EUR/shares "Dividends Proposed Or Declared Before Financial Statements Authorised For Issue But Not Recognised As Distribution To Owners Per Share" 2022-01-01 - 2023-01-01: 1.12 EUR/shares "Script Dividends" 2021-01-01 - 2022-01-01: 0 EUR "Dividends Paid" 2021-01-01 - 2022-01-01: 534300000 EUR "Dividends Paid" 2022-01-01 - 2023-01-01: 990200000 EUR "Name Of Reporting Entity Or Other Means Of Identification" "fr" 2022-01-01 - 2023-01-01: Veolia Environnement "Address Of Registered Office Of Entity" "fr" 2022-01-01 - 2023-01-01: 21, rue La Boétie – 75008 Paris "Country Of Incorporation" "fr" 2022-01-01 - 2023-01-01: – France "Domicile Of Entity" "fr" 2022-01-01 - 2023-01-01: – France "Legal Form Of Entity" "fr" 2022-01-01 - 2023-01-01: Société anonyme à conseil d’administration -------------------- Here is a description of the S&P rating methodology for specific industries: # Regulated Utilities ## Business Risk Profile ### Regulatory advantage Market forces are not typically the main driver of competitive position for regulated utilities, and therefore we do not measure competitive advantage in the same way as we do for competitive firms. Instead, we assess regulatory advantage because the influence of the regulatory framework and regime is of critical importance. It defines the environment in which a utility operates and has a significant bearing on a utility's financial performance. Regulations vary across different regulatory jurisdictions, that is, the area over which a regulator has oversight. Each regulatory jurisdiction can include one or more subsectors (water, gas, and power). A geographic region may have several regulatory jurisdictions. We determine the regulatory advantage assessment by combining: - Our preliminary regulatory advantage assessment, resulting from our review of the four subfactors that we believe are key for a utility to recover all its costs-- on time and in full-- and to earn a return on the capital it deploys; and - Our view of the utility's business strategy--in particular, its regulatory strategy and its ability to manage the tariff-setting process. We assess the preliminary regulatory advantage assessment for each regulatory jurisdiction based on: - Regulatory stability, - Tariff-setting procedures and design, - Financial stability, and - Regulatory independence and insulation. **Regulatory stability:** Our view is based on how transparent the key components of the rate-setting process are, and how they are assessed. We also monitor the predictability and consistency of the regulatory framework over time. Greater consistency reduces uncertainty for the utility and its stakeholders. **Tariff-setting procedures and design:** Our view is based on whether all operating and capital costs can be recovered in full, and how the rate scheme balances the interests and concerns of all stakeholders. We look for incentives that are achievable, contained, and symmetrical (that is, mostly indexed to overperformance and underperformance). **Financial stability:** If costs are recovered in a timely manner, cash flow volatility can be avoided. We see greater flexibility as favorable, because it allows for the recovery of unexpected costs. Financial stability also depends on the framework's ability to attract long-term capital, and the availability of capital support during construction, to alleviate funding and cash flow pressure when heavy investment is needed. ### Sector description Companies that provide an essential or nearessential infrastructure product, commodity, or service that has few or no substitutes and are shielded from competition, while also being subject to comprehensive regulation by a regulatory body or oversight by a public body. | Subsectors Typical | CPGP | |---|---| | Electricity National | industry and utilities | | Gas | National industry and utilities | | Multi-utilities | National industry and utilities | | Water | National industry and utilities | ### Other adjustments To calculate a company's financial metrics, please refer to the sector-specific adjustments in "Corporate Methodology: Ratios And Adjustments." Our sector-specific liquidity considerations are described in "Methodology And Assumptions: Liquidity Descriptors For Global Corporate Issuers." **Regulated Utilities Regulatory independence and insulation:** We consider this to be stronger where the market framework and energy policies support the long-term financial stability of the utilities, are clearly enshrined in law, and protect the regulator's independence. Where there is limited risk of political intervention, the regulator is more able to efficiently protect the utility's credit profile, even during a stressful event. Preliminary regulatory advantage: typical characteristics | Strong or strong/adequate | Adequate/weak or weak | |---|---| | From a credit perspective, the utility operates in a regulatory climate that is transparent, predictable, and consistent. | The utility operates in an opaque regulatory climate that lacks transparency, predictability, and consistency. | | The utility can fully and timely recover all its fixed and variable operating costs, investments, and capital costs (depreciation and a reasonable return on the asset base). | The utility cannot recover its fixed and variable operating costs, investments, and capital costs (depreciation and a reasonable return on the asset base) fully and/or in a timely fashion. | | Any regulatory incentives are limited and mainly symmetrical. The tariff setting includes mechanisms allowing for an adjustment for the timely recovery of volatile or unexpected operating and capital costs. | The utility must make significant capital commitments with no solid legal basis for the full recovery of capital costs. | | The tariff setting may include a pass-through mechanism for major expenses--such as commodity costs--or a higher return on new assets, effectively shielding the utility from volume and input cost risks. | Ratemaking practices actively harm credit quality. | There is a record of earning a stable, compensatory rate of return in cash through various economic and political cycles and a projected ability to maintain that record. | There is a record of earning minimal or negative rates of return in cash through various economic and political cycles and a projected inability to improve that record sustainably. | | The utility operates under a regulatory system that is sufficiently insulated from political intervention to protect the utility's credit risk profile, even during stressful periods. There is support for cash flow during construction of large projects, and preapproval of capital investment programs and large projects lowers the risk of subsequent disallowances of capital costs. | The utility is regularly subject to overt political influence. | **Natural monopolies:** Where a utility has a natural monopoly and its tariffs are controlled, but it is not subject to a detailed regulatory framework or oversight by a regulatory body, we may still assess regulatory advantage, rather than competitive advantage. We would assess it using the same four subfactors, as follows: - For regulatory stability, we evaluate the stability of the setup, and give more emphasis to the historical record and our expectations regarding future changes. - For tariff-setting procedures and design, we examine the utility's ability to fully recover operating costs, its investment requirements, and its debt-service obligations. - For financial stability, we consider tariff flexibility, and whether this is sufficient to counter volume risk or commodity risk. In addition, we consider indirect competition, for example, while Nordic district heating companies operate under a natural monopoly, their tariff flexibility is partly restricted by customers' option to change to a different heating source if tariffs are increased significantly. - For regulatory independence and insulation, we evaluate the risk that political intervention could change the setup, and in turn, affect the utility's credit profile. Although political intervention tends to be mostly negative, state ownership might positively influence tariff determination. Because these four subfactors effectively capture the benefit of the close relationship with the state as owner, we do not typically modify our regulatory advantage assessment for natural monopolies based on business strategy. **Business strategy:** After determining the preliminary regulatory advantage assessment, we assess the utility's business strategy as positive, neutral, negative, or very negative, and may modify the preliminary regulatory advantage assessment as a result. This factor chiefly addresses the effectiveness of a utility's regulatory risk management in the jurisdictions where it operates. In certain jurisdictions, a utility can create a sustainable competitive advantage through its regulatory strategy and ability to manage the tariff-setting process effectively. Ensuring that revenue changes with costs is a key regulatory risk factor, especially if the risk of political intervention is high. Our assessment of the utility's business strategy is informed by historical performance and business objectives in the context of industry dynamics and the regulatory climate. We assess the utility's business strategy as positive and modify the preliminary regulatory advantage assessment upward if we consider the business strategy effectively bolsters the utility's regulatory advantage through favorable commission rulings, beyond what is typical for a utility in that jurisdiction. Where business strategy has limited effect relative to peers, our assessment is neutral. Where the business strategy leads to worse regulatory outcomes than peers, such as failing to achieve recovery of typical costs, we may see the implications as negative or very negative, and would apply the downward modifications as shown in the table below. Regulated utilities: determining