Cover Page
Cover Page - USD ($) | 12 Months Ended | ||
Dec. 31, 2023 | Jan. 31, 2024 | Jun. 30, 2023 | |
Document Information [Line Items] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2023 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Transition Report | false | ||
Entity File Number | 001-41137 | ||
Entity Registrant Name | CONSTELLATION ENERGY CORPORATION | ||
Entity Tax Identification Number | 87-1210716 | ||
Entity Incorporation, State or Country Code | PA | ||
Entity Address, Address Line One | 1310 Point Street | ||
Entity Address, City or Town | Baltimore | ||
Entity Address, State or Province | MD | ||
Entity Address, Postal Zip Code | 21231-3380 | ||
City Area Code | (833) | ||
Local Phone Number | 883-0162 | ||
Title of 12(b) Security | Common Stock, without par value | ||
Trading Symbol | CEG | ||
Security Exchange Name | NASDAQ | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
ICFR Auditor Attestation Flag | true | ||
Document Financial Statement Error Correction [Flag] | false | ||
Entity Shell Company | false | ||
Entity Public Float | $ 29,396,464,132 | ||
Entity Common Stock Shares Outstanding | 316,666,538 | ||
Documents Incorporated by Reference [Text Block] | Documents Incorporated by Reference Portions of the Registrants’ Definitive Proxy Statement relating to the 2024 Annual Meeting of Shareholders are incorporated by reference into Part III of this report. The Registrants expect to file the Definitive Proxy Statement with the Securities and Exchange Commission within 120 days after December 31, 2023. | ||
Document Fiscal Year Focus | 2023 | ||
Document Fiscal Period Focus | FY | ||
Entity Central Index Key | 0001868275 | ||
Amendment Flag | false | ||
Constellation Energy Generation, LLC | |||
Document Information [Line Items] | |||
Entity File Number | 333-85496 | ||
Entity Registrant Name | CONSTELLATION ENERGY GENERATION, LLC | ||
Entity Tax Identification Number | 23-3064219 | ||
Entity Incorporation, State or Country Code | PA | ||
Entity Address, Address Line One | 200 Exelon Way | ||
Entity Address, City or Town | Kennett Square | ||
Entity Address, State or Province | PA | ||
Entity Address, Postal Zip Code | 19348-2473 | ||
City Area Code | (833) | ||
Local Phone Number | 883-0162 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Central Index Key | 0001168165 |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2023 | |
Audit Information [Abstract] | |
Auditor Name | PricewaterhouseCoopers LLP |
Auditor Location | Baltimore, Maryland |
Auditor Firm ID | 238 |
Consolidated Statements of Oper
Consolidated Statements of Operations and Comprehensive Income, Parent - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Operating revenues | |||
Total operating revenues | $ 24,918 | $ 24,440 | $ 19,649 |
Operating expenses | |||
Purchased power and fuel | 16,001 | 17,457 | 12,157 |
Purchased power and fuel from affiliates | 0 | 5 | 6 |
Operating and maintenance | 5,685 | 4,797 | 3,934 |
Operating and maintenance from affiliates | 0 | 44 | 621 |
Depreciation and amortization | 1,096 | 1,091 | 3,003 |
Taxes other than income taxes | 553 | 552 | 475 |
Total operating expenses | 23,335 | 23,946 | 20,196 |
Gain (loss) on sales of assets and businesses | 27 | 1 | 201 |
Gain (loss) on sales of assets and businesses | 1,610 | 495 | (346) |
Other income and (deductions) | |||
Interest expense, net | (431) | (250) | (282) |
Interest expense to affiliates | 0 | (1) | (15) |
Other, net | 1,268 | (786) | 795 |
Total other income and (deductions) | 837 | (1,037) | 498 |
Income (loss) before income taxes | 2,447 | (542) | 152 |
Income tax (benefit) expense | 859 | (388) | 225 |
Equity in income (losses) of unconsolidated affiliates | (11) | (13) | (10) |
Net income (loss) | 1,577 | (167) | (83) |
Net income (loss) attributable to noncontrolling interests | (46) | (7) | 122 |
Net income (loss) attributable to membership interest | 1,623 | (160) | (205) |
Other comprehensive income (loss), net of income taxes | |||
Net income (loss) | 1,577 | (167) | (83) |
Pension and non-pension postretirement benefit plans: | |||
Prior service benefit reclassified to periodic benefit cost | (4) | (6) | 0 |
Actuarial loss reclassified to periodic cost | 25 | 101 | 0 |
Pension and non-pension postretirement benefit plans valuation adjustment | (453) | 186 | 0 |
Unrealized gain (loss) on cash flow hedges | (1) | (1) | (1) |
Unrealized gain (loss) on foreign currency translation | 2 | (3) | 0 |
Comprehensive income (loss) | (431) | 277 | (1) |
Comprehensive income (loss) | 1,146 | 110 | (84) |
Comprehensive income (loss) attributable to noncontrolling interests | (46) | (7) | 122 |
Comprehensive income (loss) attributable to membership interest | $ 1,192 | $ 117 | $ (206) |
Average shares of common stock outstanding: | |||
Basic (in shares) | 323 | 328 | 0 |
Assumed exercise and/or distributions of stock-based awards (in shares) | 1 | 1 | 0 |
Diluted (in shares) | 324 | 329 | 0 |
Earnings per average common share | |||
Basic (in dollars per share) | $ 5.02 | $ (0.49) | $ 0 |
Diluted (in dollars per share) | $ 5.01 | $ (0.49) | $ 0 |
Nonrelated Party | |||
Operating revenues | |||
Operating revenues | $ 24,918 | $ 24,280 | $ 18,461 |
Affiliated Entities | |||
Operating revenues | |||
Operating revenues | $ 0 | $ 160 | $ 1,188 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows, Parent - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Cash flows from operating activities | |||
Net income (loss) | $ 1,577 | $ (167) | $ (83) |
Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities | |||
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization | 2,514 | 2,427 | 4,540 |
Deferred income taxes and amortization of ITC | 251 | (643) | (205) |
Net fair value changes related to derivatives | 996 | 986 | (568) |
Net realized and unrealized (gains) losses on NDT funds | (476) | 794 | (586) |
Net realized and unrealized (gains) losses on equity investments | (307) | 13 | 160 |
Other non-cash operating activities | 18 | 248 | (261) |
Changes in assets and liabilities: | |||
Accounts receivable | 396 | (868) | (616) |
Receivables from and payables to affiliates, net | 0 | 20 | 14 |
Inventories | 60 | (228) | (68) |
Accounts payable and accrued expenses | (1,330) | 1,142 | 346 |
Option premiums received (paid), net | 26 | (177) | (338) |
Collateral received (posted), net | (1,491) | (351) | (130) |
Income taxes | 325 | 162 | 256 |
Pension and non-pension postretirement benefit contributions | (54) | (237) | (259) |
Other assets and liabilities | (7,806) | (5,474) | (3,540) |
Net cash flows provided by (used in) operating activities | (5,301) | (2,353) | (1,338) |
Cash flows from investing activities | |||
Capital expenditures | (2,422) | (1,689) | (1,329) |
Proceeds from NDT fund sales | 5,822 | 4,050 | 6,532 |
Investment in NDT funds | (6,050) | (4,271) | (6,673) |
Collection of DPP, net | 7,340 | 4,964 | 3,902 |
Proceeds from sales of assets and businesses | 24 | 52 | 878 |
Acquisition of business | (1,690) | (29) | (30) |
Other investing activities | 7 | 27 | 2 |
Net cash flows provided by (used in) investing activities | 3,031 | 3,104 | 3,282 |
Cash flows from financing activities | |||
Change in short-term borrowings | 146 | 257 | 362 |
Proceeds from short-term borrowings with maturities greater than 90 days | 539 | 0 | 880 |
Repayments of short-term borrowings with maturities greater than 90 days | (200) | (1,180) | 0 |
Issuance of long-term debt | 3,195 | 14 | 152 |
Retirement of long-term debt | (168) | (1,162) | (105) |
Retirement of long-term debt to affiliate | 0 | (258) | 0 |
Change in money pool with Exelon | 0 | 0 | (285) |
Acquisition of CENG noncontrolling interest | 0 | 0 | (885) |
Distributions to Exelon | 0 | 0 | (1,832) |
Contributions from Exelon | 0 | 1,750 | 64 |
Dividends paid on common stock | (366) | (185) | 0 |
Repurchases of common stock | (992) | 0 | 0 |
Other financing activities | 42 | (35) | (46) |
Net cash flows provided by (used in) financing activities | 2,196 | (799) | (1,695) |
Increase (decrease) in cash, restricted cash, and cash equivalents | (74) | (48) | 249 |
Cash, restricted cash, and cash equivalents at beginning of period | 528 | 576 | 327 |
Cash, restricted cash, and cash equivalents at end of period | 454 | 528 | 576 |
Supplemental cash flow information | |||
Increase (decrease) in capital expenditures not paid | 16 | (23) | 96 |
Increase (decrease) in DPP | 8,097 | 5,166 | 3,652 |
Increase (decrease) in PP&E related to ARO update | $ 501 | $ 343 | $ 618 |
Consolidated Balance Sheets, Pa
Consolidated Balance Sheets, Parent - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | |
Current assets | |||
Cash and cash equivalents | $ 368 | $ 422 | |
Restricted cash and cash equivalents | 86 | 106 | |
Accounts receivable | |||
Customer accounts receivable (net of allowance for credit losses of $56 and $46 as of December 31, 2023 and 2022, respectively) | 1,934 | 2,585 | |
Other accounts receivable (net of allowance for credit losses of $5 as of December 31, 2023 and 2022) | 917 | 731 | |
Mark-to-market derivative assets | 1,179 | 2,368 | |
Inventories, net | |||
Natural gas, oil, and emission allowances | 284 | 429 | |
Materials and supplies | 1,216 | 1,076 | |
Renewable energy credits | 660 | 617 | |
Other | 1,655 | 1,026 | |
Total current assets | 8,299 | 9,360 | |
Property, plant, and equipment (net of accumulated depreciation and amortization of $17,423 and $16,726 as of December 31, 2023 and 2022, respectively) | 22,116 | 19,822 | |
Deferred debits and other assets | |||
Nuclear decommissioning trust funds | 16,398 | 14,114 | |
Investments | 563 | 202 | |
Goodwill | 425 | 47 | |
Mark-to-market derivative assets | 995 | 1,261 | |
Deferred income taxes | 52 | 44 | |
Other | 1,910 | 2,059 | |
Total deferred debits and other assets | 20,343 | 17,727 | |
Total assets | [1] | 50,758 | 46,909 |
Current liabilities | |||
Short-term borrowings | 1,644 | 1,159 | |
Long-term debt due within one year | 121 | 143 | |
Accounts payable and accrued expenses | 2,612 | 3,734 | |
Mark-to-market derivative liabilities | 632 | 1,558 | |
Renewable energy credit obligation | 972 | 901 | |
Other | 338 | 344 | |
Total current liabilities | 6,319 | 7,839 | |
Long-term debt | 7,496 | 4,466 | |
Deferred credits and other liabilities | |||
Deferred income taxes and unamortized ITCs | 3,209 | 3,031 | |
Asset retirement obligations | 14,118 | 12,699 | |
Pension obligations | 1,070 | 605 | |
Non-pension postretirement benefit obligations | 732 | 609 | |
Spent nuclear fuel obligation | 1,296 | 1,230 | |
Payables related to Regulatory Agreement Units | 3,688 | 2,897 | |
Mark-to-market derivative liabilities | 419 | 983 | |
Other | 1,125 | 1,178 | |
Total deferred credits and other liabilities | 25,657 | 23,232 | |
Total liabilities | [1] | 39,472 | 35,537 |
Commitments and contingencies (Note 19) | |||
Member’s equity | |||
Common stock (No par value, 1,000 shares authorized, 317 shares and 327 shares outstanding as of December 31, 2023 and 2022, respectively) | 12,355 | 13,274 | |
Retained earnings (deficit) | 761 | (496) | |
Accumulated other comprehensive income (loss), net | (2,191) | (1,760) | |
Total shareholders’ equity | 10,925 | 11,018 | |
Noncontrolling interests | 361 | 354 | |
Total equity | 11,286 | 11,372 | |
Total liabilities and equity | $ 50,758 | $ 46,909 | |
[1] Our consolidated assets include $3,355 million and $2,641 million at December 31, 2023 and 2022, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $990 million and $1,041 million at December 31, 2023 and 2022, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 22–Variable Interest Entities for additional information. |
Consolidated Balance Sheets, _2
Consolidated Balance Sheets, Parent (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | |
Allowance for credit losses | $ (56) | $ (46) | |
Allowance for other credit losses | (5) | (5) | |
Accumulated depreciation and amortization | $ 17,423 | $ 16,726 | |
Common stock, par value (in dollars per share) | $ 0 | $ 0 | |
Common stock, shares authorized (in shares) | 1,000,000,000 | 1,000,000,000 | |
Common stock, shares outstanding (in shares) | 317,000,000 | 327,000,000 | |
Total assets | [1] | $ 50,758 | $ 46,909 |
Total liabilities | [1] | 39,472 | 35,537 |
Variable Interest Entity, Primary Beneficiary | |||
Total assets | 3,532 | 2,842 | |
Total liabilities | 990 | 1,042 | |
Variable Interest Entity, Primary Beneficiary | Nonrecourse | |||
Total liabilities | 990 | 1,041 | |
Variable Interest Entity, Primary Beneficiary | Asset Pledged as Collateral | |||
Total assets | $ 3,355 | $ 2,641 | |
[1] Our consolidated assets include $3,355 million and $2,641 million at December 31, 2023 and 2022, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $990 million and $1,041 million at December 31, 2023 and 2022, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 22–Variable Interest Entities for additional information. |
Consolidated Statements of Chan
Consolidated Statements of Changes in Shareholders Equity, Parent - USD ($) $ in Millions | Total | CENG | Common Stock | Retained Earnings (Deficit) | Accumulated Other Comprehensive Income (Loss), net | Noncontrolling Interests | Noncontrolling Interests CENG | Predecessor Member's Equity | [1] | Predecessor Member's Equity CENG | [1] |
Beginning Balance (in shares) at Dec. 31, 2020 | 0 | ||||||||||
Beginning Balance at Dec. 31, 2020 | $ 14,676 | $ 0 | $ 0 | $ (30) | $ 2,277 | $ 12,429 | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||
Net income (loss) | (83) | 122 | (205) | ||||||||
Changes in equity of noncontrolling interest | (37) | (37) | |||||||||
Acquisition of CENG noncontrolling Interest | $ (885) | $ (1,965) | $ 1,080 | ||||||||
Deferred tax adjustment related to acquisition of CENG noncontrolling interest | (288) | (288) | |||||||||
Distribution to member | (1,832) | (1,832) | |||||||||
Contributions from member | 64 | 64 | |||||||||
Acquisition of noncontrolling interest | 0 | (2) | 2 | ||||||||
Other comprehensive income (loss), net of income taxes | (1) | (1) | |||||||||
Ending Balance (in shares) at Dec. 31, 2021 | 0 | ||||||||||
Ending Balance at Dec. 31, 2021 | 11,614 | $ 0 | 0 | (31) | 395 | 11,250 | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||
Net income (loss) | 151 | 151 | |||||||||
Separation-related adjustments | (197) | (2,006) | 7 | 1,802 | |||||||
Changes in equity of noncontrolling interest | (7) | (7) | |||||||||
Ending Balance (in shares) at Jan. 31, 2022 | 326,664,000 | ||||||||||
Ending Balance at Jan. 31, 2022 | 0 | $ 13,203 | 0 | 0 | 0 | (13,203) | |||||
Beginning Balance (in shares) at Dec. 31, 2021 | 0 | ||||||||||
Beginning Balance at Dec. 31, 2021 | 11,614 | $ 0 | 0 | (31) | 395 | 11,250 | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||
Net income (loss) | (167) | ||||||||||
Other comprehensive income (loss), net of income taxes | $ 277 | ||||||||||
Ending Balance (in shares) at Dec. 31, 2022 | 327,000,000 | 327,130,000 | |||||||||
Ending Balance at Dec. 31, 2022 | $ 11,372 | $ 13,274 | (496) | (1,760) | 354 | 0 | |||||
Beginning Balance (in shares) at Jan. 31, 2022 | 326,664,000 | ||||||||||
Beginning Balance at Jan. 31, 2022 | 0 | $ 13,203 | 0 | 0 | 0 | (13,203) | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||
Net income (loss) | (318) | (311) | (7) | ||||||||
Employee incentive plans (in shares) | 466,000 | ||||||||||
Employee incentive plans | 71 | $ 71 | |||||||||
Changes in equity of noncontrolling interest | (34) | (34) | |||||||||
Common stock dividends | (185) | (185) | |||||||||
Other comprehensive income (loss), net of income taxes | $ 277 | 277 | |||||||||
Ending Balance (in shares) at Dec. 31, 2022 | 327,000,000 | 327,130,000 | |||||||||
Ending Balance at Dec. 31, 2022 | $ 11,372 | $ 13,274 | (496) | (1,760) | 354 | 0 | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||
Net income (loss) | 1,577 | 1,623 | (46) | ||||||||
Employee incentive plans (in shares) | 902,000 | ||||||||||
Employee incentive plans | 81 | $ 81 | |||||||||
Changes in equity of noncontrolling interest | 53 | 53 | |||||||||
Common stock dividends | $ (366) | (366) | |||||||||
Common stock repurchased (in shares) | (10,600,000) | (10,560,000) | |||||||||
Common stock repurchased | $ (1,000) | $ (1,000) | |||||||||
Other comprehensive income (loss), net of income taxes | $ (431) | (431) | |||||||||
Ending Balance (in shares) at Dec. 31, 2023 | 317,000,000 | 317,472,000 | |||||||||
Ending Balance at Dec. 31, 2023 | $ 11,286 | $ 12,355 | $ 761 | $ (2,191) | $ 361 | $ 0 | |||||
[1] Represents Constellation’s predecessor member's equity prior to the separation transaction. Upon completion of the separation, the predecessor member's equity was transferred to CEG Parent’s Common stock. See Note 1 — Basis of Presentation for additional information on the separation. |
Consolidated Statements of Ch_2
Consolidated Statements of Changes in Equity, Parent (Parenthetical) - $ / shares | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Statement of Stockholders' Equity [Abstract] | ||
Common stock dividends (in dollars per share) | $ 0.2820 | $ 0.1410 |
Consolidated Statements of Op_2
Consolidated Statements of Operations and Comprehensive Income - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Revenues [Abstract] | |||
Total operating revenues | $ 24,918 | $ 24,440 | $ 19,649 |
Operating expenses | |||
Purchased power and fuel | 16,001 | 17,457 | 12,157 |
Purchased power and fuel from affiliates | 0 | 5 | 6 |
Operating and maintenance | 5,685 | 4,797 | 3,934 |
Operating and maintenance from affiliates | 0 | 44 | 621 |
Depreciation and amortization | 1,096 | 1,091 | 3,003 |
Taxes other than income taxes | 553 | 552 | 475 |
Total operating expenses | 23,335 | 23,946 | 20,196 |
Total operating expenses | 27 | 1 | 201 |
Gain (loss) on sales of assets and businesses | 1,610 | 495 | (346) |
Operating income (loss) | |||
Interest expense, net | (431) | (250) | (282) |
Interest expense to affiliates | 0 | (1) | (15) |
Other, net | 1,268 | (786) | 795 |
Total other income and (deductions) | 837 | (1,037) | 498 |
Income (loss) before income taxes | 2,447 | (542) | 152 |
Income tax (benefit) expense | 859 | (388) | 225 |
Equity in income (losses) of unconsolidated affiliates | (11) | (13) | (10) |
Net income (loss) | 1,577 | (167) | (83) |
Net income (loss) attributable to noncontrolling interests | (46) | (7) | 122 |
Net income (loss) attributable to membership interest | 1,623 | (160) | (205) |
Comprehensive income (loss), net of income taxes | |||
Net income (loss) | 1,577 | (167) | (83) |
Pension and non-pension postretirement benefit plans: | |||
Prior service benefit reclassified to periodic benefit cost | (4) | (6) | 0 |
Actuarial loss reclassified to periodic benefit cost | 25 | 101 | 0 |
Pension and non-pension postretirement benefit plans valuation adjustment | (453) | 186 | 0 |
Unrealized gain (loss) on cash flow hedges | (1) | (1) | (1) |
Other comprehensive income (loss), net of income taxes | 2 | (3) | 0 |
Comprehensive income (loss) | (431) | 277 | (1) |
Comprehensive income (loss) | 1,146 | 110 | (84) |
Comprehensive income (loss) attributable to noncontrolling interests | (46) | (7) | 122 |
Comprehensive income (loss) attributable to membership interest | 1,192 | 117 | (206) |
Nonrelated Party | |||
Revenues [Abstract] | |||
Operating revenues | 24,918 | 24,280 | 18,461 |
Affiliated Entities | |||
Revenues [Abstract] | |||
Operating revenues | 0 | 160 | 1,188 |
Constellation Energy Generation, LLC | |||
Revenues [Abstract] | |||
Total operating revenues | 24,918 | 24,440 | 19,649 |
Operating expenses | |||
Purchased power and fuel | 16,001 | 17,457 | 12,157 |
Purchased power and fuel from affiliates | 0 | 5 | 6 |
Operating and maintenance | 5,685 | 4,797 | 3,934 |
Operating and maintenance from affiliates | 0 | 44 | 621 |
Depreciation and amortization | 1,096 | 1,091 | 3,003 |
Taxes other than income taxes | 553 | 552 | 475 |
Total operating expenses | 23,335 | 23,946 | 20,196 |