the final regulatory advantage assessment (Business strategy modifier: Positive / Neutral / Negative / Very negative) | Preliminary regulatory advantage score | Positive | Neutral | Negative | Very negative | |---|---|---|---|---| | Strong | Strong | Strong | Strong/adequate | Adequate | | Strong/adequate | Strong | Strong/adequate | Adequate | Adequate/weak | | Adequate | Strong/adequate | Adequate | Adequate/weak | Weak | Adequate/weak | Adequate | Adequate/weak | Weak | Weak | | Weak | Adequate/weak | Weak | Weak | Weak | ### Scale, scope, and diversity We assess scale, scope, and diversity in the regulated utilities sector based on: - Operational scale; and - The geographic, economic, and regulatory diversity of a utility's markets and service territories. These characteristics can contribute to cash flow stability while dampening the effect of economic and market threats. We generally believe a larger service territory--with a diverse customer base and average to above-average economic growth prospects--provides a utility with cushion and flexibility in the recovery of operating costs and ongoing investments (including replacement and growth capital spending). It also lessens the effect of external shocks (such as extreme local weather) because the incremental effect on each customer declines as the scale increases. We consider that residential and small commercial customers have more stable usage patterns and are less exposed to periodic economic weakness, even after accounting for some weatherdriven usage variability. Significant industrial exposure--combined with a local economy that largely depends on one or few cyclical industries--could contribute to the cyclicality of a utility's load and financial performance, magnifying the effect of an economic downturn. A utility's cash flow generation and stability can benefit from operating in multiple geographic regions that exhibit average to better-than-average levels of wealth, and where employment and growth levels underpin the local economy and support long-term growth. Operating in a single geographic region carries a risk that can be ameliorated if the region is sufficiently large, demonstrates economic diversity, and has at least average demographic characteristics. In addition, if a utility operates in a single large geographic area and has a strong regulatory assessment, the benefit of diversity can be incremental. Scale, scope, and diversity: typical characteristics | Strong or strong/adequate | Adequate/weak or weak | |---|---| | Stability of its revenue and profits limits its vulnerability to most combinations of adverse factors, events, or trends. | Revenue and profits are unstable and unsustainable, so that the utility is vulnerable to economic, competitive, or technological threats. | | Customer base is large and diverse, with no meaningful customer concentration risk; that is, residential and small and midsize commercial customers typically provide most of the operating income. | Customer base is small and demonstrates customer or industry concentrations, combined with little economic diversity and average to below-average economic prospects. | | Exposed to a wider range of service territories than others in the sector. | Exposed to a single service territory. | | Operates in multiple regulatory jurisdictions where we assess the final regulatory advantage as adequate or stronger; or operates in a single regulatory jurisdiction where we assess final regulatory advantage as strong or strong/adequate. | Operates in a single regulatory jurisdiction where we assess the final regulatory advantage as adequate or adequate/weak. | | No meaningful concentrations by asset or supplier that could weigh on operations; or assets and suppliers can easily be replaced. | Dependence on a single supplier or asset that cannot easily be replaced and that could damage the utility's operations. | ### Operating efficiency We assess operating efficiency in the regulated utilities sector based on: - A utility's compliance with the terms of its operating license--including safety, reliability, and environmental standards; - Its cost management; and - The scale, scope, and management of its capital spending. We analyze management's record in these three key areas, relative to peers, and the resulting cash flow stability. In addition, we consider how management reduces the prospect of penalties for noncompliance; operating costs being greater than allowed; or capital projects running over budget and time--all of which could impair the company's ability to recover its full costs. The relative importance of the above three factors, particularly cost and capital spending management, is determined by the type of regulation under which the utility operates. Utilities operating under robust cost-plus regimes tend to be more insulated given the high degree of confidence that costs will invariably be passed through to customers. Utilities operating under incentive-based regimes are likely to be more sensitive to achieving regulatory standards. This is particularly so where regulatory regimes involve active consultation between regulator and utility, and market testing, as opposed to just handing down an outcome on a more-arbitrary basis. In some jurisdictions, absolute performance standards are less relevant than how the utility performs against the regulator's performance benchmarks. This performance will drive any penalties or incentive payments and can determine the utility's credibility on operating and asset management plans with its regulator. Therefore, we believe that well-managed utilities are more likely to maximize the likelihood of cost recovery and full inclusion of capital spending in their asset bases. When regulatory resets are more at the discretion of the utility, effective cost management--including of labor--may allow for more control over the timing and magnitude of rate filings. This would maximize the chances of a constructive outcome--such as full operational and capital cost recovery--while protecting against reputational risks. Operating efficiency: typical characteristics | Strong or strong/adequate | Adequate/weak or weak | |---|---| | Cost structure is better than that of peers and volatility is limited. Generates revenue and profits by minimizing costs, increasing efficiencies, and asset utilization. | Cost structure is worse than that of peers; its cost position and efficiency factors do not support profit sustainability; and volatility is above-average. | | Asset profile (including age and technology) is such that we have confidence that it could sustain favorable performance against targets. | The capital spending program is so large and complex that overall operating efficiency is compromised. | | Strong safety record. Poor safety performance Strong service reliability, with a record of meeting the operating performance requirements of stakeholders (including regulators). | Service reliability has been sporadic or nonexistent, with a track record of not meeting operating performance requirements of stakeholders (including regulators); we do not believe the utility can consistently meet performance targets without additional capital spending. | | Where applicable, well-placed to meet current and potential future environmental standards. | Where applicable, the utility is challenged to comply with current environmental standards and is highly vulnerable to more onerous standards. | | Management maintains very good control over both fixed and variable costs, in line with regulatory expectations (including labor and working capital management being in line with regulator's allowed collection cycles). | Management typically exceeds operating costs authorized by regulators. | | Strong record of projects managed almost invariably within regulatory allowances for timing and budget. | Inconsistent project management skills, as demonstrated by cost overruns and delays, including for maintenance capital spending. | ### Profitability A utility with above-average profitability would, relative to its peers, generally earn a rate of return at or above what regulators authorize and has minimal exposure to earnings volatility from affiliated unregulated business activities or market-sensitive regulated operations. Conversely, a utility with below-average profitability would generally earn rates of return well below the authorized return relative to its peers or have significant exposure to earnings volatility from affiliated unregulated business activities or market-sensitive regulated operations. We typically use the EBITDA margin as key indicator of profitability, unless it is distorted--for example, by pass-through costs like congestion revenue or collection of third-party revenue, or by accelerated asset depreciation that we do not view as sustainable in the long run. In such cases, we would use ROC or ROE to benchmark the company against peers. For regulated utilities subject to full cost-of-service regulation and return-on-investment requirements, we normally measure profitability using ROE, the ratio of net income available for common stockholders to average common equity. When setting rates, the regulator ultimately bases its decision on an authorized ROE. However, different factors--such as variances in costs and usage--may influence the return a utility is actually able to earn. Consequently, our analysis of profitability for cost-of-service-based utilities centers on the utility's ability to consistently earn the authorized ROE. **Volatility of profitability:** We may observe a clear difference between the volatility of actual reported profitability and the volatility of underlying regulatory profitability. In these cases, we could use the regulatory accounts as a proxy to judge earnings stability. ## Financial Risk Profile ### Accounting characteristics Important accounting practices for utilities include: - For integrated electric utilities that meet native load obligations partly by using third-party power contracts, we use our purchased power methodology to adjust measures for such contracts' debt-like obligations. - Where substantial seasonal working capital requirements--for example, at natural gas distribution utilities--distort leverage measures, we adjust inventory and debt balances by netting the value of inventory against outstanding short-term borrowings. This adjustment informs balance sheet analysis by reducing seasonal debt balances when we are very confident of near-term cost recovery. - We deconsolidate securitized debt (and associated revenue and expense) that has been accorded specialized recovery provisions. In the U.S. and certain other regions, utilities employ "regulatory accounting," which permits a rate-regulated company to defer some revenue and expense to match the timing of the recognition of those items in rates, as determined by regulators. A utility subject to regulatory accounting therefore records assets and liabilities that an unregulated corporation--or even regulated utilities in other global regions--cannot record. We do not adjust GAAP earnings or balance-sheet figures to remove the effects of regulatory accounting. While IFRS does not currently provide for any recognition of the effects of rate-setting for financial reporting purposes, our financial analysis focuses on the economics and actual cash flow generation. ### Volatility tables We apply the low volatility benchmark table to regulated utilities where: - They derive about two-thirds or more of their operating cash flows or profits from regulated operations that are predominantly at the low end of the utility risk spectrum (such as a network or distribution/transmission business unexposed to commodity risk and with very low operating risk); - Their regulated operations have a regulatory advantage assessment of strong; - They are expected to maintain their established record of achieving stable credit measures and low funding costs; and - No other activities contribute significantly to the group's overall risk profile and are viewed as high-risk or volatile. We apply the medial volatility table to regulated utilities that do not qualify for low volatility and that either: - Derive about 50% or more of their operating cash flows or profits from regulated activities that have a regulatory advantage assessment of at least adequate and operate in a jurisdiction where the country risk is '4' or better; or - Derive about one third or more of their consolidated operating cash flows or profits from regulated utility activities that have a regulatory advantage assessment of strong; or a regulatory advantage assessment of strong/adequate and a CICRA of '3' or better. In both cases, the competitive position for the remaining activities must be assessed as at least satisfactory. In all other cases, we use the standard volatility benchmark table # Oil And Gas Exploration And Production ## Business Risk Profile ### Competitive advantage Companies in the oil and gas exploration and production (E&P) sector depend on the availability of suitable reserves that can be profitably extracted. Competitive advantage for these upstream companies largely depends on their ability to manage the risks associated with replacing and increasing reserves. We assess competitive advantage for an integrated company in the E&P sector based on: - The growth prospects inherent in its acreage (the area on which it has an oil and gas license); - The quality of liquids and gas produced; - Unit revenue realized at each producing region; and - Extent of vertical integration, if any, among its operating segments. **Growth prospects inherent in its acreage:** We assess a company's ability to increase production and reserves through internal development (that is, finding and exploiting reserves in the fields where it already has a license), based on: - Its history of successful exploration and development; technical resources and capabilities; and required capital spending; - Its acreage position (geological conditions and accessibility of its fields); and - The length of its project queue, based on the reserve life index (RLI; defined as reserves divided by annual production). Where a company's reserves are not growing, it can indicate poor prospects for its ability to continue to meet its debt service requirements. On the other hand, the upfront investment associated with sustained high growth can put a strain on funding sources. **Production quality:** Hydrocarbons are subject to price differentials based on type and quality. Therefore, the quality of hydrocarbons produced by a company affects its revenue and cash flow. For example, light, sweet crudes require less refining treatment and yield more high-priced byproducts such as gasoline, kerosene, and jet fuel. Therefore, they command a higher price than heavy, sour crudes which cost more to refine. Similarly, wet gas, which contains natural gas liquids, commands a premium over dry gas because of its higher energy content. **Unit revenue at each producing region:** Revenue at E&P companies is also affected by basis differentials---the difference between the price in a particular region and the benchmark price. These usually arise because of transportation costs or supply and demand characteristics in the production area. If a company's acreage is in a region where the cost of transportation to market is high, or limited capacity makes hydrocarbons difficult to transport out of the region, it typically sells at a discount to the benchmark price. We view this as an adverse factor. On the other hand, if it is supplying hydrocarbons to a region where demand is high or transportation costs are low, the regional price may include a premium compared with the benchmark. The company will therefore benefit from higher unit revenue, cash flow, and earnings. **Extent of vertical integration:** Strategic approaches to integration vary considerably, but it is common for larger E&P companies to operate a cluster of ancillary related businesses. Related businesses that an E&P company may integrate with include: - Natural gas processing plants; - Oil and gas common long-haul or gathering pipelines; and - Oilfield services operations and assets, such as drilling rigs and pressure pumping equipment. Participation in pipeline operations that carry third-party volumes can sometimes offer an E&P company a highly stable source of earnings that is not closely correlated with its base earnings. When capacity among third-party suppliers is constrained, vertical integration (for example, ownership of oilfield services operations and assets) can benefit E&P companies by facilitating cost-effective growth in reserves and production. That said, it requires capital, adds to fixed costs, and can exacerbate a downturn's adverse effects. Although integration and diversification can enhance an E&P company's competitive position and increase the stability of its financial performance, the financial results are not always positive. #### Competitive advantage: typical characteristics | **Strong or strong/adequate** | **Adequate/weak or weak** | |-------------------------------------|-----------------------------------| | A strong record of project execution, with production and costs that compare favorably with operators that have adjacent acreage. | Project execution has historically been poor, so that costs are higher and production inferior to that of operators with adjacent acreage. | | A record of allocating capital to basins that have favorable internal rates of return (typically exceeding 30%). | Limited record of allocating capital to basins that have favorable internal rates of return. | | Diversification that demonstrably improves profitability or the stability of financial performance throughout the business cycle. | Operations have shown inferior profitability or more volatile financial performance throughout the business cycle. | | Where transportation and services, such as drilling rigs, are integrated, unit costs are lower than the available alternatives, sourced through a third party. | A lack of integration with transportation, or equipment and services. | | Some degree of leverage with customers and suppliers. | Little or no leverage with customers and suppliers. | ## Scale, scope, and diversity We assess scale, scope, and diversity in the E&P sector based on: - Size of the reserves, because larger reservoirs offer potential economies of scale; - Geographic diversity of production sources; - Diversity of hydrocarbons produced; - Operational risk required to exploit the reserves; and - Quality of the reserves. **Reserve size:** If the reserve base is larger than that of peers, we would expect the company to benefit from greater operating flexibility, more geographic diversity, and larger economies of scale. In our view, the size and type of a company's individual reservoirs is important. Large onshore or offshore reservoirs allow companies to spread overhead costs and capital investment across more production, and so provide greater economies of scale. Size can also give companies access to more favorable financing terms, which can significantly boost their ompetitive advantage when developing or uying properties. During industry downturns, large E&P companies may have greater financial lexibility than their smaller competitors. **Geographic diversity of production:** A geographically diversified portfolio can provide opportunities for cost-effective reserves and production growth, if regional factors affect production or reinvestment in a particular area. In addition, by operating in multiple, geographically diverse fields, a large E&P company can reduce its dependence on the operational performance of a small cluster of wells or fields, and make itself less susceptible to regional price volatility. We view production as less diversified if a company operates in several basins but