Total operating expenses | 27 | 1 | 201 |
Gain (loss) on sales of assets and businesses | 1,610 | 495 | (346) |
Operating income (loss) | |||
Interest expense, net | (431) | (250) | (282) |
Interest expense to affiliates | 0 | (1) | (15) |
Other, net | 1,268 | (786) | 795 |
Total other income and (deductions) | 837 | (1,037) | 498 |
Income (loss) before income taxes | 2,447 | (542) | 152 |
Income tax (benefit) expense | 859 | (388) | 225 |
Equity in income (losses) of unconsolidated affiliates | (11) | (13) | (10) |
Net income (loss) | 1,577 | (167) | (83) |
Net income (loss) attributable to noncontrolling interests | (46) | (7) | 122 |
Net income (loss) attributable to membership interest | 1,623 | (160) | (205) |
Comprehensive income (loss), net of income taxes | |||
Net income (loss) | 1,577 | (167) | (83) |
Pension and non-pension postretirement benefit plans: | |||
Prior service benefit reclassified to periodic benefit cost | (4) | (6) | 0 |
Actuarial loss reclassified to periodic benefit cost | 25 | 101 | 0 |
Pension and non-pension postretirement benefit plans valuation adjustment | (453) | 186 | 0 |
Unrealized gain (loss) on cash flow hedges | (1) | (1) | (1) |
Other comprehensive income (loss), net of income taxes | 2 | (3) | 0 |
Comprehensive income (loss) | (431) | 277 | (1) |
Comprehensive income (loss) | 1,146 | 110 | (84) |
Comprehensive income (loss) attributable to noncontrolling interests | (46) | (7) | 122 |
Comprehensive income (loss) attributable to membership interest | 1,192 | 117 | (206) |
Constellation Energy Generation, LLC | Nonrelated Party | |||
Revenues [Abstract] | |||
Operating revenues | 24,918 | 24,280 | 18,461 |
Constellation Energy Generation, LLC | Affiliated Entities | |||
Revenues [Abstract] | |||
Operating revenues | $ 0 | $ 160 | $ 1,188 |
Consolidated Statements of Ca_2
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Cash flows from operating activities | |||
Net income (loss) | $ 1,577 | $ (167) | $ (83) |
Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities | |||
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization | 2,514 | 2,427 | 4,540 |
Deferred income taxes and amortization of ITCs | 251 | (643) | (205) |
Net fair value changes related to derivatives | 996 | 986 | (568) |
Net realized and unrealized (gains) losses on NDT funds | (476) | 794 | (586) |
Net realized and unrealized (gains) losses on equity investments | (307) | 13 | 160 |
Other non-cash operating activities | 18 | 248 | (261) |
Changes in assets and liabilities: | |||
Accounts receivable | 396 | (868) | (616) |
Receivables from and payables to affiliates, net | 0 | 20 | 14 |
Inventories | 60 | (228) | (68) |
Accounts payable and accrued expenses | (1,330) | 1,142 | 346 |
Option premiums received (paid), net | 26 | (177) | (338) |
Collateral received (posted), net | (1,491) | (351) | (130) |
Income taxes | 325 | 162 | 256 |
Pension and non-pension postretirement benefit contributions | (54) | (237) | (259) |
Other assets and liabilities | (7,806) | (5,474) | (3,540) |
Net cash flows provided by (used in) operating activities | (5,301) | (2,353) | (1,338) |
Cash flows from investing activities | |||
Capital expenditures | (2,422) | (1,689) | (1,329) |
Proceeds from NDT fund sales | 5,822 | 4,050 | 6,532 |
Investment in NDT funds | (6,050) | (4,271) | (6,673) |
Collection of DPP, net | 7,340 | 4,964 | 3,902 |
Proceeds from sales of assets and businesses | 24 | 52 | 878 |
Other investing activities | 7 | 27 | 2 |
Net cash flows provided by (used in) investing activities | 3,031 | 3,104 | 3,282 |
Cash flows from financing activities | |||
Change in short-term borrowings | 146 | 257 | 362 |
Proceeds from short-term borrowings with maturities greater than 90 days | 539 | 0 | 880 |
Repayments of short-term borrowings with maturities greater than 90 days | (200) | (1,180) | 0 |
Retirement of long-term debt | 3,195 | 14 | 152 |
Retirement of long-term debt | (168) | (1,162) | (105) |
Retirement of long-term debt to affiliate | 0 | (258) | 0 |
Change in money pool with Exelon | 0 | 0 | (285) |
Acquisition of CENG noncontrolling interest | 0 | 0 | (885) |
Distributions to member | 0 | 0 | (1,832) |
Contributions from member | 0 | 1,750 | 64 |
Other financing activities | 42 | (35) | (46) |
Net cash flows provided by (used in) financing activities | 2,196 | (799) | (1,695) |
Increase (decrease) in cash, restricted cash, and cash equivalents | (74) | (48) | 249 |
Cash, restricted cash, and cash equivalents at beginning of period | 528 | 576 | 327 |
Cash, restricted cash, and cash equivalents at end of period | 454 | 528 | 576 |
Supplemental cash flow information | |||
Increase (decrease) in capital expenditures not paid | 16 | (23) | 96 |
Increase (decrease) in DPP | 8,097 | 5,166 | 3,652 |
Increase (decrease) in PP&E related to ARO update | 501 | 343 | 618 |
Constellation Energy Generation, LLC | |||
Cash flows from operating activities | |||
Net income (loss) | 1,577 | (167) | (83) |
Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities | |||
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization | 2,514 | 2,427 | 4,540 |
Deferred income taxes and amortization of ITCs | 251 | (643) | (205) |
Net fair value changes related to derivatives | 996 | 986 | (568) |
Net realized and unrealized (gains) losses on NDT funds | (476) | 794 | (586) |
Net realized and unrealized (gains) losses on equity investments | (307) | 13 | 160 |
Other non-cash operating activities | (44) | 199 | (261) |
Changes in assets and liabilities: | |||
Accounts receivable | 389 | (855) | (616) |
Receivables from and payables to affiliates, net | 73 | 65 | 14 |
Inventories | 60 | (228) | (68) |
Accounts payable and accrued expenses | (1,330) | 1,112 | 346 |
Option premiums received (paid), net | 26 | (177) | (338) |
Collateral received (posted), net | (1,491) | (351) | (130) |
Income taxes | 325 | 162 | 256 |
Pension and non-pension postretirement benefit contributions | (54) | (237) | (259) |
Other assets and liabilities | (7,897) | (5,540) | (3,540) |
Net cash flows provided by (used in) operating activities | (5,388) | (2,440) | (1,338) |
Cash flows from investing activities | |||
Capital expenditures | (2,422) | (1,689) | (1,329) |
Proceeds from NDT fund sales | 5,822 | 4,050 | 6,532 |
Investment in NDT funds | (6,050) | (4,271) | (6,673) |
Collection of DPP, net | 7,340 | 4,964 | 3,902 |
Proceeds from sales of assets and businesses | 24 | 52 | 878 |
Acquisitions of assets and businesses | (1,690) | (29) | (30) |
Other investing activities | 7 | 27 | 2 |
Net cash flows provided by (used in) investing activities | 3,031 | 3,104 | 3,282 |
Cash flows from financing activities | |||
Change in short-term borrowings | 146 | 257 | 362 |
Proceeds from short-term borrowings with maturities greater than 90 days | 539 | 0 | 880 |
Repayments of short-term borrowings with maturities greater than 90 days | (200) | (1,180) | 0 |
Retirement of long-term debt | 3,195 | 14 | 152 |
Retirement of long-term debt | (168) | (1,162) | (105) |
Retirement of long-term debt to affiliate | 0 | (258) | 0 |
Change in money pool with Exelon | 0 | 0 | (285) |
Acquisition of CENG noncontrolling interest | 0 | 0 | (885) |
Payments of Distributions to Parent | 0 | 0 | (1,832) |
Distributions to member | (1,239) | (185) | 0 |
Contributions from Exelon | 0 | 1,750 | 64 |
Contributions from member | 0 | 82 | 0 |
Other financing activities | 23 | (57) | (46) |
Net cash flows provided by (used in) financing activities | 2,296 | (739) | (1,695) |
Increase (decrease) in cash, restricted cash, and cash equivalents | (61) | (75) | 249 |
Cash, restricted cash, and cash equivalents at beginning of period | 501 | 576 | 327 |
Cash, restricted cash, and cash equivalents at end of period | 440 | 501 | 576 |
Supplemental cash flow information | |||
Increase (decrease) in capital expenditures not paid | 16 | (23) | 96 |
Increase (decrease) in DPP | 8,097 | 5,166 | 3,652 |
Increase (decrease) in PP&E related to ARO update | $ 501 | $ 343 | $ 618 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | |
Current assets | |||
Cash and cash equivalents | $ 368 | $ 422 | |
Restricted cash and cash equivalents | 86 | 106 | |
Accounts receivable | |||
Customer accounts receivable (net of allowance for credit losses of $56 and $46 as of December 31, 2023 and 2022, respectively) | 1,934 | 2,585 | |
Other accounts receivable (net of allowance for credit losses of $5 as of December 31, 2023 and 2022) | 917 | 731 | |
Mark-to-market derivative assets | 1,179 | 2,368 | |
Inventories, net | |||
Natural gas, oil, and emission allowance | 284 | 429 | |
Materials and supplies | 1,216 | 1,076 | |
Renewable energy credits | 660 | 617 | |
Other | 1,655 | 1,026 | |
Total current assets | 8,299 | 9,360 | |
Property, plant, and equipment (net of accumulated depreciation and amortization of $17,423 and $16,726 as of December 31, 2023 and 2022, respectively) | 22,116 | 19,822 | |
Deferred debits and other assets | |||
Nuclear decommissioning trust funds | 16,398 | 14,114 | |
Investments | 563 | 202 | |
Goodwill | 425 | 47 | |
Mark-to-market derivative assets | 995 | 1,261 | |
Deferred income taxes | 52 | 44 | |
Other | 1,910 | 2,059 | |
Total deferred debits and other assets | 20,343 | 17,727 | |
Total assets | [1] | 50,758 | 46,909 |
Current liabilities | |||
Short-term borrowings | 1,644 | 1,159 | |
Long-term debt due within one year | 121 | 143 | |
Accounts payable and accrued expenses | 2,612 | 3,734 | |
Mark-to-market derivative liabilities | 632 | 1,558 | |
Renewable energy credit obligation | 972 | 901 | |
Other | 338 | 344 | |
Total current liabilities | 6,319 | 7,839 | |
Long-term debt | 7,496 | 4,466 | |
Deferred credits and other liabilities | |||
Deferred income taxes and unamortized ITCs | 3,209 | 3,031 | |
Asset retirement obligations | 14,118 | 12,699 | |
Pension obligations | 1,070 | 605 | |
Non-pension postretirement benefit obligations | 732 | 609 | |
Spent nuclear fuel obligation | 1,296 | 1,230 | |
Payables related to Regulatory Agreement Units | 3,688 | 2,897 | |
Mark-to-market derivative liabilities | 419 | 983 | |
Other | 1,125 | 1,178 | |
Total deferred credits and other liabilities | 25,657 | 23,232 | |
Total liabilities | [1] | 39,472 | 35,537 |
Commitments and contingencies (Note 19) | |||
Member’s equity | |||
Undistributed earnings | 761 | (496) | |
Accumulated other comprehensive income (loss), net | (2,191) | (1,760) | |
Total liabilities and equity | 50,758 | 46,909 | |
Variable Interest Entity, Primary Beneficiary | |||
Current assets | |||
Cash and cash equivalents | 48 | 51 | |
Restricted cash and cash equivalents | 47 | 46 | |
Accounts receivable | |||
Customer accounts receivable (net of allowance for credit losses of $56 and $46 as of December 31, 2023 and 2022, respectively) | 19 | 20 | |
Other accounts receivable (net of allowance for credit losses of $5 as of December 31, 2023 and 2022) | 10 | 9 | |
Inventories, net | |||
Materials and supplies | 14 | 12 | |
Other | 1,249 | 549 | |
Total current assets | 1,387 | 687 | |
Property, plant, and equipment (net of accumulated depreciation and amortization of $17,423 and $16,726 as of December 31, 2023 and 2022, respectively) | 1,979 | 1,965 | |
Deferred debits and other assets | |||
Other | 166 | 190 | |
Total deferred debits and other assets | 2,145 | 2,155 | |
Total assets | 3,532 | 2,842 | |
Current liabilities | |||
Long-term debt due within one year | 63 | 60 | |
Other | 0 | 2 | |
Total current liabilities | 94 | 102 | |
Long-term debt | 704 | 764 | |
Deferred credits and other liabilities | |||
Asset retirement obligations | 190 | 173 | |
Other | 2 | 3 | |
Total deferred credits and other liabilities | 896 | 940 | |
Total liabilities | 990 | 1,042 | |
Variable Interest Entity, Primary Beneficiary | Nonrecourse | |||
Deferred credits and other liabilities | |||
Total liabilities | 990 | 1,041 | |
Variable Interest Entity, Primary Beneficiary | Asset Pledged as Collateral | |||
Deferred debits and other assets | |||
Total assets | 3,355 | 2,641 | |
Constellation Energy Generation, LLC | |||
Current assets | |||
Cash and cash equivalents | 366 | 403 | |
Restricted cash and cash equivalents | 74 | 98 | |
Accounts receivable | |||
Customer accounts receivable (net of allowance for credit losses of $56 and $46 as of December 31, 2023 and 2022, respectively) | 1,934 | 2,585 | |
Other accounts receivable (net of allowance for credit losses of $5 as of December 31, 2023 and 2022) | 911 | 718 | |
Mark-to-market derivative assets | 1,179 | 2,368 | |
Inventories, net | |||
Natural gas, oil, and emission allowance | 284 | 429 | |
Materials and supplies | 1,216 | 1,076 | |
Renewable energy credits | 660 | 617 | |
Other | 1,655 | 1,026 | |
Total current assets | 8,279 | 9,320 | |
Property, plant, and equipment (net of accumulated depreciation and amortization of $17,423 and $16,726 as of December 31, 2023 and 2022, respectively) | 22,116 | 19,822 | |
Deferred debits and other assets | |||
Nuclear decommissioning trust funds | 16,398 | 14,114 | |
Investments | 563 | 202 | |
Goodwill | 425 | 47 | |
Mark-to-market derivative assets | 995 | 1,261 | |
Deferred income taxes | 52 | 44 | |
Other | 1,910 | 2,059 | |
Total deferred debits and other assets | 20,343 | 17,727 | |
Total assets | [2] | 50,738 | 46,869 |
Current liabilities | |||
Short-term borrowings | 1,644 | 1,159 | |
Long-term debt due within one year | 121 | 143 | |
Mark-to-market derivative liabilities | 632 | 1,558 | |
Renewable energy credit obligation | 972 | 901 | |
Other | 338 | 344 | |
Total current liabilities | 6,311 | 7,829 | |
Long-term debt | 7,496 | 4,466 | |
Deferred credits and other liabilities | |||
Deferred income taxes and unamortized ITCs | 3,209 | 3,031 | |
Asset retirement obligations | 14,118 | 12,699 | |
Pension obligations | 1,070 | 605 | |
Non-pension postretirement benefit obligations | 732 | 609 | |
Spent nuclear fuel obligation | 1,296 | 1,230 | |
Payables related to Regulatory Agreement Units | 3,688 | 2,897 | |
Mark-to-market derivative liabilities | 419 | 983 | |
Other | 1,025 | 1,106 | |
Total deferred credits and other liabilities | 25,557 | 23,160 | |
Total liabilities | [2] | 39,364 | 35,455 |
Commitments and contingencies (Note 19) | |||
Member’s equity | |||
Membership interest | 11,537 | 12,408 | |
Undistributed earnings | 1,667 | 412 | |
Accumulated other comprehensive income (loss), net | (2,191) | (1,760) | |
Total member’s equity | 11,013 | 11,060 | |
Noncontrolling interests | 361 | 354 | |
Total equity | 11,374 | 11,414 | |
Total liabilities and equity | 50,738 | 46,869 | |
Constellation Energy Generation, LLC | Nonrelated Party | |||
Current liabilities | |||
Accounts payable and accrued expenses | 2,486 | 3,679 | |
Constellation Energy Generation, LLC | Related Party | |||
Current liabilities | |||
Accounts payable and accrued expenses | 118 | 45 | |
Constellation Energy Generation, LLC | Variable Interest Entity, Primary Beneficiary | Nonrecourse | |||
Deferred credits and other liabilities | |||
Total liabilities | 990 | 1,041 | |
Constellation Energy Generation, LLC | Variable Interest Entity, Primary Beneficiary | Asset Pledged as Collateral | |||
Deferred debits and other assets | |||
Total assets | $ 3,355 | $ 2,641 | |
[1] Our consolidated assets include $3,355 million and $2,641 million at December 31, 2023 and 2022, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $990 million and $1,041 million at December 31, 2023 and 2022, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 22–Variable Interest Entities for additional information. Our consolidated assets include $3,355 million and $2,641 million as of December 31, 2023 and 2022, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $990 million and $1,041 million as of December 31, 2023 and 2022, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 22–Variable Interest Entities for additional information. |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Allowance for credit losses | $ (56) | $ (46) |
Allowance for other credit losses | (5) | (5) |
Accumulated depreciation and amortization | 17,423 | 16,726 |
Constellation Energy Generation, LLC | ||
Allowance for credit losses | (56) | (46) |
Allowance for other credit losses | $ (5) | $ (5) |
Consolidated Statements of Ch_3
Consolidated Statements of Changes in Equity - USD ($) $ in Millions | Total | CENG | Retained Earnings (Deficit) | Accumulated Other Comprehensive Income (Loss), net | Noncontrolling Interests | Noncontrolling Interests CENG | Constellation Energy Generation, LLC | Constellation Energy Generation, LLC CENG | Constellation Energy Generation, LLC Membership Interest | Constellation Energy Generation, LLC Membership Interest CENG | Constellation Energy Generation, LLC Retained Earnings (Deficit) | Constellation Energy Generation, LLC Accumulated Other Comprehensive Income (Loss), net | Constellation Energy Generation, LLC Noncontrolling Interests | Constellation Energy Generation, LLC Noncontrolling Interests CENG |
Beginning Balance at Dec. 31, 2020 | $ 14,676 | $ 9,624 | $ 2,805 | $ (30) | $ 2,277 | |||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||
Net income (loss) | $ (83) | $ 122 | (83) | (205) | 122 | |||||||||
Changes in equity of noncontrolling interests | (37) | (37) | (37) | (37) | ||||||||||
Acquisition of CENG noncontrolling Interest | $ (885) | $ (1,965) | $ (885) | $ 1,080 | $ (1,965) | |||||||||
Deferred tax adjustment related to acquisition of CENG noncontrolling interest | (288) | (288) | (288) | |||||||||||
Distribution to member | (1,832) | (1,832) | (1,832) | |||||||||||
Contribution from member | 64 | 64 | 64 | |||||||||||
Acquisition of noncontrolling interest | 0 | (2) | 0 | 2 | (2) | |||||||||
Other comprehensive income (loss), net of income taxes | (1) | $ (1) | (1) | (1) | 0 | |||||||||
Ending Balance at Dec. 31, 2021 | 11,614 | 10,482 | 768 | (31) | 395 | |||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||
Net income (loss) | (167) | (167) | (160) | (7) | ||||||||||
Separation-related adjustments | (166) | 1,844 | (11) | (2,006) | 7 | |||||||||
Changes in equity of noncontrolling interests | (41) | (41) | ||||||||||||
Distribution to member | (185) | (185) | ||||||||||||
Contribution from member | 82 | 82 | ||||||||||||
Other comprehensive income (loss), net of income taxes | 277 | 277 | 277 | |||||||||||
Ending Balance at Dec. 31, 2022 | 11,414 | 12,408 | 412 | (1,760) | 354 | |||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||
Net income (loss) | 1,577 | $ 1,623 | (46) | 1,577 | 1,623 | (46) | ||||||||
Changes in equity of noncontrolling interests | 53 | $ 53 | 53 | 53 | ||||||||||
Distribution to member | (1,239) | (871) | (368) | |||||||||||
Other comprehensive income (loss), net of income taxes | $ (431) | $ (431) | (431) | (431) | ||||||||||
Ending Balance at Dec. 31, 2023 | $ 11,374 | $ 11,537 | $ 1,667 | $ (2,191) | $ 361 |
Basis of Presentation