generates most of its earnings from just a few of them. Nevertheless, we may assess a company as having strong/adequate scale, scope, and diversity, even if it operates in just one major basin as long as we expect it to generate above-average profitability, it has an extensive acreage position, and its production profile is clear for at least 10 years. **Diversity of hydrocarbons produced:** We would expect a company with a broader production profile to be less volatile. For example, we view the production of a mix of liquids (oil or natural gas liquids) and natural gas as credit positive, in markets where these show low price correlation. A company that has the flexibility to shift production across a range of hydrocarbons is also better positioned to respond to changes in market dynamics. **Operational risk:** Most of the easy-to-access oil and gas reserves have already been exploited---exploration now entails drilling in more-difficult conditions, often using novel extraction methods. E&P companies can develop meaningful scale, scope, and diversification in their operations by effectively adapting extraction technologies to exploit newly discovered reservoirs. However, the complexity of the task tends to give rise to greater operational risks. Deepwater drilling techniques, for example, are much skier than those used in onshore operations. Similarly, it is difficult to make geological assessments in remote locations---uncertain outcomes increase operational isk. Health and safety concerns can also give rise to operational risk. **Quality of reserves -- Proved developed producing reserves:** Business risk tends to be better for companies with a high proved developed producing (PDP) ratio (the ratio of PDP reserves to total proven reserves). This is because PDP reserves have lower future development costs and production risks than undeveloped reserves. This implies that they have less chance of incurring cost overruns or suffering shortfalls in production. However, the optimal portfolio includes reserves at different stages of development. A PDP ratio of more than 80% (implying a low stock of undeveloped reserves) indicates that, as producing reserves decline, they could be difficult to replace. Where we see little risk associated with developing reserves, we do not place much emphasis on the distinction between reserves that are proved developed, and those that are proved undeveloped (PUD). For example, recovery of oil sands where the reserves are close to the surface uses a low-risk technique akin to strip mining. There is little geological risk associated with converting reserves to proved from probable, in such cases. We could extend this analysis to other forms of unconventional oil and gas reserves. **Reserve life index (RLI):** We use reserves divided by annual production (RLI) to indicate how long a company would take to deplete its existing reserves, at current production rates. RLI is assessed in the context of the company's total reserve base, prospects for organic or acquisition reserve growth, capital position, and operating team. In assessing reserves, we also evaluate the underlying assumed depletion rate. A steep depletion curve could imply a risk of a significant decline in production beyond the next few years if reserves are not replaced. A short RLI of less than five years may indicate that the company has been unsuccessful at replacing its reserves or that it has limited capital for organic and acquisition-related growth. A long RLI of 10 years or more may indicate a company that has a low-risk reserve base and relatively stable production outlook. This is generally the case for companies that focus on oil sands or hale oil. In some cases, however, a long RLI implies that reserves are overstated or indicates a ompany that has proved itself unable to ramp up production. **Reserve replacement ratio:** As E&P companies produce hydrocarbons, they need to find or acquire new sources of future growth. This may be achieved by drilling (organic growth) or by acquisitions. We assess a company's reserve replacement strategy using the reserve replacement ratio (RRR, the amount added to reserves divided by the amount extracted for production) along with its unit finding, development, and acquisition (FD&A) costs. **Reserve disclosures:** The U.S. Securities and Exchange Commission, and equivalent authorities in other areas, define the standards used to categorize reported reserves. Although this provides a basis for comparison, management has some discretion about how to apply the standards---this may affect whether reserves are reported as proved developed, proved undeveloped, or probable. Proved developed reserves are the most direct source of current production and cash flow. Capex is required to convert reserves ategorized as proved undeveloped or probable or possible resources into proved developed reserves. We evaluate the reliability of reserve disclosures based on whether a company has a record of posting substantial or frequent negative technical revisions. Where a company's policy on reserve bookings has historically been aggressive, we may hold it to a higher standard than similarly rated peers. **Mergers, acquisitions, and divestitures:** E&P companies frequently buy assets to enter new areas or consolidate their interest in existing properties. At the same time, they may divest noncore or high-cost assets to streamline their portfolios or to raise funds. In considering the effect of acquisitions, we focus on how much the company paid for the assets; the opportunities the assets represent for yielding reserves and production; whether they will help the company generate economies of scale; and whether the company has the capacity to manage the new properties. #### Scale, scope, and diversity: typical characteristics | **Strong or strong/adequate** | **Adequate/weak or weak** | |---------------------------------------|---------------------------------| | Large in scale, typically defined as having reserves of more than 1 billion boe and production of over 350,000 boe per day. | Small in scale, typically defined as having total proved developed reserves of less than 50 million boe and production of less than 30.000 boe per day. | | An RLI of 10 years or greater. | An RLI of five years or less. | | An average RRR that exceeds 100%, over at least three years, and good prospects for production growth, given its drilling inventory and planned investment projects. | An RRR of less than 100% over the past three years, and limited prospects for production growth. | | A well-balanced reserve mix that includes both liquids (crude oil and natural gas liquids) and natural gas. | An unbalanced reserve mix. | | Exceptionally low production risk and high certainty of reserve replacement, even where the company operates in a relatively small number of fields (typical for certain Canadian oil sands projects). | Significant uncertainty with respect to sustainability of production and reserve replacement. | | Fields or projects are geographically diverse and located in countries that have a country risk score of '3' or lower. Most have well-established records of development activity. | Most cash flow comes from one basin, indicating high geographical concentration. | ## Operating efficiency We assess operating efficiency in the E&P sector based on: - Operating and production costs; and - Exploration and development costs (including capital efficiency and reserve replacement costs). **Operating and production costs:** Because E&P companies produce commodities, they have no control over selling prices, except through hedging. Controlling the cost of current production (that is, the operating and production costs) is therefore critical to an E&P company's credit profile and we view it as an important indicator of long-term operating strength. By managing their costs, companies may be able to expand and so generate additional cash flow. However, most E&P companies depend on third-party companies to provide critical services such as drilling, pressure pumping, and hydraulic fracturing (fracking), which reduces their control over the related costs. **Exploration and development costs:** E&P companies that cannot replace their reserves at an economical cost will eventually fail. Therefore, exploration and development costs---those associated with finding and developing new reserves---significantly affect financial performance. They usually comprise more than half of the total unit cost base. In some cases, particularly offshore production projects, capex reaches its peak well before production can begin. To ensure we take this into consideration, we compare cash operating costs against capital costs. We evaluate the capital efficiency of exploration by assessing finding and development (F&D) costs relative to peers, which we view as the best measure of organic growth capabilities. We also consider the unit finding, development, and acquisitions (FD&A, also known as all-sources finding and development) cost which indicates how much capital a company spends in all forms to replace a unit of hydrocarbon produced. **Recycle ratio:** A company's break-even point can be identified using the recycle ratio, which we calculate by comparing the unit netback (gross profit per barrel) with its unit F&D, or unit FD&A. A recycle ratio of less than 1x indicates that the company may not remain viable; we would typically assess operating efficiency as weak in this case. #### Operating efficiency: typical characteristics | **Strong or strong/adequate** | **Adequate/weak or weak** | |----------------------------------|--------------------------------------| | Unit cash operating and unit FD&A costs are consistently below those of peers that have a similar hydrocarbon mix. | Consistently higher unit cash costs (for instance, costs to extract oil and gas) and consistently higher FD&A costs than peers with a similar hydrocarbon mix. | | Revenue