Basis of Presentation | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation Description of Business We are a producer of carbon-free energy and a supplier of energy products and services. Our generating capacity includes primarily nuclear, wind, solar, natural gas and hydroelectric assets. Through our integrated business operations, we sell electricity, natural gas, and other energy-related products and sustainable solutions to various types of customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, governmental, and residential customers in markets across multiple geographic regions. We have five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. Basis of Presentation On February 21, 2021, the Board of Directors of Exelon authorized management to pursue a plan to separate its competitive generation and customer-facing energy businesses, conducted through Constellation Energy Generation, LLC ( “ Constellation ” , formerly Exelon Generation Company, LLC) and its subsidiaries, into an independent, publicly-traded company. CEG Parent, a direct, wholly owned subsidiary of Exelon, was newly formed for the purpose of separation and had not engaged in any business activities nor had any assets or liabilities prior to the separation. On February 1, 2022, the separation was completed and CEG Parent holds all the interests in Constellation previously held by Exelon. As an individual registrant, Constellation has historically filed consolidated financial statements to reflect its financial position and operating results as a stand-alone, wholly owned subsidiary of Exelon. The accompanying Consolidated Financial Statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC. The Consolidated Financial Statements include the accounts of our subsidiaries and all intercompany transactions have been eliminated. CEG Parent's prior period financial statements have been adjusted to reflect the balances of Constellation in accordance with applicable guidance. Amounts disclosed relate to CEG Parent and Constellation unless specifically noted as relating to CEG Parent only. Unless otherwise indicated or the context otherwise requires, references herein to the terms “we,” “us,” and “our” refer collectively to CEG Parent and Constellation. We own 100% of our significant consolidated subsidiaries, either directly or indirectly, except for certain consolidated VIEs, including CRP, of which we hold a 51% interest. The remaining interests in the consolidated VIEs are included in noncontrolling interests on the Consolidated Balance Sheets. See Note 22 — Variable Interest Entities for additional information on consolidated VIEs. We consolidate the accounts of entities in which we have a controlling financial interest, after the elimination of intercompany transactions. Where we do not have a controlling financial interest in an entity, proportionate consolidation, equity method accounting or accounting for investments in equity securities with or without readily determinable fair value is applied. We apply proportionate consolidation when we have an undivided interest in an asset and are proportionately liable for our share of each liability associated with the asset. We proportionately consolidate our undivided ownership interest in jointly owned electric plants. Under proportionate consolidation, we separately record our proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. See Note 9 — Jointly Owned Electric Plant for additional information on application of proportionate consolidation. We apply equity method accounting when we have a significant influence over an investee through an ownership in equity, which generally approximates a 20% to 50% voting interest. We apply equity method accounting to certain investments and joint ventures. Under equity method accounting, we report our interest in the entity as an investment and our percentage share of the earnings from the entity as single line items in our consolidated financial statements. We use accounting for investments in equity securities with or without readily determinable fair values if we lack a significant influence, which generally results when we hold less than 20% of the common stock of an entity. Under accounting for investments in equity securities with readily determinable fair values, the investments are reported based on quoted prices in active markets and realized and unrealized gains and losses are included in earnings. Under accounting for investments in equity securities without readily determinable fair values, the investments are reported at cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment, and changes in measurement are reported in earnings. Separation from Exelon On February 1, 2022, Exelon completed the separation through a pro-rata distribution of all of the outstanding shares of our common stock, no par value, on the basis of one such share for every three shares of Exelon common stock held on January 20, 2022, the record date of the distribution. We are an independent, publicly traded company listed on the Nasdaq Stock Market under the symbol “CEG”, and regular-way trading began on February 2, 2022. Exelon no longer retains any ownership interest in CEG Parent or Constellation. Prior to completion of the separation, our financial statements include certain transactions with affiliates of Exelon, which are disclosed as related party transactions. After February 1, 2022, all transactions with Exelon or its affiliates are no longer related party transactions. In order to govern the ongoing relationships with Exelon after the separation, and to facilitate an orderly transition, we entered into several agreements with Exelon, including the following: • Separation Agreement – sets forth the principal actions to be taken in connection with the separation, including the transfer of assets and assumption of liabilities and establishes certain rights and obligations between us following the distribution • Transition Services Agreement (TSA) – governs all matters relating to the provision of services between us and Exelon on a transitional basis, in addition to providing us with certain services for an expected period of two-years, provided that certain services may be longer than the term and services may be extended with approval from both parties; the services include support for information technology, accounting, finance, human resources, security, and various other administrative and operational services • Employee Matters Agreement (EMA) – addresses certain employment, compensation and benefits matters, including the allocation of employees between us and Exelon and the allocation and treatment of certain assets and liabilities relating to our employees and former employees • Tax Matters Agreement (TMA) - governs the respective rights, responsibilities, and obligations between us and Exelon with respect to all tax matters (excluding employee-related taxes covered under EMA), in addition to certain restrictions which generally prohibit us from taking or failing to take any action in the two-year period following the distribution that would prevent the distribution from qualifying as tax-free for U.S. federal income tax purposes, including limitations on our ability to pursue certain equity issuances, strategic transactions, repurchases or other transactions Pursuant to the Separation Agreement, we received a cash contribution of $1.75 billion from Exelon on January 31, 2022, the proceeds of which were used to settle $258 million of an intercompany loan from Exelon and $200 million of short-term debt outstanding prior to separation, in addition to a $192 million contribution to our pension plans. We also entered into two new five-year credit facility agreements providing $4.5 billion of capacity. See Note 17 — Debt and Credit Agreements for additional information on these facility agreements. The amounts Exelon billed us for services pursuant to the TSA were $151 million and $266 million for the years ended December 31, 2023 and 2022, respectively. The amounts we billed Exelon for services pursuant to the TSA were $14 million and $43 million for the years ended December 31, 2023 and 2022, respectively. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and OPEB plans, inventory reserves, allowance for credit losses, long-lived asset valuations and impairment assessments, derivative instruments, goodwill, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ from those estimates. Revenues Operating Revenues. Our operating revenues generally consist of revenues from contracts with customers involving competitive sales of power, natural gas, and other energy-related products and sustainable solutions. We recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that we expect to be entitled to in exchange for those goods or services. At the end of each reporting period, we accrue an estimate for the unbilled amount of power and natural gas delivered or services provided to customers. Commodity Derivatives. Derivative instruments are generally recorded at fair value with subsequent changes in fair value recognized as realized and unrealized revenue or expense. The classification of revenue or expense is based on the intent of the transaction. See Note 16 — Derivative Financial Instruments for additional information. Taxes Directly Imposed on Revenue-Producing Transactions. We collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges and fees, that are levied by state or local governments on the sale or distribution of electricity and natural gas and any taxable energy-related products and services. Some of these taxes are imposed on the customer, but paid by us, while others are imposed on us. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis in revenues. However, where these taxes are imposed on us, such as gross receipts taxes, they are reported on a gross basis in expense. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense in Taxes other than income taxes in the Consolidated Statements of Operations and Comprehensive Income. Se e Note 23 — Supplemental Financial Information for the taxes that are presented on a gross basis. Leases We recognize a ROU asset and lease liability for operating leases with a term of greater than one year. Operating lease ROU assets are included in Other deferred debits and other assets and operating lease liabilities are included in Other current liabilities and Other deferred credits and other liabilities on the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using the rate implicit in the lease whenever that is readily determinable or our incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received) and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. We include non-lease components for most asset classes, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability. Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred and consist primarily of payments for purchases of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease expense and variable lease payments are recorded to Purchased power and fuel expense for contracted generation or Operating and maintenance expense for all other lease agreements in the Consolidated Statements of Operations and Comprehensive Income. Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease payments are recognized in the period in which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Our operating leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. We generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all the economic benefits. We generally do not account for contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. We account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. See Note 11 — Leases for additional information. Income Taxes Deferred federal and state income taxes are recorded on temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. ITCs have been deferred in the Consolidated Balance Sheets and are recognized in book income over the life of the related property. We account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. We recognize accrued interest related to unrecognized tax benefits in Interest expense, net or Other, net (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in the Consolidated Statements of Operations and Comprehensive Income. Cash and Cash Equivalents We consider investments purchased with an original maturity of three months or less to be cash equivalents. Restricted Cash and Cash Equivalents Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2023 and 2022, restricted cash and cash equivalents primarily represented the payment of medical, dental, vision, and long-term disability benefits and project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities. See Note 17 — Debt and Credit Agreements and Note 23 — Supplemental Financial Information for additional information. Allowance for Credit Losses on Accounts Receivables The allowance for credit losses reflects our best estimate of losses on the customers' accounts receivable balances based on historical experience, current information, and reasonable and supportable forecasts. The allowance for credit losses for our retail customers is based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. The allowance for credit losses for our wholesale customers is developed using a credit monitoring process, like that used for retail customers. When a wholesale customer’s risk characteristics are no longer aligned with the pooled population, we use specific identification to develop an allowance for credit losses. Adjustments to the allowance for credit losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. We have certain non-customer receivables in Current Assets and Other deferred debits and other assets which primarily are with governmental agencies. As such, the allowance for credit losses related to these receivables is not material. We monitor these balances and will record an allowance if there are indicators of a decline in credit quality. Variable Interest Entities We account for our investments in and arrangements with VIEs based on the following specific requirements: • qualitative assessment of factors determinant in whether we have a controlling financial interest, • ongoing reconsideration of this assessment, and • where we consolidate a VIE (as primary beneficiary), disclosure of (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary. See Note 22 — Variable Interest Entities for additional information. Inventories Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Natural gas, oil, materials and supplies, and emissions allowances are generally included in inventory when purchased. Natural gas, oil, and emissions allowances are expensed to Purchased power and fuel expense when consumed. Materials and supplies generally include items utilized within our generating plants and are expensed to Operating and maintenance or capitalized to Property, plant and equipment, as appropriate, when installed or used. Debt and Equity Security Investments Debt and Equity Investments within NDT funds. We have debt and equity securities held in our NDT funds which are measured and recorded at fair value. Realized and unrealized gains and losses, net of trust level taxes, on our NDT funds associated with the Regulatory Agreement Units are offset in Noncurrent payables related to Regulatory Agreement Units. Realized and unrealized gains and losses, net of trust level taxes, on our NDT funds associated with the Non-Regulatory Agreement Units are included in Other, net in the Consolidated Statements of Operations and Comprehensive Income. For equity securities without readily determinable fair values, we have elected to use the measurement alternative to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Our NDT funds are classified as current or noncurrent assets, depending on the timing of the decommissioning activities and income taxes on trust earnings. See Note 18 — Fair Value of Financial Assets and Liabilities and Note 10 — Asset Retirement Obligations for additional information. Equity Security Investments with Readily Determinable Fair Values. We have certain equity securities with readily determinable fair values. Realized and unrealized gains and losses are included in Other, net in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Fair Value of Financial Assets and Liabilities for additional information. Equity Security Investments without Readily Determinable Fair Values. We have certain equity securities without readily determinable fair values. We have elected to use the measurement alternative to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Changes in measurement are reported in Other, net in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Fair Value of Financial Assets for additional information. Property, Plant and Equipment Property, plant and equipment is recorded at acquired cost. Acquired cost includes construction-related direct labor and material costs. When appropriate, acquired cost also includes capitalized interest. Costs associated with nuclear outages and planned major maintenance activities, are expensed to Operating and maintenance expense or capitalized to Property, plant, and equipment based on the nature of the activities in the period incurred. The cost of repairs and maintenance and minor replacements of property is charged to Operating and maintenance expense as incurred. Upon retirement, the cost of property is generally charged to accumulated depreciation in accordance with the composite and group methods of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to Operating and maintenance expense as incurred. Certain assets follow the unitary method of depreciation and recognize gains and losses in the period of replacement or retirement. These gains and losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized in Property, plant and equipment in the Consolidated Balance Sheets. Similar costs incurred for cloud-based solutions treated as service arrangements are capitalized in Other current assets and Deferred debits and other assets in the Consolidated Balance Sheets. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Capitalized Interest. During construction, we capitalize the costs of debt funds. Most projects will use a debt rate calculated using the general corporate debt pool. In some cases, projects are specifically financed and use a project specific debt rate, which is excluded from the general corporate debt pool. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense. See Note 8 — Property, Plant, and Equipment, Note 9 — Jointly Owned Electric Plant and Note 23 — Supplemental Financial Information for additional information. Nuclear Fuel The cost of nuclear fuel is capitalized in Property, plant and equipment and charged to Purchased power and fuel using the unit-of-production method. Any potential future SNF disposal fees will also be expensed through Purchased power and fuel expense. Additionally, certain on-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 19 — Commitments and Contingencies for additional information regarding the cost of SNF storage and disposal. Depreciation and Amortization Except for the amortization of nuclear fuel, depreciation, inclusive of ARC, is generally recorded over the estimated service lives of property, plant and equipment on a straight-line basis using the group, composite or unitary methods of depreciation. Two methods of depreciating multiple asset groups exist: the group method and the composite method. The group method is typically for groups of assets that are largely homogenous and have approximately the same useful lives. The composite method is used when the assets are heterogeneous and have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimated service lives are based on a combination of depreciation studies, historical retirements, site licenses and management estimates of operating costs and expected future energy market conditions. See Note 7 — Early Plant Retirements for additional information on the impacts of early plant retirements, Note 8 — Property, Plant, and Equipment for additional information regarding depreciation, and Note 23 — Supplemental Financial Information for additional information regarding nuclear fuel. Asset Retirement Obligations We estimate and recognize a liability for our legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. We generally update our nuclear decommissioning ARO annually, unless circumstances warrant more frequent updates, based on our annual evaluation of cost escalation factors and probabilities assigned to the multiple outcome scenarios within our probability-weighted discounted cash flow models. Our multiple outcome scenarios are generally based on decommissioning cost studies which are updated, on a rotational basis, for each of our nuclear units at least every five years, unless circumstances warrant more frequent updates. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income for Non-Regulatory Agreement Units and through an offsetting decrease in noncurrent payables related to Regulatory Agreement Units. See Note 10 — Asset Retirement Obligations for additional information. Accounting Implications of the Regulatory Agreement Units Based on the requirements of the ICC, PAPUC, and PUCT that dictate our obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd, former PECO, and STP units, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation are generally offset in the Consolidated Statements of Operations and Comprehensive Income and are recorded as noncurrent payables in the Consolidated Balance Sheets (within Payables related to Regulatory Agreement Units). See Note 10 — Asset Retirement Obligations for additional information. Asset Impairments Long-Lived Assets. We regularly monitor and evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. We determine if long-lived assets or asset groups are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. Generally, pre-tax impairment losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. See Note 12 — Asset Impairments for additional information. Goodwill. Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or in an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 2 — Mergers, Acquisitions, and Dispositions and Note 13 — Intangible Assets for additional information. Equity Method Investments. We regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature. Additionally, if the entity in which we hold an investment recognizes an impairment loss, we would record their proportionate share of that impairment loss and evaluate the investment for an other-than-temporary decline in value. These impairment losses are recorded in Equity in (losses) earnings of unconsolidated affiliates in the Consolidated Statements of Operations and Comprehensive Income. Equity Security Investments. Equity investments with readily determinable fair values are measured and recorded at fair value with any changes in fair value recorded in Other, net in the Consolidated Statements of Operations and Comprehensive Income. Investments in equity securities without readily determinable fair values are qualitatively assessed for impairment each reporting period. If it is determined that the equity security is impaired, an impairment loss will be recognized in Other, net in the Consolidated Statements of Operations and Comprehensive Income to the amount by which the security’s carrying amount exceeds its fair value. Derivative Financial Instruments All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including NPNS. For derivatives intended to serve as economic hedges, changes in fair value are recognized in earnings each period. Amounts classified in earnings are included in Operating revenues, Purchased power and fuel, or Interest expense in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. While most of the derivatives serve as economic hedges, there are also derivatives entered into for proprietary trading purposes, subject to our RMP, and changes in the fair value of those derivatives are recorded in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. As part of the energy marketing business, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. NPNS are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as NPNS are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value. See Note 16 — Derivative Financial Instruments for additional information. Retirement Benefits Prior to separation, Exelon sponsored defined benefit pension plans an |
Mergers, Acquisitions, and Disp
Mergers, Acquisitions, and Dispositions | 12 Months Ended |
Dec. 31, 2023 | |
Mergers, Acquisitions, and Dispositions [Abstract] | |
Mergers, Acquisitions, and Dispositions | Mergers, Acquisitions, and Dispositions Acquisition of Joint Ownership in South Texas Project On November 1, 2023, we completed the acquisition of NRG South Texas LP (renamed and converted as Constellation South Texas, LLC), which owns a 44% undivided ownership interest in the jointly owned STP, a 2,645 MW, dual-unit nuclear plant located in Bay City, Texas. The net cash paid was $1.65 billion, after certain purchase price adjustments. The current renewed NRC licenses for the STP units expire in 2047 and 2048, and the NRC licensed operator is STP Nuclear Operating Company (STPNOC), acting on behalf of the joint owners. Other owners include City Public Service Board of San Antonio (CPS, 40%) and the City of Austin, Texas (Austin Energy, 16%). This acquisition is complementary to and aligned strategically with our existing clean energy business operations. As part of the transaction, we acquired ownership of two decommissioning trust funds established to provide funding for decontamination and decommissioning of STP. The trust funds have been funded with amounts collected from predecessor utilities. We maintain the ability to collect additional funds from utility customers in the event of a shortfall and are required to return any excess funds to utility customers upon completion of decommissioning. As such, our accounting for the future decommissioning of our interest in STP will mirror that of our existing Regulatory Agreement Units. See Note 1 — Basis of Presentation and Note 10 — Asset Retirement Obligations for additional information on our accounting policy for Regulatory Agreement Units. The acquisition was accounted for using the acquisition method of accounting in accordance with authoritative guidance, which requires, among other things, the assets acquired and liabilities assumed to be recognized at their respective fair value as of the acquisition date. The excess of the purchase price over fair value of our proportionate share of the assets acquired and liabilities assumed was recorded to goodwill. The goodwill recognized is primarily driven by the opportunity for continued operations through 80 years and the value of STP’s carbon-free energy that is not fully reflected by the markets. The goodwill amount has been assigned entirely to the ERCOT operating segment. See Note 13 — Intangible Assets for additional information. The total amount of goodwill is expected to be deductible for tax purposes over the amortization period. The fair values of STP’s assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows and future power and fuel market prices. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the acquisition to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. Any changes could result in a change in the amount of goodwill recorded. The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the STP acquisition: Cash paid for purchase price $ 1,654 Identifiable assets acquired and liabilities assumed Property, plant, and equipment 1,254 Nuclear decommissioning trust funds 869 Inventories, net 47 Other long-term assets 40 Other current assets 11 Total assets 2,221 Asset retirement obligations 429 Payables related to Regulatory Agreement Units 376 Deferred income taxes and unamortized investment tax credits 65 Accounts payable and accrued expenses 45 Pension and OPEB obligations 25 Other long-term liabilities 5 Total liabilities 945 Total net identifiable assets, at fair value 1,276 Goodwill $ 378 For the year ended December 31, 2023, we incurred immaterial merger and integration-related costs which are included within Operating and maintenance expense in our Consolidated Statements of Operations and Comprehensive Income. The operating revenues and results of operations for STP have been included in the Consolidated Statements of Operations and Comprehensive Income from the date of acquisition and were not material for the year ended December 31, 2023. The pro forma effects of this acquisition are not significant to our reported results for any periods presented. Accordingly, no pro forma financial statements have been presented herein. On July 28, 2023 NRG accepted service of a lawsuit filed by the City of San Antonio, Texas, acting by and through CPS, in the 130th District Court of Matagorda County, Texas against NRG and certain of its subsidiaries, claiming the existence of a right of first refusal that applies to the transaction contemplated between us and NRG. On July 31, 2023 we intervened in the lawsuit and Austin Energy also intervened in the lawsuit claiming a similar right of first refusal. Per the terms of the Equity Purchase Agreement, NRG made representations that no right of first refusal applied to the transaction contemplated between us. Separately, on July 31, 2023, San Antonio and Austin filed motions to dismiss and (in the alternative) immediately stay proceedings and petitions to intervene on the application for June 12, 2023 license transfer application that was filed with the NRC. These motions and petitions remain pending before the NRC. Notwithstanding this, the NRC issued approval of the license transfer application on October 30, 2023. However, the NRC staff’s approval of the license transfer is subject to the Commission’s authority to rescind, modify, or condition the approved transfer based on the outcome of any post-effectiveness hearing or motions on the license transfer application. On February 20, 2024, we (along with San Antonio, Austin and NRG) jointly filed a motion to stay of the issuance of a decision by the NRC on the pending petition and motions. The motion requested that the NRC stay any decision so that the parties can attempt to finalize a settlement agreement that would result in the withdrawal of San Antonio’s pending petition and motions. The ongoing legal proceedings did not prohibit NRG and CEG from consummating the transaction, and Constellation is working with all parties to reach a resolution to the matter. We cannot reasonably predict the outcome of the lawsuit or NRC litigation; however, we do not expect it to have a material impact to our consolidated financial statements. CENG Put Option Prior to August 6, 2021, we owned a 50.01% membership interest in CENG, a joint venture with EDF, which wholly owned the Calvert Cliffs and Ginna nuclear stations and Nine Mile Point Unit 1, in addition to an 82% undivided ownership interest in Nine Mile Point Unit 2. CENG is 100% consolidated in our financial statements. On April 1, 2014, we entered into various agreements with EDF including a Nuclear Operating Services Agreement, an amended LLC Operating Agreement, an Employee Matters Agreement, and a Put Option Agreement, among others. Under the amended LLC Operating Agreement, CENG made a $400 million special distribution to EDF and committed to make preferred distributions to us until we had received aggregate distributions of $400 million plus a return of 8.50% per annum. Under the terms of the Put Option Agreement, EDF had the option to sell its 49.99% equity interest in CENG exercisable beginning on January 1, 2016 and thereafter until June 30, 2022. On November 20, 2019, we received notice of EDF’s intention to exercise the put option, and the put automatically exercised on January 19, 2020 at the end of the sixty-day advance notice period. The transaction required approval by FERC and the NYPSC, which approvals were received on July 30, 2020 and April 15, 2021, respectively. On August 6, 2021, we entered into a settlement agreement pursuant to which we purchased EDF's equity interest in CENG for a net purchase price of $885 million, which included, among other things, an adjustment for EDF's share of the outstanding balance of the preferred distribution payable to us by CENG. The difference between the net purchase price and EDF's noncontrolling interest as of August 6, 2021 was recorded to Membership interest in the Consolidated Balance Sheet. As a result of the transaction, we also recorded deferred tax liabilities of $288 million in Membership interest in the Consolidated Balance Sheet. See Note 14 — Income Taxes for additional information. The following table summarizes the effects of the changes in our ownership interest in CENG in Member's Equity: For the Year Ended December 31, 2021 Net loss attributable to membership interest $ (205) Pre-tax increase in membership interest for purchase of EDF's 49.99% equity interest (a) 1,080 Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest (a) (288) Change from net loss attributable to membership interest and transfers from noncontrolling interest $ 587 __________ (a) Represents non-cash activity in the consolidated financial statements. Agreement for Sale of Our Biomass Facility On April 28, 2021, we entered into a purchase agreement with ReGenerate Energy Holdings, LLC ("ReGenerate"), under which ReGenerate agreed to purchase our interest in the Albany Green Energy biomass facility. As a result, in the second quarter of 2021, we recorded a pre-tax impairment charge of $140 million in Operating and maintenance expense in the Consolidated Statement of Operations and Comprehensive Income. Completion of the transaction was subject to the satisfaction of various customary closing conditions that were satisfied in the second quarter of 2021. The sale was completed on June 30, 2021 for a net purchase price of $36 million. Agreement for Sale of Our Solar Business On December 8, 2020, we entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of our solar business, including 360 MWs of generation in operation or under construction across more than 600 sites across the United States. We retained certain solar assets not included in this agreement, primarily Antelope Valley. Completion of the transaction contemplated by the sale agreement was subject to the satisfaction of several closing conditions that were satisfied in the first quarter of 2021. The sale was completed on March 31, 2021 for a purchase price of $810 million. We received cash proceeds of $675 million, net of $125 million long-term debt assumed by the buyer and certain working capital and other post-closing adjustments. We recognized a pre-tax gain of $68 million which is included in Gain on sales of assets and businesses in the Consolidated Statement of Operations and Comprehensive Income. |
Regulatory Matters
Regulatory Matters | 12 Months Ended |
Dec. 31, 2023 | |
Regulated Operations [Abstract] | |
Regulatory Matters | Regulatory Matters The following matters below discuss the status of our material regulatory and legislative proceedings. PJM Performance Bonuses On December 23, 2022, and continuing through the morning of December 25, 2022, winter storm Elliott blanketed the entirety of PJM’s footprint with record low temperatures and extreme weather conditions. A significant portion of PJM's fossil generation fleet failed to perform as reserves were called. In accordance with PJM's tariff, funds collected from non-performance charges are redistributed as bonuses to generating resources that overperformed during the event, including our nuclear fleet. Complaints were filed at FERC by underperforming generators alleging, among other things, that PJM’s tariff is unjust and unreasonable, and that PJM violated its tariff or otherwise acted negligently in operating the system during that period, seeking to reduce or eliminate any penalty. In 2023, a proposed settlement was filed with FERC, and FERC subsequently approved the settlement as uncontested. We recognized $120 million and $109 million for bonuses (pre-tax), net of non-performance charges, in 2023 and 2022, respectively, associated with this event, primarily driven by the overperformance of our nuclear fleet. Remaining amounts on our balance sheet as of December 31, 2023 associated with this event are not material. New England Regulatory Matters Mystic Units 8 and 9 Cost of Service Agreement. On December 20, 2018, FERC issued an order accepting a cost of service agreement for Mystic Units 8 and 9 for the period between June 1, 2022 to May 31, 2024. The agreement is intended to preserve the two units for the two-year period while allowing the Mystic units to recover their costs of operating, including a substantial portion of the costs associated with the adjacent EMT we acquired in October 2018. In 2020, FERC issued several orders that, together, affirmed the recovery of key elements of Mystic's cost of service compensation, including recovery of costs associated with the operation of EMT. Several parties appealed the orders to the U.S. Court of Appeals for the D.C. Circuit. On August 23, 2022, the court issued its opinion and remanded several issues back to FERC, including the amount of the EMT’s fixed costs that can be recovered via the Mystic COS. On March 28, 2023, FERC issued an order on remand from the D.C. Circuit’s August 2022 decision (FERC Remand Order). Among other things, the FERC Remand Order affirmed that 91% of EMT’s fixed costs will be recovered via the Mystic COS, subject to the reinstatement of a margin sharing mechanism on forward sales of vapor. The Mystic COS requires an annual process whereby we identify and support our projected costs under the agreement and/or true-up previous projections to the actual costs incurred. The first annual process resulted in a filing at FERC on September 15, 2021 and included our projection of capital expenditures to be recovered under the Mystic COS between June 1, 2022 and December 31, 2022. On April 28, 2022, FERC issued an order setting for settlement and/or hearing the issue of whether our projected 2022 capital expenditures can be recovered. A settlement was filed at FERC in March 2023 and was approved by FERC on August 1, 2023. The settlement reduces the recovery we receive for capital projects over the term of the Mystic COS. The settlement also eliminates the potential that we would need to return EMT capital expenditures that were recovered via COS if EMT continues operating after the Mystic COS terminates. The approval of this offer of settlement does not have a material financial statement impact. On September 15, 2022, we made our second annual filing at FERC. On December 5, 2023, FERC issued an order setting for settlement/hearing certain components of the second annual filing, including the issue of Mystic’s recovery of historical rate base costs. We cannot reasonably predict the outcome of the settlement and/or hearing. See Note 7 — Early Plant Retirements and Note 12 — Asset Impairments for additional information on the impacts of our August 2020 decision to retire Mystic Units 8 and 9 upon expiration of the cost of service agreement. Federal Regulatory Matters Inflation Reduction Act of 2022. On August 16, 2022, President Biden signed into law the IRA, which, among other things, includes federal tax credits, certain of which are transferable or fully refundable, for a number of clean energy technologies including existing nuclear plants. The nuclear PTC recognizes the contributions of carbon-free nuclear power by providing a federal tax credit of up to $15/MWh, subject to phase-out, beginning in 2024 and continuing through 2032. The nuclear PTC includes adjustments for inflation. With the nuclear PTC policy support, we expect that many of our nuclear assets will operate through the end of the nuclear PTC period. Further, the IRA includes a 15% book-minimum tax on applicable corporations that we do not expect to have a material impact to our consolidated financial statements. The U.S. Department of Treasury has begun the process of issuing guidance on the relevant tax provisions included in the legislation but has not yet addressed the nuclear PTC. Operating License Renewals Conowingo Hydroelectric Project. In 2012, we submitted an application to FERC for a new license for the Conowingo Hydroelectric Project (Conowingo). In connection with our efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) from MDE for Conowingo, we had been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment. In 2019, we and MDE filed with FERC a Joint Offer of Settlement (Offer of Settlement) that would resolve all outstanding issues relating to the 401 Certification. FERC subsequently issued a new 50-year license for Conowingo, effective March 1, 2021. Several environmental groups appealed FERC’s ruling to the U.S. Court of Appeals for the D.C. Circuit. The court of appeals issued a decision vacating FERC’s decision to grant Conowingo its license renewal and sending the matter back to FERC for further proceedings. Upon issuance of the mandate from the U.S. Court of Appeals for the D.C. Circuit, we began operating under an annual license, which renews automatically, containing the same terms as the license that was in effect prior to the 2021 FERC order. MDE informed us that as a result of the U.S. Court of Appeals decision, they would be resuming their administrative reconsideration of the 401 Certification. In response to the procedure outlined by the MDE, supplemental briefs on the 401 Certification were filed by the Lower Susquehanna Riverkeeper Association and Waterkeepers Chesapeake (jointly) and us. In addition, we filed a supplemental reply brief. We are unable to further predict the outcome of this proceeding at this time. Depreciation provisions continue to assume operation through 2071 given our expectation that a 50-year license will be issued. Peach Bottom Units 2 and 3. On March 6, 2020, the NRC approved a second 20-year license renewal for Peach Bottom Units 2 and 3. As a result, Peach Bottom Units 2 and 3 were granted the authority to operate through 2053 and 2054, respectively. Notwithstanding its 2020 approval, on February 24, 2022, the NRC took action to modify Peach Bottom's subsequently renewed licenses in response to a request for hearing that the NRC had not previously adjudicated. In its February 2022 decision, the NRC reversed itself and concluded that the previous environmental review required by the National Environmental Policy Act (NEPA) for the Peach Bottom subsequently renewed licenses was incomplete because it did not adequately address environmental impacts resulting from renewing the units’ licenses for an additional 20 years. As a result, the NRC has undertaken a rulemaking to modify its regulations and guidance to specifically address environmental impacts during the period of subsequent license renewal. In addition, the NRC modified the expiration dates for the Peach Bottom licenses from 2053 and 2054 to 2033 and 2034, respectively, pending the completion of the updated NEPA analysis. We expect that the license expiration dates will be restored to 2053 and 2054, respectively, once the NRC's reevaluation of environmental impacts resulting from subsequent license renewal is complete. In September 2023, the NRC announced that its schedule to complete the rulemaking has delayed by several months and now intends to be complete by August 2024. This delay does not alter our expectation that the license expiration dates for Peach Bottom will be restored. Depreciation provisions and ARO assumed retirement dates continue to assume Peach Bottom Units 2 and 3 will operate through 2053 and 2054, respectively, given our expectation that the previously approved expiration dates will be restored. |
Revenue from Contracts with Cus
Revenue from Contracts with Customers | 12 Months Ended |
Dec. 31, 2023 | |
Revenue from Contract with Customer [Abstract] | |
Revenue from Contracts with Customers | Revenue from Contracts with Customers We recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that we expect to be entitled to in exchange for those goods or services. Our primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and sustainable solutions. The performance obligations, revenue recognition, and payment terms associated with these sources of revenue are further discussed in the table below. There are no significant financing components for these sources of revenue. Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, we have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, we generally recognize revenue in the amount for which we have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price. Revenue Source Description Performance Obligation Timing of Revenue Recognition Payment Terms Power Sales Sales of power and other energy-related commodities to wholesale and retail customers through our customer-facing business Various, including the delivery of power (generally delivered over time) and other energy-related commodities such as capacity (generally delivered over time), CMCs, ZECs, RECs or other ancillary services (generally delivered at a point in time) Concurrently as power is generated for bundled power sale contracts (a) Generally within the month following delivery to the customer Natural Gas Sales Sales of natural gas to wholesale and retail customers through our customer-facing business Various, including the delivery of natural gas (generally delivered overtime) and sustainable natural gas attributes (generally delivered at a point in time) Over time as the natural gas is delivered to the customer Generally within the month following delivery to the customer Other Products and Services Sales of other energy-related products and sustainable solutions such as long-term construction and installation of energy efficiency assets and new power generating facilities, primarily to C&I customers Construction and/or installation of the asset for the customer Revenues and associated costs are recognized throughout the contract term using an input method to measure progress towards completion (b) Generally within 30 or 45 days from the invoice date __________ (a) Certain contracts may contain limits on the total amount of revenue we are able to collect over the entire term of the contract. In such cases, we estimate the total consideration expected to be received over the term of the contract net of the constraint and allocate the expected consideration to the performance obligations in the contract such that revenue is recognized ratably over the term of the entire contract as the performance obligations are satisfied. (b) The method recognizes revenue based on the various inputs used to satisfy the performance obligation, such as costs incurred and total labor hours expended. The total amount of revenue that will be recognized is based on the agreed upon contractually-stated amount. The average contract term for these projects is approximately 18 months. We incur incremental costs in order to execute certain retail power and gas sales contracts. These costs, which primarily relate to retail broker fees and sales commissions, are capitalized when incurred as contract acquisition costs and generally amortized over the corresponding term of the contract. These capitalized costs and related amortization were not material as of and for the years ended December 31, 2023 and 2022. Contract Balances Contract Assets We record contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before we have an unconditional right to bill for and receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. We record contract assets and contract receivables in Other current assets and Customer accounts receivable, net, respectively, in the Consolidated Balance Sheets. The following table provides a rollforward of the contract assets reflected in the Consolidated Balance Sheets: 2023 2022 Beginning balance as of January 1 $ 130 $ 149 Amounts reclassified to receivables (127) (81) Revenues recognized 79 62 Ending balance as of December 31 $ 82 $ 130 Contract Liabilities We record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. We record contract liabilities in Other current liabilities and Other deferred credits and other liabilities in the Consolidated Balance Sheets. These contract liabilities primarily relate to upfront consideration received or due for equipment service plans, the Mystic COS, and the Illinois ZEC program. The Mystic COS includes upfront consideration received or due that differs from the recognized earnings over the cost of the service period. The Illinois ZEC program introduces an annual cap on the total consideration to be received by us for each delivery period. The ZEC price is established on a per MWh of production basis with a maximum annual cap for total compensation to be received for each planning year, while requiring delivery of all ZECs produced by our participating facilities during each delivery period. ZECs delivered to Illinois utilities in excess of the annual cost cap may be paid in subsequent years if the payments do not exceed the prescribed annual cost cap for that year. There were no outstanding contract liabilities for the Illinois ZEC program as of December 31, 2023, and were not material as of December 31, 2022. The following table provides a rollforward of the contract liabilities reflected in the Consolidated Balance Sheets: 2023 2022 2021 Beginning balance as of January 1 $ 47 $ 75 $ 84 Consideration received or due 331 339 251 Revenues recognized (338) (367) (263) Contract liabilities reclassified as held for sale — — 3 Ending balance as of December 31 $ 40 $ 47 $ 75 The following table reflects revenues recognized in the years ended December 31, 2023, 2022 and 2021, which were included in contract liabilities at December 31, 2022, 2021, and 2020, respectively: 2023 2022 2021 Revenues recognized $ 26 $ 71 $ 82 Transaction Price Allocated to Remaining Performance Obligations The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2023. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years. This disclosure excludes mark-to-market derivatives and certain power and gas sales contracts which contain variable volumes and/or variable pricing. 2024 2025 2026 2027 2028 and thereafter Total Remaining performance obligations $ 152 $ 44 $ 20 $ 18 $ 130 $ 364 Transaction Price Allocated to Previously Satisfied Performance Obligations Illinois ZEC Revenues Our Clinton and Quad Cities units contract with certain utilities in Illinois which requires delivery of all ZECs produced during each planning year (June 1 to May 31), with total compensation limited by an annual cap for each planning year designed to limit the cost of ZECs to each utility's customers. ZECs delivered that, if paid, would result in the annual cap being exceeded may be paid in subsequent years at the vintage year price as long as the payments would not exceed the annual cap in the year paid. In each planning year since the program commenced on June 1, 2017, we delivered ZECs to the utilities in excess of the annual compensation cap. The ZEC price and annual compensation cap effective for each planning year are administratively determined by the IPA. For the June 1, 2023 to May 31, 2024 planning year the ZEC price has been established at $0.30 per ZEC, subject to an annual cap of $224 million. ZECs generated and delivered during this planning year will not exceed the annual cap, providing capacity to compensate for ZECs delivered in prior planning years in excess of the compensation cap. In 2023, we recognized $218 million of revenue as a receivable for ZECs delivered in prior planning years, with payment expected in the third quarter of 2024. As of December 31, 2023, this receivable is included within Customer accounts receivable, net in the Consolidated Balance Sheets. PJM Performance Bonuses For the year ended December 31, 2023, we recognized a benefit of $120 million (pre-tax) for performance bonuses (net of non-performance charges), primarily driven by the overperformance of our nuclear fleet during the 2022 winter storm Elliott. See Note 3 — Regulatory Matters for additional information on the PJM performance bonuses. Revenue Disaggregation We disaggregate the revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 5 — Segment Information for the presentation of revenue disaggregation. |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2023 | |
Segment Reporting [Abstract] | |
Segment Information | Segment Information Operating segments are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources. We have five reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT, and all other power regions referred to collectively as “Other Power Regions.” The basis for our reportable segments is the integrated management of our electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Our hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of our five reportable segments are as follows: • Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia, and parts of Pennsylvania and North Carolina. • Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region. • New York represents operations within NYISO. • ERCOT represents operations within Electric Reliability Council of Texas that covers a majority of the state of Texas. • Other Power Regions: • New England represents operations within ISO-NE. • South represents operations in FRCC, MISO’s Southern Region, and the remaining portions of SERC not included within MISO or PJM. • West represents operations in WECC, which includes CAISO. • Canada represents operations across the entire country of Canada and includes AESO, OIESO, and the Canadian portion of MISO. The CODM evaluates the performance of our electric business activities and allocates resources based on Operating revenues net of Purchased power and fuel expense (RNF). We believe this is a useful measurement of operational performance, although it is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Our operating revenues include all sales to third parties and affiliate sales to Exelon's utility subsidiaries, prior to the separation on February 1, 2022. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy, and ancillary services. Fuel expense includes the fuel costs for our owned generation and fuel costs associated with tolling agreements. The results of our other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include wholesale and retail sales of natural gas, energy-related sales in the United Kingdom, as well as sales of other energy-related products and sustainable solutions that are not significant to our overall results of operations. Further, our unrealized mark-to-market gains and losses on economic hedging activities and our amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the regional reportable segment amounts. The CODM does not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments. The following tables disaggregate the revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. The disaggregation of revenues reflects our two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. The following tables also show the reconciliation of reportable segment revenues and RNF to our total revenues and RNF for the years ended December 31, 2023, 2022, and 2021. 2023 Revenues from external customers Contracts with customers Other (a) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 5,453 $ (265) $ 5,188 $ (50) $ 5,138 Midwest 4,846 (191) 4,655 3 4,658 New York 1,910 56 1,966 55 2,021 ERCOT 1,232 109 1,341 5 1,346 Other Power Regions 4,956 908 5,864 (13) 5,851 Total Reportable Segment Power Revenues 18,397 617 19,014 — 19,014 Total Natural Gas Revenues 1,859 1,866 3,725 — 3,725 Total Other Revenues (b) 585 1,594 2,179 — 2,179 Total Consolidated Operating Revenues $ 20,841 $ 4,077 $ 24,918 $ — $ 24,918 2022 Revenues from external customers (c) Contracts with customers Other (a) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 5,264 $ (105) $ 5,159 $ 5 $ 5,164 Midwest 5,164 (507) 4,657 (7) 4,650 New York 2,004 (408) 1,596 (1) 1,595 ERCOT 954 602 1,556 (13) 1,543 Other Power Regions 5,035 1,681 6,716 16 6,732 Total Reportable Segment Power Revenues 18,421 1,263 19,684 — 19,684 Total Natural Gas Revenues 2,559 2,408 4,967 — 4,967 Total Other Revenues (b) 591 (802) (211) — (211) Total Consolidated Operating Revenues $ 21,571 $ 2,869 $ 24,440 $ — $ 24,440 2021 Revenues from external customers (c) Contracts with customers Other (a) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 4,381 $ 183 $ 4,564 $ 20 $ 4,584 Midwest 4,265 (205) 4,060 — 4,060 New York 1,633 (57) 1,576 (1) 1,575 ERCOT 896 276 1,172 9 1,181 Other Power Regions 3,937 981 4,918 (28) 4,890 Total Reportable Segment Power Revenues 15,112 1,178 16,290 — 16,290 Total Natural Gas Revenues 1,777 1,602 3,379 — 3,379 Total Other Revenues (b) 365 (385) (20) — (20) Total Consolidated Operating Revenues $ 17,254 $ 2,395 $ 19,649 $ — $ 19,649 __________ (a) Includes revenues from derivatives and leases. (b) Represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $1,399 million and losses of $1,188 million, and $633 million for the years ended December 31, 2023, 2022, and 2021, respectively. (c) Includes all wholesale and retail electric sales to third parties and affiliated sales to Exelon's utility subsidiaries prior to the separation on February 1, 2022. See Note 24 — Related Party Transactions for additional information. 2023 2022 2021 RNF from external Intersegment Total RNF from external (b) Intersegment Total RNF from external (b) Intersegment Total Mid-Atlantic $ 2,972 $ (48) $ 2,924 $ 2,129 $ 9 $ 2,138 $ 2,247 $ 17 $ 2,264 Midwest 3,252 3 3,255 2,765 (1) 2,764 2,717 — 2,717 New York 1,189 62 1,251 1,061 6 1,067 1,151 10 1,161 ERCOT 588 (6) 582 503 (96) 407 (668) (157) (825) Other Power Regions 1,270 (30) 1,240 952 (31) 921 984 (93) 891 Total RNF for Reportable Segments 9,271 (19) 9,252 7,410 (113) 7,297 6,431 (223) 6,208 Other (a) (354) 19 (335) (432) 113 (319) 1,055 223 1,278 Total RNF $ 8,917 $ — $ 8,917 $ 6,978 $ — $ 6,978 $ 7,486 $ — $ 7,486 __________ (a) Other represents activities not allocated to a region. See text above for a description of included activities. Primarily includes: • Unrealized mark-to-market losses of $972 million and $1,013 million and gains of $565 million for the years ended December 31, 2023, 2022, and 2021, respectively; and • Accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 7 - Early Plant Retirements of $148 million for the year ended December 31, 2021. (b) Includes purchases and sales from/to third parties and affiliated sales to Exelon's utility subsidiaries prior to the separation on February 1, 2022. See Note 24 — Related Party Transactions for additional information. |
Accounts Receivable
Accounts Receivable | 12 Months Ended |
Dec. 31, 2023 | |
Receivables [Abstract] | |
Accounts Receivable | Accounts Receivable Unbilled Customer Revenue We recorded $372 million and $564 million of unbilled customer revenues in Customer accounts receivables, net in the Consolidated Balance Sheets as of December 31, 2023 and 2022, respectively. Sales of Customer Accounts Receivable On April 8, 2020, NER, a bankruptcy remote, special purpose entity, which is wholly owned by us, entered into a revolving accounts receivable financing arrangement with a number of financial institutions and a commercial paper conduit (Purchasers) to sell certain customer accounts receivable (Facility). On August 16, 2022, we entered into an amendment on the Facility, which increased the maximum funding limit of the Facility from $900 million to $1.1 billion and extended the term of the Facility through August 15, 2025, unless renewed by the mutual consent of the parties in accordance with its terms. Under the Facility, NER may sell eligible short-term customer accounts receivable to the Purchasers in exchange for cash and subordinated interest. The transfers are reported as sales of receivables in the consolidated financial statements. The subordinated interest in collections upon the receivables sold to the Purchasers is referred to as the DPP, which is reflected in Other current assets in the Consolidated Balance Sheets. The Facility requires the balance of eligible receivables to be maintained at or above the balance of cash proceeds received from the Purchasers. To the extent the eligible receivables decrease below such balance, we are required to repay cash to the Purchasers. When eligible receivables exceed cash proceeds, we have the ability to increase the cash received up to the maximum funding limit. These cash inflows and outflows impact the DPP. The following table summarizes the impact of the sale of certain receivables: As of December 31, 2023 2022 Derecognized receivables transferred at fair value $ 1,516 $ 1,615 Less: Cash proceeds received 300 1,100 DPP $ 1,216 $ 515 For the Years Ended December 31, 2023 2022 2021 Loss on sale of receivables (a) $ 75 $ 69 $ 36 _________ (a) Reflected in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. This represents the amount by which the accounts receivable sold into the Facility are discounted, limited to credit losses. For the Years Ended December 31, 2023 2022 2021 Proceeds from new transfers (a) $ 3,649 $ 6,108 $ 6,095 Cash collections received on DPP and reinvested in the Facility (b) 8,140 4,764 3,502 Cash collections reinvested in the Facility $ 11,789 $ 10,872 $ 9,597 _________ (a) Customer accounts receivable sold into the Facility were $11,746 million, $11,274 million, and $9,747 million for the years ended December 31, 2023, 2022, and 2021, respectively. (b) Does not include the $800 million net cash payments to the Purchasers in 2023, the $200 million net cash proceeds received from the Purchasers in 2022, or $400 million cash proceeds received from the Purchases in 2021. Our risk of loss following the transfer of accounts receivable is limited to the DPP outstanding. Payment of DPP is not subject to significant risks other than delinquencies and credit losses on accounts receivable transferred. We recognize the cash proceeds received upon sale in Cash flows from operating activities in the Consolidated Statements of Cash Flows. The collection and reinvestment of DPP is recognized in Cash flows from investing activities in the Consolidated Statements of Cash Flows. See Note 18 — Fair Value of Financial Assets and Liabilities and Note 22 — Variable Interest Entities for additional information. Other Sales of Customer Accounts Receivables We are required, under supplier tariffs, to sell customer receivables to utility companies. The following table presents the total receivables sold: For the Years Ended December 31, 2023 2022 2021 Total receivables sold $ 356 $ 423 $ 147 |