per unit of production is consistently higher, and expected to remain consistently higher, than unit unleveraged costs, based on our pricing assumptions, and unit cash margins are sufficient to cover unit FD&A costs. | Revenue per unit of production that are consistently lower than unit unleveraged costs (and that we expect to remain so) under our pricing assumptions, with unit cash margins that cannot fund unit FD&A costs internally (external financing is essential for the company's growth). | ## National oil companies In addition to the factors considered above, for national oil companies, we place special emphasis on national industry-specific factors that derive from being a national company, and that may positively or negatively affect the company's competitive position compared with peers. In particular, our analysis considers: - To what extent heavy taxes or domestic price regulations affect the company's profitability through the cycle; - To what extent regulations have a stabilizing effect on national oil companies' profits (that is, whether taxes act as a natural hedge); - Whether the company has any advantages due to barriers to entry created by the regulatory framework in the hydrocarbon industry; and - How stable the regulatory regime is and how resilient it is to potential changes in international oil prices. ### Profitability Because performance in the E&P industry is affected by natural hydrocarbon price volatility and possible changes in company operating efficiency metrics, we do not assess profitability based on standard global benchmarks over a whole cycle. Instead, we rank E&P companies against their peers annually, using the profitability measures listed below. - Adjusted unit EBIT; - ROC; and - Adjusted unit earnings before interest. We calculate adjusted unit earnings by applying our off-balance-sheet adjustments to unhedged earnings before interest and after taxes, for each unit of production. We may also include the unit EBIT as a proxy metric, depending on the availability of data and its relevance to the peer group used to benchmark a company. ## Financial Risk Profile ### Supplementary ratios In our view, the most likely source of financial stress for an E&P company is an inability to fund its minimum ongoing investment requirements, or its maintenance capex. Reserve replacement, and thus production stability, rely on substantial access to capital. Our preferred supplementary ratios in the sector are FOCF to debt and DCF to debt. In calculating FOCF, we assume that maintenance capex, at least, is required. We view DCF to debt as most relevant for companies that pay out a portion of excess cash flow to shareholders. We use our price assumptions for oil and natural gas when assessing the financial risk profile. To capture the higher volatility typical of speculative-grade companies, we generally focus on financial performance in the current and next year. We add an additional forecast year when assessing more stable companies. The diversified operations of the major integrated companies should enable them to demonstrate some stability through a price cycle, in our view. Therefore, in assessing these groups, we take into account historical ratios for the previous two years, as well as our estimate for the current and our forecast for the two subsequent years. # Unregulated Power And Gas ## Industry Risk ### Cyclicality We assess cyclicality for the unregulated power and gas industry as moderately high risk (4). The industry has evolved over different periods of time around the world but, globally, it is considered to be relatively young. As such, the data available to analyze the industry's performance during recessions is more limited, and we consider the little we have to be inconclusive. The unregulated sector has rapidly developed into an integral component of the global power and gas industry; therefore, we expect to gain more directly relevant peak-to-trough data over time. Until then, based on the industry dynamics demonstrated so far, we align the cyclicality assessment with our competitive risk and growth assessment and consider that the level of cyclicality for the unregulated power and gas industry warrants a moderately high risk assessment. ## Business Risk Profile ### Competitive advantage Unregulated power and gas companies, such as renewable generation companies, don't benefit from protective rate regulation. However, they may benefit from policy support and gain competitive strength from fixed-price or feed-in tariffs, or from long-term contractual arrangements with creditworthy off-takers. We assess competitive advantage in the unregulated power and gas sector based on: - Market structure and attractiveness; - Earnings structure and stability; and - Asset mix and quality or technological advantage. **Market structure and attractiveness:** The risk level of an unregulated power and gas company is heavily influenced by the markets in which it operates. We anticipate that operating stability would be affected by public policies in areas such as energy and the environment. The market structure in the relevant national, regional, or state jurisdiction may also have an effect, based on the degree of market liberalization; types of contract in use; mix and age of generation assets; weather impact; quality of interconnections with other markets or price zones; risk of curtailment; contracting and pricing structures; structural balance between supply and demand; and market liquidity, transparency, and growth rate. **Earnings structure and stability:** This can vary widely, depending on price volatility and the specific utility's contractual price protections. For entities that produce, buy, and resell power and gas, we analyze factors that may affect competitive pressure, such as barriers to entry; potential exposure to short positions; customer-base stability; ability to pass on cost increases to customers; and price structure and flexibility with end consumers. We also look at brand reputation; hedging and procurement risk; the range of products the company offers; customer satisfaction; customer churn rates; policy interference in market rates; and demographic trends. Credit-supportive features may include the ability to transfer pricing and, in some cases, volume risks. For electricity generators and supply companies, long-term and attractive pricing certainty may be achieved via long-term contracts for differences (CfDs) or feed-in tariffs, or through flexible long-term off-take agreements (sometimes referred to as power-purchase agreements) with creditworthy counterparties. Separately, entities may mitigate pricing volatility through hedging, depending on the liquidity and depth of the energy derivatives market. In certain markets, part of the generation capacity may have firm energy obligations (also known as "must-dispatch status") for which companies are remunerated via capacity mechanisms that can enhance long-term cash flow predictability. Separately, renewables subsidy schemes may enhance predictability but can sometimes be subject to retroactive government interference. Where companies are exposed to merchant risks or rely on spot markets to sell a high proportion of their volumes, we anticipate that earnings may be more volatile. A history of temporary short positions that force a company to source volumes in the spot market to meet its sale commitments would weigh on our assessment. This can occur where a company has committed to sell a certain volume at a fixed price and supplies are disrupted by unforeseen low-probability, high-impact operational, climate-related, or market events. **Asset mix and quality or technological advantage:** Technological advantage---in particular, the quality and attractiveness of a company's generation portfolio---is key to ensuring long-term profitability in the sector, particularly for merchant power. We assess it based on: - Generation type, fuel mix (thermal, hydro, renewables, or nuclear) and carbon intensity; - Position in the merit order, which ranks all generating assets serving a market by marginal cost position, and dispatching profile (base, mid-merit, or peak load); - Age profile and reinvestment needs (related to retrofits or replacement); and - Location with respect to end customers and proximity to raw material inputs (such as integrated coal mines, a gas hub, or a major transmission line). #### Competitive advantage: typical characteristics | **Strong or strong/adequate** | **Adequate/weak or weak** | |:-----------------------------------|:-----------------------------------| | Participates in a market or region that has well-established and predictable market rules, including transparent and reasonably predictable environmental rule-making processes. | Participates in a market or region that has poorly defined and unpredictable or transitory market rules; or a market that is undergoing significant structural changes and is subject to high uncertainty. | | High barriers to entry, low market volatility, low competitive pressures, manageable structural changes (including from environmental net zero regulations or carbon taxes), and balanced supply-and-demand characteristics. | Low barriers to entry, high market volatility or uncertainty, weak medium- and long-term growth prospects, or supply-and-demand characteristics that are often unbalanced. | | Has gained a technological advantage through its attractive and diverse mix of generation assets that have low variable costs, such as renewables. | Poor asset mix and quality. | | Asset base is well-invested in diverse and favorable locations and has sufficient dispatchable capacities to limit supply shortages and exposure to extreme price spikes (this may include nuclear, hydropower, and---in some markets---gas-fired generation). | Asset base is in unfavorable locations (for example, it is exposed to curtailment) or has significant and unmitigated exposure to energy