Early Plant Retirements
Early Plant Retirements | 12 Months Ended |
Dec. 31, 2023 | |
Implications of Potential Early Plant Retirements [Abstract] | |
Early Plant Retirements | Early Plant Retirements We continuously evaluate factors that affect the current and expected economic value of our plants, including, but not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions to ensure plants are fairly compensated for benefits they provide through their carbon-free emissions, reliability or fuel security, and the impact of potential rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. We remain committed to continued operations for our nuclear plants receiving state-supported payments under the Illinois CMC (Byron, Dresden, and Braidwood), Illinois ZES (Clinton and Quad Cities), New Jersey ZEC program (Salem), and the New York CES (FitzPatrick, Ginna, and Nine Mile Point), assuming the continued effectiveness of each program. While the current ZEC program in New York ends in 2029, the state has acknowledged our nuclear assets are vital to achieving its clean energy goals and we believe New York will continue to promote policies that support nuclear in the state beyond 2029. With the passage of the IRA, we expect that many of our nuclear assets will operate at least through the end of the nuclear PTC period, concluding at the end of 2032. To enable long term operations, we plan to file applications to extend the licenses of our nuclear fleet to 80 years for the units that receive continued support under federal or state policies or a combination of both. See Note 8 — Property, Plant, and Equipment for additional information on depreciable provisions of the stations, and Note 10 — Asset Retirement Obligations for additional information on ARO. Nuclear Generation On August 27, 2020, we announced our intention to permanently cease our operations at Byron in September 2021 and at Dresden in November 2021. On September 15, 2021, we announced that we had reversed our previous decision to retire Byron and Dresden given the opportunity for additional revenue under the Illinois Clean Energy Law. Our Byron, Dresden, and Braidwood nuclear plants were each awarded CMC contracts. In 2021, we reversed $81 million of severance benefit costs and $13 million of other one-time charges initially recorded in Operating and maintenance expense in 2020 associated with the early retirements. In addition, we updated the expected economic useful life for both facilities to 2044 and 2046, for Byron Units 1 and 2, respectively, and to 2029 and 2031 for Dresden Units 2 and 3, respectively, the end of the respective NRC operating license for each unit. Depreciation was therefore adjusted beginning September 15, 2021, to reflect these extended useful life estimates. See Note 10 — Asset Retirement Obligations for additional detail on changes to the nuclear decommissioning ARO balances resulting from the initial decision and subsequent reversal of the decision to early retire Byron and Dresden. The total impact for the year ended December 31, 2021 in the Consolidated Statements of Operations and Comprehensive Income resulting from the initial decision and subsequent reversal of the decision to early retire Byron and Dresden is summarized in the table below: Income statement expense (pre-tax) For the Year Ended December 31, 2021 Depreciation and amortization Accelerated depreciation (a) $ 1,805 Accelerated nuclear fuel amortization 148 Operating and maintenance One-time charges (94) Other charges 9 Contractual offset (b) (451) Total $ 1,417 _________ (a) Includes the accelerated depreciation of plant assets including any ARC. (b) Reflects contractual offset for ARO accretion, ARC depreciation, ARO remeasurement, and excludes any changes in earnings in the NDT funds. Decommissioning-related impacts were not offset for the Byron units starting in the second quarter of 2021 due to the inability to recognize a regulatory asset at ComEd. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. Based on the regulatory agreement with the ICC, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income as long as the net cumulative decommissioning-related activity result in a regulatory liability at ComEd. The offset resulted in an equal adjustment to the noncurrent payables to ComEd. See Note 10 - Asset Retirement Obligations for additional information. Other Generation |
Property, Plant, and Equipment
Property, Plant, and Equipment | 12 Months Ended |
Dec. 31, 2023 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant, and Equipment | Property, Plant, and Equipment The following table presents a summary of property, plant, and equipment by asset category as of December 31, 2023 and 2022: Asset Category December 31, 2023 December 31, 2022 Electric $ 32,889 $ 30,804 Nuclear fuel (a) 5,503 5,106 Construction work in progress 1,133 630 Other property, plant, and equipment 14 8 Total property, plant, and equipment 39,539 36,548 Less: accumulated depreciation (b) 17,423 16,726 Property, plant, and equipment, net $ 22,116 $ 19,822 __________ (a) Includes nuclear fuel that is in the fabrication and installation phase of $1,265 million and $937 million as of December 31, 2023 and 2022, respectively. (b) Includes accumulated amortization of nuclear fuel in the reactor core of $2,484 million and $2,657 million as of December 31, 2023 and 2022, respectively. The following table presents the average service life for each asset category in number of years: Asset Category Average Service Life (years) Electric 1-60 Nuclear fuel 1-8 Other property, plant, and equipment 1-10 Depreciation provisions are based on the estimated useful lives of the stations, which generally correspond with the term of the NRC operating licenses, except for Clinton, Dresden Units 2 and 3, Ginna, NMP Unit 1, Peach Bottom Units 2 and 3 and Conowingo. Depreciation provisions for Clinton, Dresden Units 2 and 3, Ginna, NMP Unit 1, and Peach Bottom Units 2 and 3 all assume an additional 20 years beyond current license expiration. Conowingo depreciation provisions are based on an estimated useful life through 2071, in anticipation that a 50-year license will be issued. See Note 3 — Regulatory Matters for additional information regarding license renewals for Peach Bottom and Conowingo. Beginning August 2020, Byron and Dresden depreciation provisions were based on their announced shutdown dates of September 2021, November 2021, and May 2024, respectively. On September 15, 2021, we updated the estimated useful lives for Byron and Dresden to reflect the end of the available NRC operating license for each unit. Beginning in the third quarter of 2022, we updated Dresden depreciation provisions consistent with the license renewal of 2029. See Note 3 — Regulatory Matters for additional information regarding license renewals for Peach Bottom and Conowingo. See Note 7 — Early Plant Retirements for additional information on the impacts related to Byron and Dresden. Annual depreciation rates for electric generation were 3.26%, 3.46%, and 8.67% for the years ended December 31, 2023, 2022, and 2021, respectively. Nuclear fuel amortization is charged to fuel expense using the unit-of-production method and not included in the annual depreciation rates. |
Jointly Owned Electric Plant
Jointly Owned Electric Plant | 12 Months Ended |
Dec. 31, 2023 | |
Public Utilities, Property, Plant and Equipment [Abstract] | |
Jointly Owned Electric Plant | Jointly Owned Electric Plant Our material undivided ownership interests in jointly owned nuclear plants as of December 31, 2023 and 2022 were as follows: Nuclear Generation Quad Cities Peach Salem Nine Mile Point Unit 2 South Texas Project Operator Constellation Constellation PSEG Nuclear Constellation STPNOC Ownership interest 75.00 % 50.00 % 42.59 % 82.00 % 44.00 % Our share as of December 31, 2023 Plant in service $ 1,263 $ 1,552 $ 781 $ 1,073 $ 1,089 Accumulated depreciation 805 689 357 292 5 Construction work in progress 8 14 49 35 13 Our share as of December 31, 2022 Plant in service $ 1,243 $ 1,534 $ 772 $ 1,063 $ — Accumulated depreciation 761 659 328 256 — Construction work in progress 7 12 23 26 — Our undivided ownership interests are financed with our funds and all operations are proportionately consolidated consistent with our ownership interest. Our share of direct expenses of the jointly owned plants are included in Purchased power and fuel and Operating and maintenance expenses in the Consolidated Statements of Operations and Comprehensive Income. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2023 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations Nuclear Decommissioning Asset Retirement Obligations We have a legal obligation to decommission our nuclear power plants following the permanent cessation of operations. To estimate our nuclear decommissioning obligations we use a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. We update our AROs annually, unless circumstances warrant more frequent updates, based on our review of updated cost studies and our annual evaluation of cost escalation factors and probabilities assigned to various scenarios. We began decommissioning the TMI nuclear plant upon permanently ceasing operations in 2019. See below for further discussion of the decommissioning of Zion Station. The financial statement impact for changes in the ARO, on an individual unit basis, due to the changes in and timing of estimated cash flows generally result in a corresponding change in the unit’s ARC in Property, plant, and equipment in the Consolidated Balance Sheets. If the ARO decreases for a Non-Regulatory Agreement unit without any remaining ARC, the corresponding change is recorded as a decrease in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income, whereas the corresponding decrease for Regulatory Agreement Units without any remaining ARC results in an increase to the Payables related to Regulatory Agreement Units in the Consolidated Balance Sheets. The following table provides a rollforward of the nuclear decommissioning AROs reflected in the Consolidated Balance Sheets from January 1, 2022 to December 31, 2023: 2023 2022 Beginning balance as of January 1 $ 12,500 $ 12,676 Net increase (decrease) due to changes in, and timing of, estimated future cash flows 411 (648) Accretion expense 582 532 Acquisition of joint ownership in STP (b) 429 — Costs incurred related to decommissioning plants (31) (60) Ending balance as of December 31 (a) $ 13,891 $ 12,500 __________ (a) Includes $30 million and $40 million as the current portion of the ARO as of December 31, 2023 and 2022, respectively, which is included in Other current liabilities in the Consolidated Balance Sheets. (b) Reflects our estimated share of the STP decommissioning obligation. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. The net $411 million increase in the ARO during 2023 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments, including the following: • An increase of approximately $610 million due to an increase in cost escalation rates, partially offset by an increase in discount rates. • Net increase of approximately $470 million due to updated cost assumptions for dry cask storage across the fleet and revised cost studies for Dresden, Limerick and Peach Bottom. • Net decrease of approximately $675 million due to changes in assumed retirement dates for Ginna, NMP Unit 1, and Salem. The 2023 ARO updates resulted in a decrease of $68 million in Operati ng and maintenance expense for the year ended December 31, 2023 in the Consolidated Statement of Operations and Comprehensive Income. The net $648 million decrease in the ARO during 2022 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, including the following: • Net decrease of approximately $790 million due to an increase in discount rates partly offset by an increase in cost escalation rates, primarily labor and energy. • A decrease of approximately $235 million due to changes in assumed retirement dates as a result of the passage of the IRA and useful life extension for Clinton and Dresden plants. See Note 3 - Regulatory Matters for additional information. • An increase of approximately $320 million due to revisions to the projected decommissioning schedule for our New York nuclear plants in connection with our separation from Exelon as discussed further below. • Net increase of approximately $75 million due to higher estimated decommissioning costs resulting from the completion of updated cost studies for our New York nuclear plants, Quad Cities, Calvert Cliffs, and Three Mile Island. The 2022 ARO updates resulted i n a decrease of $226 million in Operating and maintenance expense for the year ended December 31, 2022 in the Consolidated Statement of Operations and Comprehensive Income. NDT Funds NDT funds have been established for each of our nuclear units to satisfy our nuclear decommissioning obligations, as required by the NRC, and withdrawals from these funds for reasons other than to pay for decommissioning are restricted pursuant to NRC requirements until all decommissioning activities have been completed. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit. The NDT funds associated with our nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, through regulated rates for decommissioning the former PECO nuclear plants, and these collections are scheduled through the operating lives of these former PECO plants. The amounts collected from PECO customers are remitted to us and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 31, 2022, PECO filed its Nuclear Decommissioning Cost Adjustment with the PAPUC proposing an annual recovery from customers of approximately $4 million. On August 19, 2022, the PAPUC approved the filing, and the new rates became effective January 1, 2023. Additionally, for the newly acquired STP units, we maintain decommissioning trust funds for those units proportionate to our 44% ownership. We also retain the authority through the PUCT to obtain additional decommissioning funding through CenterPoint Energy Houston Electric, LLC and AEP Texas, Inc. Any shortfall of funds necessary for decommissioning, determined for each generating station unit, are generally required to be funded by us, with the exception of STP and the former PECO nuclear plants. We have recourse to collect additional amounts from the respective utility customers through the utility commissions for the former PECO units and STP in the event of a shortfall of NDT funds. Collection of additional amounts for the former PECO units are subject to certain limitations and thresholds, as prescribed by an order from the PAPUC that limits collection of amounts associated with the first $50 million of any shortfall of trust funds compared to decommissioning costs, as well as 5% of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $50 million and up to 5% of any additional shortfalls would be borne by us. Aside from the former PECO units and STP, no recourse exists to collect additional amounts from utility customers for any of our other nuclear units. With respect to the Regulatory Agreement Units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to the respective utility customers, subject to certain limitations that allow sharing of excess funds with us related to the former PECO units. With respect to our other nuclear units, we retain any funds remaining after decommissioning. However, in connection with CENG's acquisition of the Nine Mile Point and Ginna plants and settlements with certain regulatory agencies, certain conditions pertaining to NDT funds apply that, if met, could possibly result in obligations to make payments to certain third parties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event that the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for Nine Mile Point, then, depending upon the triggering event, an amount equal to 50% of the total amount withdrawn from the funds for non-decommissioning activities as defined in the agreement or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including SNF management and site restoration) is to be paid to the Nine Mile Point sellers. In the event that the clawback provisions are triggered for Ginna, then an amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers. We expect to comply with applicable regulations and timely commence and complete all required decommissioning activities. We had NDT funds totali ng $16,398 million and $14,127 million as of December 31, 2023 and 2022, respectively. As of December 31, 2023, there was no current portion of t he NDT funds. $13 million of the NDT funds were current as of December 31, 2022, and included in Other current assets in the Consolidated Balance Sheets. See Note 23 — Supplemental Financial Information for additional information on activities of the NDT funds. Accounting Implications of the Regulatory Agreement Units See Note 1 — Basis of Presentation for additional information on the accounting policy for Regulatory Agreement Units. For the former PECO units and STP, given the symmetric settlement provisions that allow for continued recovery of decommissioning costs from the respective utility customers in the event of a shortfall and the obligation for us to ultimately return excess funds to the respective utility customers (on an aggregate basis for all seven former PECO units and on the underlying utility customer basis for STP) decommissioning-related activities are generally offset in the Consolidated Statements of Operations and Comprehensive Income regardless of whether the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation. The offset of decommissioning-related activities in the Consolidated Statements of Operations and Comprehensive Income results in an equal adjustment to noncurrent payables or noncurrent receivables. Any changes to the existing PECO or STP regulatory agreements could impact our ability to offset decommissioning-related activities in the Consolidated Statements of Operations and Comprehensive Income, and the potential impact to our consolidated financial statements could be material. For the former ComEd units, given no further recovery from ComEd customers is permitted and we retain an obligation to ultimately return any unused NDTs to ComEd customers (on a unit-by-unit basis), to the extent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for each unit, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income which results in us recognizing a noncurrent payable. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a receivable related to former ComEd Units is not permissible and accounting for decommissioning-related activities for that unit would not be offset, and the impact to the Consolidated Statements of Operations and Comprehensive Income could be material during such periods. For the year ended December 31, 2021, a pre-tax charge of $193 million was recorded in the Consolidated Statement of Operations and Comprehensive Income for decommissioning-related activities that were not offset for the Byron units due to contractual offset being temporarily suspended. With our September 15, 2021 reversal of the previous decision to retire Byron and the corresponding adjustment to the ARO for Byron discussed previously, we resumed contractual offset for Byron as of that date. The following table presents our noncurrent payables to ComEd and PECO, as well as CenterPoint Energy Houston Electric, LLC and AEP Texas, Inc. for STP, which are recorded as Payables related to Regulatory Agreement Units in the Consolidated Balance Sheets as of December 31, 2023 and 2022: As of December 31, 2023 2022 ComEd $ 2,955 $ 2,660 PECO 278 237 CenterPoint Energy Houston Electric, LLC 338 — AEP Texas, Inc. 117 — Payables related to Regulatory Agreement Units $ 3,688 $ 2,897 As of December 31, 2023, decommissioning-related activities for all of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are currently offset in the Consolidated Statements of Operations and Comprehensive Income. The decommissioning-related activities for the Non-Regulatory Agreement Units are reflected in the Consolidated Statements of Operations and Comprehensive Income within Operating and maintenance expense, Depreciation and amortization expense, and in Other, net. Zion Station Decommissioning In 2010, we completed an ASA under which ZionSolutions assumed responsibility for decommissioning Zion Station and we transferred to ZionSolutions substantially all the Zion Station’s assets, including the related NDT funds. On November 16, 2023, ZionSolutions completed its contractual obligations and transferred the NRC license back to us. We will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal and complete all remaining decommissioning activities associated with the SNF dry storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by us. As of December 31, 2023 and 2022, the ARO associated with Zion's SNF storage facility is $139 million and $138 million, respectively, and the NDT funds available to fund this obligation are $62 million and $58 million, respectively. NRC Minimum Funding Requirements NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. The estimated decommissioning obligations are calculated using an NRC methodology that is different from the ARO recorded in the Consolidated Balance Sheets primarily due to differences in the type of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements for radiological decommissioning calculated under the NRC methodology are greater than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires resolution of the shortfalls which could include further funding or other financial guarantees. Key assumptions used in the minimum funding calculation for radiological decommissioning costs using the NRC methodology at December 31, 2023 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the former PECO units, as specified by the PAPUC). In contrast, the key criteria and assumptions used by us to determine the ARO and to forecast the target growth in the NDT funds as of December 31, 2023 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site SNF maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain LLRW); (3) as applicable, the consideration of multiple scenarios where decommissioning and site restoration activities, as applicable, are completed under possible scenarios ranging from 10 to 70 years after the cessation of plant operations or the end of the current licensed operating life; (4) the consideration of multiple end of life scenarios; (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 4% through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 6.1% to 7.1% (as compared to a historical 5-year annual average pre-tax return of approximately 8.0% ). We are required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of license expiration), based on values as of December 31, addressing our ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, we may be required to take steps, such as providing financial guarantees through surety bonds, letters of credit, or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, our cash flows and financial position may be significantly adversely affected. We filed our biennial decommissioning funding status report with the NRC on March 23, 2023 for all units, including our shutdown units, except for Zion Station which was included in a separate report to the NRC submitted by ZionSolutions, LLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2022 for all units except for Peach Bottom Unit 1. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund, collections from PECO customers, and the ability to adjust those collections in accordance with the approved PAPUC tariff. See NDT Funds section above for additional information. Additionally, the STP units demonstrated adequate decommissioning funding assurance as of December 31, 2022 in the decommissioning funding status report filed with the NRC by STPNOC on March 29, 2023. We will file the next decommissioning funding status report with the NRC by March 31, 2024. This report will reflect the status of decommissioning funding as of December 31, 2023 for shutdown units, including Zion, and any units within five years of license expiration. We expect the funding status report to demonstrate adequate funding assurance for all units except for Peach Bottom Unit 1. Financial assurance for decommissioning Peach Bottom Unit 1 is provided by the collections from PECO customers as mentioned above. Additionally, the decommissioning funding status report for STP following our November 1, 2023 acquisition of a 44% interest will be filed by STPNOC in March 2024. The status report will demonstrate adequate funding assurance as of December 31, 2023. As the future values of trust funds change due to market conditions, the NRC minimum funding status of our units will change. In addition, if changes occur to the regulatory agreements with the PAPUC or the PUCT that currently allow amounts to be collected from utility customers for decommissioning the former PECO and STP units, the NRC minimum funding status of those plants could change at subsequent NRC filing dates. Impact of Separation from Exelon Satisfying a condition precedent, on December 16, 2021, the NYPSC authorized our separation from Exelon and accepted the terms of a Joint Proposal that became binding upon closing of the separation on February 1, 2022. As part of the Joint Proposal, among other items, we have projected completion of radiological decommissioning and site restoration activities necessary to achieve a partial site release from the NRC (release of the site for unrestricted use, except for any on-site dry cask storage) within 20 years from the end of licensed life for each of our Ginna and FitzPatrick units and from the end of licensed life for the last of the NMP operating units. While there is flexibility under the Joint Proposal, there was an increase to the AROs, as noted above, associated with our New York nuclear plants during the first quarter of 2022. The Joint Proposal also required a contribution of $15 million to the NDT for NMP Unit 2 in January 2022 and requires various financial assurance mechanisms through the duration of decommissioning and site restoration, including a minimum NDT balance for each unit, adjusted for specific stages of decommissioning, and a parent guaranty for site restoration costs updated annually as site restoration progresses, which must be replaced with a third-party surety bond or equivalent financial instrument in the event we were to fall below investment grade. See Note 1 — Basis of Presentation for additional information on the separation. Non-Nuclear Asset Retirement Obligations We have AROs for plant closure costs associated with our natural gas, oil, and renewable generating facilities, including asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations, and other decommissioning-related activities. See Note 1 — Basis of Presentation for additional information on the accounting policy for AROs. The following table provides a rollforward of the non-nuclear AROs reflected in the Consolidated Balance Sheets from January 1, 2022 to December 31, 2023: 2023 2022 Beginning balance as of January 1 $ 239 $ 216 Net increase due to changes in, and timing of, estimated future cash flows 14 18 Accretion expense 14 11 Asset divestitures (9) (1) Payments (1) (5) Ending balance as of December 31 $ 257 $ 239 . |
Leases
Leases | 12 Months Ended |
Dec. 31, 2023 | |
Leases [Abstract] | |
Leases | Leases Lessee We have operating leases for which we are the lessee. The significant types of leases are contracted generation, real estate, and vehicles and equipment. The following table outlines other terms and conditions of the lease agreements as of December 31, 2023. We did not have material finance leases in 2023, 2022, or 2021. In Years Remaining lease terms 1-32 Options to extend the term 2-30 Options to terminate within 1 The components of operating lease costs were as follows: For the Years Ended December 31, 2023 2022 2021 Operating lease costs $ 96 $ 109 $ 161 Variable lease costs 146 169 168 Total lease costs (a) $ 242 $ 278 $ 329 __________ (a) Excludes $50 million, $49 million, $44 million of sublease income recorded for each of the years ended December 31, 2023, 2022, and 2021, respectively. The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities in the Consolidated Balance Sheets: As of December 31, 2023 2022 Operating lease ROU assets (a) Other deferred debits and other assets $ 494 $ 545 Operating lease liabilities (a) Other current liabilities 67 67 Other deferred credits and other liabilities 583 643 Total operating lease liabilities $ 650 $ 710 __________ (a) The operating ROU assets and lease liabilities include $212 million and $334 million, respectively, related to contracted generation as of December 31, 2023, and $248 million and $377 million, respectively, as of December 31, 2022. The weighted average remaining lease terms, in years, and the weighted average discount rates for operating leases were as follows: As of December 31, 2023 2022 2021 Weighted average remaining lease term 8.4 9.3 10.1 Weighted average discount rate 5.0 % 5.0 % 5.0 % The following table reconciles the undiscounted cash flows for our operating leases to the operating lease liabilities recorded on our consolidated balance sheet as of December 31, 2023: 2024 $ 101 2025 104 2026 104 2027 102 2028 103 Thereafter 325 Total lease payments 839 Less: Imputed interest 189 Operating lease liabilities $ 650 Supplemental cash flow information related to operating leases was as follows: For the Years Ended December 31, 2023 2022 2021 Cash paid for amounts included in the measurement of operating lease liabilities $ 102 $ 114 $ 162 ROU assets obtained in exchange for operating lease obligations 13 14 2 Lessor We have operating leases for which we are the lessor. The significant types of leases are contracted generation and real estate. The following table outlines other terms and conditions of the lease agreements as of December 31, 2023. In Years Remaining lease terms 1-17 Options to extend the term 1-20 The components of lease income were as follows: For the Years Ended December 31, 2023 2022 2021 Operating lease income $ 51 $ 51 $ 47 Variable lease income 248 258 261 The following table presents maturity analysis of the lease payments we expect to receive as of December 31, 2023: 2024 $ 48 2025 48 2026 49 2027 49 2028 48 Thereafter 85 Total $ 327 |
Leases | Leases Lessee We have operating leases for which we are the lessee. The significant types of leases are contracted generation, real estate, and vehicles and equipment. The following table outlines other terms and conditions of the lease agreements as of December 31, 2023. We did not have material finance leases in 2023, 2022, or 2021. In Years Remaining lease terms 1-32 Options to extend the term 2-30 Options to terminate within 1 The components of operating lease costs were as follows: For the Years Ended December 31, 2023 2022 2021 Operating lease costs $ 96 $ 109 $ 161 Variable lease costs 146 169 168 Total lease costs (a) $ 242 $ 278 $ 329 __________ (a) Excludes $50 million, $49 million, $44 million of sublease income recorded for each of the years ended December 31, 2023, 2022, and 2021, respectively. The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities in the Consolidated Balance Sheets: As of December 31, 2023 2022 Operating lease ROU assets (a) Other deferred debits and other assets $ 494 $ 545 Operating lease liabilities (a) Other current liabilities 67 67 Other deferred credits and other liabilities 583 643 Total operating lease liabilities $ 650 $ 710 __________ (a) The operating ROU assets and lease liabilities include $212 million and $334 million, respectively, related to contracted generation as of December 31, 2023, and $248 million and $377 million, respectively, as of December 31, 2022. The weighted average remaining lease terms, in years, and the weighted average discount rates for operating leases were as follows: As of December 31, 2023 2022 2021 Weighted average remaining lease term 8.4 9.3 10.1 Weighted average discount rate 5.0 % 5.0 % 5.0 % The following table reconciles the undiscounted cash flows for our operating leases to the operating lease liabilities recorded on our consolidated balance sheet as of December 31, 2023: 2024 $ 101 2025 104 2026 104 2027 102 2028 103 Thereafter 325 Total lease payments 839 Less: Imputed interest 189 Operating lease liabilities $ 650 Supplemental cash flow information related to operating leases was as follows: For the Years Ended December 31, 2023 2022 2021 Cash paid for amounts included in the measurement of operating lease liabilities $ 102 $ 114 $ 162 ROU assets obtained in exchange for operating lease obligations 13 14 2 Lessor We have operating leases for which we are the lessor. The significant types of leases are contracted generation and real estate. The following table outlines other terms and conditions of the lease agreements as of December 31, 2023. In Years Remaining lease terms 1-17 Options to extend the term 1-20 The components of lease income were as follows: For the Years Ended December 31, 2023 2022 2021 Operating lease income $ 51 $ 51 $ 47 Variable lease income 248 258 261 The following table presents maturity analysis of the lease payments we expect to receive as of December 31, 2023: 2024 $ 48 2025 48 2026 49 2027 49 2028 48 Thereafter 85 Total $ 327 |
Asset Impairments
Asset Impairments | 12 Months Ended |
Dec. 31, 2023 | |
Impairment or Disposal of Tangible Assets Disclosure [Abstract] | |
Asset Impairments | Asset Impairments We evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. We determine if long-lived assets or asset groups are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value analysis is primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments of our long-lived assets. Generally, pre-tax impairment losses on long-lived assets or asset groups are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. New England Asset Group In the second quarter of 2021, an overall decline in the asset group's portfolio value suggested that the carrying value of the New England asset group may be impaired. We completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and concluded that the carrying value was not recoverable and that its fair value was less than its carrying value. As a result, a pre-tax impairment charge of $350 million was recorded in the second quarter of 2021 in Operating and maintenance expense |
Intangible Assets
Intangible Assets | 12 Months Ended |
Dec. 31, 2023 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Intangible Assets | Intangible Assets Goodwill The following table presents the carrying amount of goodwill as of December 31, 2023 and 2022. There were no impairment losses during the years ended December 31, 2023, 2022, and 2021 . Goodwill Balance at December 31, 2022 $ 47 Goodwill resulting from acquisition of STP (a) 378 Balance at December 31, 2023 $ 425 __________ (a) See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. See Note 1 — Basis of Presentation for our policy regarding goodwill. Our operating segments are also considered reporting units for goodwill impairment assessment purposes. The goodwill recognized in 2023 has been assigned entirely to the ERCOT operating segment. Other Intangible Assets and Liabilities Our other intangible assets and liabilities, included in Other current assets, Other deferred debits and other assets, Other current liabilities, Other deferred credits and other liabilities in the Consolidated Balance Sheets, consisted of the following as of December 31, 2023 and 2022. The intangible assets and liabilities shown below are generally amortized on a straight line basis, except for unamortized energy contracts which are amortized in relation to the expected realization of the underlying cash flows: December 31, 2023 December 31, 2022 Gross Accumulated Amortization Net Gross Accumulated Amortization Net Unamortized Energy Contracts $ 1,892 $ (1,631) $ 261 $ 1,960 $ (1,708) $ 252 Customer Relationships 242 (167) 75 356 (265) 91 Total $ 2,134 $ (1,798) $ 336 $ 2,316 $ (1,973) $ 343 The following table summarizes the amortization expense related to our other intangible assets and liabilities for each of the years ended December 31, 2023, 2022, and 2021: For the Years Ended December 31, Amortization Expense (a) 2023 $ 58 2022 61 2021 80 __________ (a) See Note 23 — Supplemental Financial Information for additional information related to the amortization of unamortized energy contracts. The following table summarizes the estimated future amortization expense related to our other intangible assets and liabilities as of December 31, 2023: For the Years Ending December 31, Estimated Future Amortization Expense 2024 $ 62 2025 58 2026 51 2027 37 2028 31 2029 and thereafter 97 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes Components of Income Tax Expense or Benefit Income taxes are comprised of the following components: For the Years Ended December 31, 2023 2022 2021 Federal Current $ 464 $ 219 $ 394 Deferred 301 (655) (153) ITC amortization (15) (15) (15) State Current 142 34 36 Deferred (33) 29 (37) Total income tax (benefit) expense $ 859 $ (388) $ 225 Rate Reconciliation The effective income tax rate varies from the U.S. federal statutory rate principally due to the following: For the Years Ended December 31, 2023 (a) 2022 (b) 2021 (a) U.S. federal statutory rate 21.0 % 21.0 % 21.0 % (Decrease) increase due to: State income taxes, net of federal income tax benefit (c) 3.5 (9.2) — Qualified NDT fund income and losses 10.3 46.3 165.1 Amortization of investment tax credit, including deferred taxes on basis differences (0.5) 2.2 (9.0) Production tax credits and other credits (0.6) 7.7 (28.7) Noncontrolling interests 0.4 (0.3) (3.0) Other (d) 1.0 3.9 2.6 Effective income tax rate (e) 35.1 % 71.6 % 148.0 % _________ (a) Positive percentages represent income tax expense. Negative percentages represent income tax benefit. (b) As there was a pre-tax loss during 2022, negative percentages represent income tax expense. Positive percentages represent income tax