transition risks (for example, assets that have high greenhouse-gas emissions and may dispatch only under certain conditions). | | Price risk has been sharply reduced or eliminated through regulatory or contractual protections or long-term off-take agreements with creditworthy counterparties, especially if the counterparties show diversity and the agreements last longer than eight years (or, for shorter agreements, renewal on similar terms is highly likely). | The earnings profile generally shows significant volatility over the short or medium term because most volumes are exposed to merchant risks, sold in spot markets, or sold at unfavorable prices, with only a modest level of hedging. | | Strong retail market shares, or market position that benefits from generation dispatch and a generally stable retail market share that helps to limit load mismatch and lessen any reliance on selling into or procuring from a competitive market. | Shares in retail markets are relatively small and may be unstable; business model focuses on retail markets with only modest integration of operations and are typically subject to high competitive pressures or regulatory or country risks that impede the ability to pass along costs to end customers; or the company is a pure price taker. | ## Scale, scope, and diversity We assess scale, scope, and diversity in the unregulated power and gas sector based on: - The relative size of operations, earnings, and cash flow; - The company's diversity in terms of the markets in which it operates; - Customer and supplier concentrations; - The breadth of the asset mix (including fuel type and plant diversity); and - The degree of vertical integration---both forward (retail) and backward (generation or fuel). **Size of operations:** We measure the scale of operations by power generation or distribution capacity, and by earnings and cash flow. Large-scale operations support stronger competitive positions, with more operating flexibility and economies of scale than small companies. For companies that supply the retail market, the position and size of the markets in which they participate can affect the degree to which they benefit from economies of scale. **Market diversity:** We review the company's diversity across the markets it serves by looking at how its cash flow generation and stability benefit from operating in multiple geographic regions. We view companies more positively if they operate in regions that exhibit average to better-than-average levels of wealth, and where employment and growth levels underpin the local economy and support long-term growth and prices. The risk of operating in a single region may be mitigated if the region is sufficiently large, demonstrates economic diversity, and has at least average demographic characteristics. Increasingly, weak correlation of seasonal weather and extreme events across regions served may mitigate environmental risks. **Customer and supplier concentrations:** These may expose any company in the unregulated power and gas market to higher risk of operational disruptions and cash flow volatility, especially in the case of retailers, as counterparty risk might be heightened by dependance on a few key customers. Customer diversity depends on the mix of residential, commercial, and industrial clients. Supplier diversity is driven by the company's needs; for example, having multiple natural gas pipeline alternatives indicates a diverse supplier base for a gas-fired power plant. **Asset mix:** The broader the asset mix---whether by fuel type, dispatchability, geography, or markets---the greater the protection against risk factors that may affect one region and its market dynamics more than another, such as fluctuations in supply and demand, or price. **Degree of integration:** Similarly, a greater degree of vertical integration provides a greater ability to withstand unexpected operational or market disruptions to any one aspect of the business. #### Scale, scope, and diversity: typical characteristics | **Strong or strong/adequate** | **Adequate/weak or weak** | |:------------------------------------------|:----------------------------| | Large scale relative to competitors, and a strong market position in its key markets. | Small in scale, with little pricing power, in a market that has low growth prospects. | | Participates in a variety of attractive geographic or organized markets. | Concentration in one market that exhibits high volatility or risk. | | Diversity and flexibility in terms of fuel mix and plants compares favorably with that of peers, based on factors such as number of plants and base/mid-merit/peak load. For example, in renewable generation, a company may see demonstrable benefits from its multiple assets and its resource risk may be strongly mitigated by uncorrelated geographic locations or use of different technologies, such as wind versus solar. | Company is exposed to operating availability risks at key plants because its diversity and flexibility in terms of fuel mix and number of plants is limited. | | No meaningful supplier or customer concentrations, or counterparty or procurement risk. | Meaningful supplier or customer concentration or procurement risk that could lead to uncertain operational availability or increased cost risk. | | Significant levels of forward and backward integration that reduces the volatility of operating earnings. | Full merchant or retail risk, with little meaningful integration or hedging that could mitigate price and volume volatility. | ## Operating efficiency We assess operating efficiency in the unregulated power and gas sector based on: - Cost competitiveness; - Asset efficiency; - Flexibility of the cost structure in absorbing demand declines (operating leverage) or input cost pressures; and - Cost and operational risk management. **Cost competitiveness:** Our assessment focuses on economies of scale; access to important commodity inputs (including via direct ownership, through attractively priced contracts, or based on location); and the fixed-cost profile. **Asset efficiency:** Our assessment focuses on the nature and age of the technology deployed; its relative productive efficiency, availability, and capacity factors; and placement in the dispatch merit order, as appropriate. **Cost structure flexibility:** Our assessment focuses on overall sensitivity to raw material cost fluctuations and commodity prices; the relative proportion of fixed costs to variable costs that---when elevated---could dampen cash flow if utilization rates decline; and cash flow dependence on actual asset utilization. **Cost and operational risk management:** This is particularly relevant when we assess retail supply companies, where profit margins are narrow and highly dependent on adequate risk controls on hedging, contracting, and treasury management. For retail supply companies, we consider the relative cost of serving their customer base and their ability to manage collections, and, in particular, how this affects working capital management. We also evaluate suppliers' proficiency at managing billing system upgrades or the introduction of new systems---a poorly implemented process has an adverse effect on cost and customer base management. #### Operating efficiency: typical characteristics | **Strong or strong/adequate** | **Adequate/weak or weak** | |:--------------------------------------|:--------------------------------| | **All** | | | Sustainable, leading cost position due to economies of scale, fuel flexibility or integration, and production efficiencies that support plant positioning at the low end of the merit order; high and stable capacity (load) factors through the cycle; and high availability and capacity factors and state-of-the-art technology. | Cost position is relatively weak due to high fuel cost or concentration risk, with key plants at the average-to-weak end of the merit order curve; or weak availability and capacity factors, perhaps influenced by aging technology. | | Cost structure has relatively low fixed costs and the sensitivity of profit margins to fluctuations in the cost of raw materials or commodity prices, or supply-chain risks is limited, or effectively mitigated. | Profit margins show higher-than-average sensitivity to fluctuations in the cost of raw materials or commodity prices, or supply-chain risks. | | Strong risk management policies and limited risk taking that can result from large contractual or commodity hedging positions, including an ability to limit volatility during periods of extreme price spike scenarios. | Risk management policies allow higher-than-average risk position due to extensive contractual commitments (operational or commodity hedging), including exposure to the risk of a sizable effect on profit during extreme price spikes. | | Efficient working capital management, supported by a record of shorter-than-average cash conversion cycles. | Inefficient working capital management, supported by a track record of longer-than-average cash-conversion cycles. | | **Retail suppliers** | | | A sustainable and leading cost-to-serve position, supported by a record of stable, above-market-average operating margins. | A higher average cost-to-serve position, demonstrated by a record of below-average operating margins and stability. | | Stronger-than-peers working capital management (based on number of unbilled customers), often underpinned by use of a single platform and proven technology. | Cash collection could be adversely affected by the higher number of unbilled customers, compared with peers. | ## Profitability The two main benchmark measures we use in determining profitability are the EBITDA margin and ROC. We select the most appropriate benchmark for a particular company based on factors including the market location, position on the value chain, capital cycle, and even type of asset. For example: - A hydro, wind, solar, or nuclear generator is likely to have reasonably high margins and low ROC, reflecting its low variable cost profile and high capital intensity. In this case, we generally view ROC as a better metric. - An entity that mainly focuses on thermal generation may have stronger ROC and weaker EBITDA margins, reflecting its significant fuel costs, compared with fixed costs. In this case, the EBITDA margin is the more appropriate metric. - A retail supplier is likely to have low margins, but a high ROC, because its business requires a limited capital commitment (excluding any liquidity buffer required to meet its hedging needs). Here, we rely primarily on EBITDA margins. For integrated players, the appropriate measure depends on the degree of vertical and horizontal integration. If the company is undertaking a large capex program that has a long lead time, we generally focus on the EBITDA margin. When assessing the profitability of companies engaged in trading activity or more-frequent, event-driven activity---for example, where asset acquisitions or divestitures, which can distort margins, are part of the business strategy---we generally use the ROC. An unregulated power and gas entity that we assess as having above-average profitability would be able to sustain a higher profitability than its peers in a similar market because of the composition of its customer and asset portfolio, including the competitive position (merit order) within its markets. We would also expect the entity to have a history of managing its costs well. For traditional incumbents in mature markets, where demand growth is declining or even flat, the flexibility of their asset portfolios can be important in determining the stability of profitability. For merchant power and integrated companies, fuel is a key input cost, while for those that have retail exposure, energy costs and operating costs are important. An entity with long-term contractual arrangements that give earnings more stability might earn a lower return than a more commodity-exposed issuer, but still be assessed as having above-average profitability. Conversely, a company we assess as having below-average profitability would generally have higher input costs, less-predictable asset performance, higher related maintenance expenses, or uneven experience in managing capital projects. ## Financial Risk Profile ### Accounting For unregulated power and gas companies that enter into long-term power purchase agreements (PPAs), we make adjustments to account for those obligations, as we do for regulated utilities under our ratios and adjustments criteria. ### Volatility tables We use the medial volatility table only when assessing companies that derive a significant proportion of their operating cash flow or profits from lower-risk industries (typically regulated utility activities or those having particularly strongly protected unregulated revenue). "Strongly protected unregulated revenue" refers to revenue that benefits from long-term contractual arrangements that ensure high cash flow predictability with limited volume, price, and counterparty risk. In addition, use of the medial volatility table is restricted to companies that operate in jurisdictions with a supportive legal and regulatory environment, limited exposure to energy transition risks, and little likelihood of political interference or contractual renegotiation. Assuming that they meet the previous conditions, eligible arrangements may include capacity mechanisms; CfDs; feed-in tariffs; PPAs; and take-and/or-pay contracts that have minimal commodity price, inflation, and volume exposure. Typically, a baseload PPA would not qualify. We apply the medial volatility table to companies with unregulated activities with country risk of '4' or better that meet either of the following characteristics: - About 50% or more of forecast operating cash flows or profits come from regulated activities that have a regulatory advantage assessment of adequate or better and/or about two-thirds when adding strongly protected unregulated revenue; or - About one-third or more of consolidated operating cash flows or profits comes from regulated activities that have a regulatory advantage assessment of strong/adequate or better and a CICRA of '3' or better. In addition, in either case, the competitive position for the remaining activities must be assessed as at least satisfactory. In all other cases, we apply the standard volatility table to unregulated power and gas companies. # **Transportation Infrastructure** ## Business Risk Profile ### Competitive advantage We assess competitive advantage in the transportation infrastructure sector based on: - The transparency and predictability of the regulatory framework, or the concession or contract, under which the company operates; and the potential for changes to regulatory policy and/or to government intervention (negative or supportive); and - The demand risk, which depends on the size and attractiveness of the catchment area, including location, population served, wealth and economic strength and growth potential, and contribution to the regional development. **Regulatory or contractual framework:** We consider how tariffs are set; how regulated revenue is determined and shared; and the regulator's record on oversight, protection of stakeholders, and enforcement of legal or contractual constraints. Mandatory investments, with no legal or contractual means of recovering these capital costs, may place some transportation infrastructure companies at a competitive disadvantage. **Demand risk:** We consider the company's specific role and relative value added to users and economies relative to other modes of transportation, as well as the stability and type of traffic. Key competitive drivers are market share dynamics and the nature of competition, including the number of competitors and the presence of alternative modes of transportation. #### Airports **Regulation, oversight, and tariff-setting mechanism:** Regulated airports may benefit from transparency and visibility on the determination of tariffs, while commercial airports may be more exposed to competition but enjoy greater tariff-setting ability. For regulated airports, we assess the independence and predictability of the regulatory framework underpinning the operation of the airport. We focus, in particular, on the ability to adjust tariffs and recover costs in a timely manner, as well as earn a reasonable return supporting access to markets. Pricing frameworks include "single till," "dual till," and "hybrid till" models: - The single-till method caps the maximum return on total airport assets, including commercial revenue sources (such as retail, parking, or property revenue). This provides more certainty to returns and earnings, and is generally considered as more credit protective by reducing volatility, lowering downside but also limiting upside. - Under the dual-till method, the returns on aeronautical assets are regulated or subject to oversight, while the commercial revenue sources (such as retail, car parking, or property) are unregulated. This method permits substantial upside from growing airport revenue, and gives the airport management a greater role but, equally, could represent more downside risk during economic downturns or unsuccessful commercial strategies. Finally, we factor in any obligations or constraints under license and permits, future development rights, operating conditions such as curfew hours, noise or environmental restrictions, and related penalties. **Demand risk:** We consider: - The size and attractiveness of the airport's catchment area and markets, including wealth and economic strength and growth potential. - The stability and type of passenger traffic (Transit vs O&D, domestic vs international). - The competition from other airports or alternative modes of transport (e.g., high-speed rail for short-haul). #### Roads **Regulatory framework:** For roads, we assess how closely their regulatory or contractual framework is aligned with the government's infrastructure policies and long-term plans. A strong framework that includes clear pricing or tariff-setting mechanisms will attract long-term capital and offer operators the ability to recover costs. **Demand risk:** We consider location, wealth, and size of the populations served, connectivity with the regional economy, and the stability of traffic volumes (commercial traffic reacts more than light traffic to macroeconomic downturns). #### Car parks We analyze car parks that operate under long-term concessions as infrastructure companies. We consider the size and diversification of the portfolio, location of key assets, and proximity to final destinations. #### Ports **Regulatory framework:** For ports operating under concessions, we consider the legal strength of contractual provisions implemented to prevent overcharging and the transparency of mandatory capex requirements. **Demand risk:** We consider location, connectivity, trade routes, and the past record of volume patterns. Ports benefit if they have guaranteed revenue or harbor dues subject to long-lasting agreements. #### Mass transit and railway **Regulatory framework:** Competitive advantage is assessed by considering government policy, scope of services, asset profiles, and the provider's ability to access ancillary revenue. Typically, rail services are provided under a bilateral agreement (Public Service Operations - PSO). **Government policy:** Close alignment with national infrastructure planning is beneficial. The cost to users can be politically sensitive, making regulatory intervention likely. **Demand risk:** Competition from alternative providers affects traffic stability. Commuter traffic is generally more stable than tourist-dependent traffic. ### Competitive advantage: typical characteristics | **Strong or strong/adequate** | **Adequate/weak or weak** | |---------------------------------------|---------------------------------| | **All** | | | The company provides an essential service to a national or regional economy. The area is large and wealthy and includes a capital city, economic hub, or strategic routes. | The company serves a relatively small or weak economy and/or demand patterns can be considered as volatile or uncertain. | | Limited competition. | Competition from operators or other transportation modes is meaningful, creating volatile demand and price pressure. | | The company offers a strong value for money, benefitting from a strong asset rationale and a stable and resilient demand. | The value added by the company could be perceived as limited by end users, resulting in demand uncertainty. | | Transparent, predictable, and consistent regulatory/contractual framework that enables adequate and timely cost recovery. | Unfavorable or unpredictable framework; no compensating mechanism has historically been provided. | | No history of adverse government or regulatory intervention on infrastructure assets. | Recent history of adverse government or regulatory intervention; additional costs/investments were not compensated. | | **Airports** | | | Dominant within catchment area; competition from adjacent airports/transport modes is limited. | Exposed to above-average competition; serves an end point for a catchment area suffering from structural economic decline. | | Variety of traffic flows, including a significant share of O&D traffic. Transit share is mitigated by track-record as an international hub. | High share of transit passengers, or serves a niche market (e.g., tourism) more sensitive to economic/geopolitical drivers. | | **Roads and car parks** | | | Asset serves a developed, stable local economy with high income per capita and stable correlation to GDP. | Specialized asset with narrow end user universe; undiversified local economy; observed divergence between GDP and traffic. | | Clear pricing/tariff-setting mechanisms, with track record of ability to adjust tariff as per concession/contract. | Record of riots or protest against tariff increases, not economically compensated on a timely basis. | | **Ports** | | | Serves a broad catchment area where trade routes are active and attractive. Dominant market share. | Serves a narrow catchment area on secular decline; reliance on a single industry with uncertain prospects. | | High negotiating power with customers for market-determined charges. | Track record of poor negotiating power with its customers. | | **Mass transit/railway** | | | Dominant within its market(s), large network, limited competition contributes to stability in volumes. | High sensitivity to volume fluctuations; volumes expected to show structural decline with no offsetting mechanism. | | Catchment area is wealthy; some flexibility to raise tariffs. | Tariffs cannot be raised without causing user affordability to drop. | ## Scale, scope, and diversity We assess scale, scope, and diversity based on: - The various revenue streams and their key drivers; - Geographic footprint (size, diversity, and maturity of assets); - Remaining asset or concession life. ### Scale, scope, and diversity: typical characteristics | **Strong or strong/adequate** | **Adequate/weak or weak** | |---------------------------------------|---------------------------------| | **All** | | | Remaining asset or concession life is comfortable, typically 10 years or more. | Remaining life is limited (less than five years) and renewal is unclear. | | **Airports** | | | High proportion of O&D passengers (visiting friends/family is most resilient). | High share of transit passengers, affected by competition from other hubs. | | Commercial revenue benefits from long-lasting contractual protections (long-term leases). Diverse revenue streams. | Revenue fluctuations caused by demand risk or exposure to short term leases/contracts. | | **Ports** | | | Handles large shipping volumes; diversity in cargo, shipping lines, and offtakers. | Significant swings in tonnage due to high reliance on a few commodities or industries. | | **Mass transit/railway** | | | Integrated operators with diversified revenue (infrastructure management + rail services + retail/real estate). | Less integrated operator with limited variety of additional rail services. | ## Operating efficiency We assess operating efficiency based on: - Ability to manage cost base to maintain profitability and free cash flow through the cycle; - Cost of maintenance and investment needs; - Working capital management and revenue collection; - Risk management and safety track record. ### Operating efficiency: typical characteristics | **Strong or strong/adequate** | **Adequate/weak or weak** | |-----------------------------------|-------------------------------------| | **All** | | | Ability to maintain profitability through most of the cycle by managing cost base or quickly adjusting tariffs. | Inability to manage cost base or adjust tariffs within the next two years. | | Stable cashflow generation; flexibility to reduce maintenance cost during downturn period. | Poor working capital management; exposure to late payments and customer defaults. | | **Toll roads and car parks** | | | Use of effective tolling technology and history; high control of toll leakage. | Typically uses manual tolling or unreliable system; historically high toll leakage. | | **Ports** | | | High capacity utilization and operating KPIs. Salaries/labor do not weigh on profitability. | Capacity constraints due to regulation/infrastructure. High influence of labor unions on standards. | ## Financial Risk Profile ### Volatility tables - **Low volatility table:** Applies if the company derives more than two-thirds of cash flow from predictable transportation activities AND has a CICRA of '1' or '2' (with strong/adequate competitive advantage) OR a CICRA of '3' (with strong competitive advantage and low political risk). - **Medial volatility table:** Applies if the company derives at least half of operating cash flow from predictable activities and has a CICRA of '3' or better. ### Core and Supplementary ratios - **Core ratio:** FFO to debt is the preferred measure. - **Supplementary ratio:** Our preferred supplementary ratio is **FFO cash interest coverage**. ### Modifiers (Financial policy) When operating under a **concession**, the company is required to repay its debt before the assets return to the grantor. If a company lacks a credible plan to decrease leverage well before the end of the concession, it would likely be assessed as having **negative leverage tolerance**. -------------------- In addition, here is some market data for the years leading up to 2022: # SWAP CURVE 5Y | Year | Average | Bear | Bull | |------|---------|------|------| | 2020 | -0.346 | -0.046 | -0.646 | | 2021 | -0.264 | 0.036 | -0.564 | | 2022 | 1.726 | 2.026 | 1.426 | # SWAP CURVE 7Y | Year | Average | Bear | Bull | |------|---------|------|------| | 2020 | -0.272 | 0.028 | -0.572 | | 2021 | -0.137 | 0.163 | -0.437 | | 2022 | 1.806 | 2.106 | 1.506 | # SWAP CURVE 10Y | Year | Average | Bear | Bull | |------|---------|------|------| | 2020 | -0.143 | 0.157 | -0.443 | | 2021 | 0.053 | 0.353 | -0.247 | | 2022 | 1.927 | 2.227 | 1.627 | # ISHARES CORE EURO CORP BOND | Year | Average | Bear | Bull | |------|---------|------|------| | 2020 | 1.171 | 1.3709 | 0.9709 | | 2021 | 0.733 | 0.9328 | 0.5328 | | 2022 | 1.085 | 1.2846 | 0.8846 | # SUB-SEN DELTA FOR IBOXX EUR NON-FINANCIAL IG Delta: 0.2 | Year | Average | Bear | Bull | |------|---------|------|------| | 2020 | 1.771 | 1.9708 | 1.5708 | | 2021 | 1.298 | 1.4981 | 1.0981 | | 2022 | 2.295 | 2.4953 | 2.0953 | -------------------- Based on this, assess whether this company is suitable to issue hybrid bonds. Options are: Strongly Suitable, Marginally Suitable, Not Suitable. Below are elements intended to provide guidance. They should be treated as a non-exhaustive checklist rather than rigid thresholds. - Strongly Suitable: - Regulated, quasi-regulated, infrastructure-like, utility, energy infrastructure, telecom incumbent, or business with highly visible cash flows - Investment grade profile in the BBB area - Hybrid issuance could materially improve adjusted leverage, FFO/debt, or rating headroom - Strong refinancing, capex, or M&A funding rationale - High credibility of financial policy and ability to access institutional capital markets - Deteriorating financial metrics per S&P and hybrid needed to preserve current rating - Existing hybrid bond approaching its first call date (within 18 months) requiring refinancing. - Marginally Suitable: - Industrial, partially regulated energy, telecom challenger, real estate, or infrastructure-adjacent issuer with moderate cash flow visibility - Hybrid issuance would be opportunistic, mainly for M&A, refinancing, avoiding equity issuance, or temporary credit support - Moderate rating benefit but not a core recurring funding instrument - Market access likely but pricing may be sensitive to sector, leverage, and volatility - Stable financial metrics per S&P but hybrid could increase current rating headroom - Not Suitable: - Highly cyclical, distressed, commodity pure-play, shipping, airline, LBO, early-stage growth, or structurally weak cash flow profile - Limited refinancing needs or no clear use of proceeds - Strong Investment Grade like profile, A or better - Stable or improving financial metrics per S&P - Non-investment-grade profile that would remain sub-investment-grade even after hybrid issuance - Hybrid would likely be perceived as expensive subordinated debt rather than equity-like capital - Limited or no expected rating, WACC, or leverage benefit - High risk of coupon deferral, reputational damage, or weak investor appetite Explain your reasoning, taking into account the guidelines above. Then, at the end, give your final answer, on a single line, between XML tags with no markdown fences. This final line must be exactly one of: Strongly Suitable Marginally Suitable Not Suitable