benefit. (c) Includes ($4) million and $30 million related to state rate changes and certain state tax positions in 2023 and 2022, respectively. (d) Primarily related to disallowed excess officer compensation in 2023 and $32 million prior period income tax adjustment recorded in 2022. (e) The change in effective tax rate in 2023 is primarily due to the impacts of higher realized NDT Income and significant pretax income in 2023 compared to pretax loss in 2022. Tax Differences and Carryforwards The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2023 and 2022 are presented below: December 31, 2023 December 31, 2022 Plant basis differences $ (3,130) $ (3,005) Accrual-based contracts (32) (35) Derivatives and other financial instruments 984 43 Deferred pension and postretirement obligation (314) 287 Nuclear decommissioning activities (640) (371) Tax loss carryforward, net of valuation allowances 47 67 Tax credit carryforward — 179 Investment in partnerships (193) (205) Other, net 460 407 Deferred income tax liabilities (net) (2,818) (2,633) Unamortized ITCs (339) (354) Total deferred income tax liabilities (net) and $ (3,157) $ (2,987) The following table provides our carryforwards, of which the state-related items are presented on a post-apportioned basis, and any corresponding valuation allowances as of December 31, 2023: Federal December 31, 2023 Federal general business credits carryforwards and other carryforwards $ — Year in which net operating loss or credit carryforwards will begin to expire 2043 State State net operating losses and other carryforwards 477 Deferred taxes on state tax attributes (net) 21 Valuation allowance on state tax attributes (10) Foreign Foreign net operating losses and other carryforwards 145 Deferred taxes on foreign tax attributes (net) 36 Unrecognized Tax Benefits Our unrecognized tax benefits were not material as of and for the 12 months ended December 31, 2023, 2022, and 2021, and if recognized, would not significantly impact our effective tax rate. Further, these amounts are not expected to significantly increase or decrease within the next 12 months. Total amounts of interest and penalties recognized We did not record material interest and penalty expense related to tax positions reflected in the Consolidated Balance Sheets. Interest expense and penalty expense are recorded in Interest expense, net and Other, net, respectively, in Other income and deductions in the Consolidated Statements of Operations and Comprehensive Income. Description of tax years open to assessment by major jurisdiction Major Jurisdiction Open Years (a) Federal consolidated income tax returns 2010-2022 Illinois unitary corporate income tax returns 2012-2022 New Jersey separate corporate income tax returns 2017-2018 New Jersey combined corporate income tax returns 2019-2022 New York combined corporate income tax returns 2015-2022 Pennsylvania separate corporate income tax returns 2020-2022 __________ (a) Tax years open to assessment include years when we were consolidated by Exelon. See discussion below under the Tax Matters Agreement for responsibility of taxes of these open years. Other Tax Matters Allocation of Tax Benefits Prior to separation, we were a party to an agreement with Exelon and other subsidiaries of Exelon that provided for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provided that each party was allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net federal and state benefits attributable to Exelon were reallocated to the parties. That allocation was treated as a contribution from Exelon to the party receiving the benefit. The allocation of tax benefits from Exelon to us under the Tax Sharing Agreement at December 31, 2021 was $64 million. Tax Matters Agreement In connection with the separation, we entered into a Tax Matters Agreement (TMA) with Exelon. The TMA governs the respective rights, responsibilities, and obligations between us and Exelon after the separation with respect to tax liabilities and benefits, tax attributes, tax returns, tax contests and other tax sharing regarding U.S. federal, state, local and foreign income taxes, other tax matters and related tax returns. Responsibility and Indemnification for Taxes . As a former subsidiary of Exelon, we have joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods that we were included in federal and state filings. However, the TMA specifies the portion of this tax liability for which we will bear contractual responsibility, and we and Exelon agreed to indemnify each other against any amounts for which such indemnified party is not responsible. Specifically, we will be liable for taxes due and payable in connection with tax returns that we are required to file. We will also be liable for our share of certain taxes required to be paid by Exelon with respect to taxable years or periods (or portions thereof) ending on or prior to the separation to the extent that we would have been responsible for such taxes under the Exelon tax sharing agreement then existing. As such, our Consolidated Balance Sheets at separation reflected a payable of $103 million for tax liabilities where we maintain contractual responsibility to Exelon, with $53 million recognized in Accounts payable and accrued expenses and $50 million in Noncurrent other liabilities. As of December 31, 2023 and 2022, respectively, we had $11 million and $18 million in Other accounts receivable, no payables in Accounts payable and accrued expenses and $37 million and $50 million in Noncurrent other liabilities. Tax Refunds and Attributes . The TMA provides for the allocation of certain pre-closing tax attributes between us and Exelon. Tax attributes will be allocated in accordance with the principles set forth in the existing Exelon tax sharing agreement, unless otherwise required by law. Under the TMA, we will be entitled to refunds for taxes for which we are responsible. In addition, it is expected that Exelon will have tax attributes that may be used to offset Exelon’s future tax liabilities. A significant portion of such attributes were generated by our business. Upon separation, we reclassified $508 million from Deferred income taxes to reflect receivables of $11 million and $497 million in Other accounts receivable and Other deferred debits and other assets, respectively, in the Consolidated Balance Sheets for the tax attributes expected to be utilized by Exelon after separation in accordance with the terms of the TMA. As of December 31, 2023 and 2022, respectively, we had $336 million and $168 million in Other accounts receivable and $178 million and $362 million in Other deferred debits and other assets for the reclassified tax attributes. |
Retirement Benefits
Retirement Benefits | 12 Months Ended |
Dec. 31, 2023 | |
Retirement Benefits [Abstract] | |
Retirement Benefits | Retirement Benefits Defined Benefit Pension and OPEB The majority of current employees participate in the defined benefit pension and OPEB plans that we sponsor. As the plan sponsor, our Consolidated Balance Sheets reflect underfunded pension and OPEB liabilities equal to an excess of either the PBO or APBO over the fair value of the plan assets, consistent with a single employer benefit plan. Newly hired employees are generally not eligible for either pension or OPEB benefits; instead, these employees are eligible to receive an enhanced non-discretionary fixed employer contribution under our sponsored defined contribution savings plan. Effective February 1, 2022, in connection with the separation, pension and OPEB obligations and the related plan assets for participants (inclusive of employees and certain former employees and their beneficiaries assigned to us from Exelon upon separation) were transferred to pension and OPEB plans established by us as the plan sponsor. We no longer account for our interest in Exelon sponsored pension and OPEB plans under the multi-employer benefit plan guidance as we are no longer participants. That previous approach historically resulted in the recognition of a net prepaid pension asset in our Consolidated Balance Sheets representing an excess of contributions over cumulative costs. Benefit Obligations, Plan Assets, and Funded Status As of February 1, 2022, we assumed from Exelon the PBO, APBO, and plan assets for our plan participants in connection with the separation. The defined benefit pension and OPEB plans were remeasured to determine the obligations and related plan assets to be transferred to us as of that date. The pension assets allocated to us were based on the rules prescribed by ERISA for transfers of assets in connection with a pension plan separation. A portion of the Exelon OPEB plan assets, which are held in VEBA trusts, were also allocated to us separately for each funding vehicle based on the ratio of the APBO assumed by us to the total APBO attributed to each funding vehicle. The remeasurement completed at separation is reflected in the table below as a separation-related adjustment and resulted in the recognition of pension obligations of $953 million, net of pension plan assets of $8,267 million, and OPEB obligations of $876 million, net of OPEB plan assets of $904 million. Additionally, we recognized $2,006 million (after-tax) in Accumulated other comprehensive loss for actuarial losses and prior service costs that had accrued over the lives of the plans prior to separation, primarily based on our proportionate share of the total projected pension and OPEB obligations at Exelon prior to separation. In connection with the acquisition of STP in the fourth quarter of 2023, Constellation recorded pension and OPEB obligations, net of plan assets, reflected in the tables below as an acquisition-related adjustment of $17 million and $14 million, respectively. Refer to Note 2 - Mergers, Acquisitions and Dispositions for additional discussion of the acquisition of STP. We use a December 31 measurement date for our pension and OPEB obligations and the related plan assets. The actuarial losses experienced upon remeasurement as of December 31, 2023 were offset against AOCI and attributable to decreases in the discount rates used to measure the benefit obligations net of actual investment performance that was less than expected. See the table below for the actuarial loss associated with the pension valuation. The following tables provide a rollforward of the changes in the benefit obligations and plan assets for the years ended December 31, 2023 and 2022 for all plans combined: Pension Benefits OPEB 2023 2022 2023 2022 Change in benefit obligation: Benefit obligation as of the beginning of the year $ 7,275 $ — $ 1,360 $ 847 Separation-related adjustment — 9,220 — 933 Benefit obligation as of February 1, 2022 — 9,220 — 1,780 Service cost 89 115 16 23 Interest cost 394 269 74 52 Plan participants' contributions — — 23 20 Actuarial loss/(gain), net 368 (1,756) 99 (401) Acquisition-related adjustment (a) 187 — 14 — Settlements — (15) — — Gross benefits paid (543) (558) (143) (114) Benefit obligation as of the end of year $ 7,770 $ 7,275 $ 1,443 $ 1,360 __________ (a) Pension and OPEB adjustment related to the acquisition of STP in 2023. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. Pension Benefits OPEB 2023 2022 2023 2022 Change in plan assets: Plan assets as of the beginning of year (a) $ 6,660 $ 1,683 $ 734 $ — Separation-related adjustment — 6,584 — 904 Fair value of plan assets as of February 1, 2022 — 8,267 — 904 Actual return (loss) on plan assets 374 (1,245) 50 (99) Employer contributions 26 211 — — Plan participants' contributions — — 18 15 Gross benefits paid (543) (558) (110) (86) Acquisition-related adjustment (b) 170 — — — Settlements — (15) — — Fair value of plan assets as of the end of year $ 6,687 $ 6,660 $ 692 $ 734 Over (under) funded status (Plan assets less benefit obligations) $ (1,083) $ (615) $ (751) $ (626) __________ (a) The balance on January 1, 2022 was reflected as a prepaid pension asset. (b) Pension and OPEB adjustment related to the acquisition of STP in 2023. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. We present our benefit obligations net of plan assets on our Consolidated Balance Sheets within the following line items: Pension Benefits OPEB 2023 2022 2023 2022 Other current liabilities $ (13) $ (10) $ (19) $ (17) Pension obligations (1,070) (605) — — Non-pension postretirement benefit — — (732) (609) The following table provides the ABO and fair value of plan assets for all pension plans with an ABO in excess of plan assets. ABO in Excess of Plan Assets December 31, 2023 December 31, 2022 ABO $ (7,567) $ (7,121) Fair value of net plan assets 6,687 6,660 Components of Net Periodic Benefit (Credits) Costs See Note 1 — Basis of Presentation for additional information on where we report the service cost and other non-service cost (credit) components for all plans. The following table presents the components of our net periodic benefit (credits) costs, prior to capitalization and co-owner allocations, for the years ended December 31 2023, 2022 and 2021: Pension Benefits OPEB Total Pension Benefits and OPEB 2023 2022 2021 (a) 2023 2022 2021 (a) 2023 2022 2021 (a) Components of net periodic benefit (credit) cost: Service cost $ 89 $ 126 $ 145 $ 16 $ 25 $ 29 $ 105 $ 151 $ 174 Non-service components of pension benefits & OPEB (credit) cost: Interest cost 404 290 235 76 55 45 480 345 280 Expected return on assets (520) (565) (493) (45) (55) (58) (565) (620) (551) Amortization of: Prior service (credit) cost 1 1 1 (10) (7) (9) (9) (6) (8) Actuarial (gain) loss 48 148 199 (12) (1) 10 36 147 209 Settlement charges — 6 20 — — — — 6 20 Non-service components of pension benefits & OPEB credit (cost) (b) (67) (120) (38) 9 (8) (12) (58) (128) (50) Net periodic benefit (credit) cost (c)(d)(e) $ 22 $ 6 $ 107 $ 25 $ 17 $ 17 $ 47 $ 23 $ 124 __________ (a) Costs recognized for the year ended December 31, 2021 were allocated to us by Exelon under the Exelon sponsored pension and OPEB plans prior to separation. (b) Effective February 1, 2022, these non-service (credits) costs are reflected in Other, net in the Consolidated Statements of Operations and Comprehensive Income. (c) The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2023 totaled $94 million. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2023 totaled ($54) million. (d) The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2022 totaled $131 million. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2022 totaled ($116) million. Our portion of the total net periodic benefit (credits) costs allocated to us from Exelon in January 2022 prior to separation was not material and remains in total Operating and maintenance expense. (e) The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2021 totaled $144 million. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2021 totaled ($50) million. Components of AOCI We recognize the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on our balance sheet, with offsetting entries to AOCI. The following tables provide the pre-tax components of AOCI for the years ended December 31, 2023 and 2022, for all plans combined: Pension Benefits OPEB 2023 2022 2023 2022 Changes in plan assets and benefit obligations recognized in AOCI: Separation-related adjustment $ — $ 2,664 $ — $ 22 Current year actuarial (gain) loss 509 11 94 (253) Amortization of actuarial (loss) gain (46) (134) 14 1 Amortization of prior service (cost) credit (1) (1) 6 7 Settlements — (6) — — Total recognized in AOCI $ 462 $ 2,534 $ 114 $ (223) The following table provides the components of gross accumulated other comprehensive loss that have not been recognized as components of periodic benefit cost as of December 31, 2023 and 2022, for all plans combined: Pension Benefits OPEB 2023 2022 2023 2022 Prior service (credit) cost $ 9 $ 10 $ (24) $ (30) Actuarial (gain) loss 2,985 2,524 (85) (193) Total $ 2,994 $ 2,534 $ (109) $ (223) Average Remaining Service Period For pension benefits, we amortize the unrecognized prior service (credits) costs and certain actuarial gains and losses reflected in AOCI, as applicable, based on participants’ average remaining service periods. For OPEB, we amortize the unrecognized prior service (credits) costs reflected in AOCI over participants’ average remaining service period to benefit eligibility age, and amortize certain actuarial gains and losses reflected in AOCI over participants’ average remaining service period to expected retirement. The resulting average remaining service periods for pension and OPEB were as follows as of December 31, 2023 and 2022: December 31, 2023 December 31, 2022 Pension plans 12.4 12.2 OPEB plans: Benefit Eligibility Age 7.5 7.4 Expected Retirement 8.3 8.3 Assumptions The measurement of the plan obligations and costs of providing benefits under our defined benefit pension and OPEB plans involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. The measurement of benefit obligations and costs is impacted by several assumptions and inputs, as shown below, among other factors. When developing the required assumptions, we consider historical information as well as future expectations. Discount Rate. The discount rates are determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality non-callable (or callable with make whole provisions) bonds with similar maturities to the related pension and OPEB obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and OPEB plans. The discount rate is the single level rate that produces the same result as the spot rate curve. We utilize an analytical tool developed by our actuaries to determine the discount rates. Expected Rate of Return. In determining the EROA, we consider historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectation regarding future long-term capital market performance, weighted by our target asset class allocations. Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Upon remeasurement as of December 31, 2023 and December 31, 2022, we utilized the mortality tables and projection scales released by the SOA. The following assumptions were used to determine the benefit obligations for the plans as of December 31, 2023 and December 31, 2022. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs. Pension Benefits OPEB December 31, 2023 December 31, 2022 December 31, 2023 December 31, 2022 Discount rate (a) 5.17 % 5.52 % 5.15 % 5.50 % Investment crediting rate (b) 5.07 % 5.15 % N/A N/A Rate of compensation increase (c) 4.25 % 3.75 % 4.25 % 3.75 % Mortality table Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Healthcare cost trend on covered charges N/A N/A Initial and ultimate rate of 5.00% Initial and ultimate rate of 5.00% __________ (a) The discount rates above represent the blended rates used to calculate the majority of Constellation's pension and OPEB costs. (b) The investment crediting rate above represents a weighted average rate. (c) Includes 4.25% average for the 5 year period (2024-2028) and 3.75% average thereafter. The following assumptions were used to determine the net periodic benefit cost for the plans for the years ended December 31, 2023 and 2022. Pension Benefits OPEB 2023 2022 2023 2022 Discount rate (a) 5.52 % 3.23 % 5.50 % 3.21 % Investment crediting rate (b) 5.15 % 3.86 % N/A N/A Expected return on plan assets (c) 6.50 % 6.50 % 6.51 % 6.39 % Rate of compensation increase 3.75 % 3.75 % 3.75 % 3.75 % Mortality table Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Healthcare cost trend on covered charges N/A N/A Initial and ultimate rate of 5.00% Initial and ultimate rate of 5.00% __________ (a) The discount rates above represent the blended rates used to calculate the majority of Constellation's pension and OPEB costs. (b) The investment crediting rate above represents a weighted average rate. (c) Applicable to our pension and OPEB plans with plan assets, with the OPEB rate representing a weighted average. Contributions We consider various factors when making qualified pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act, and management of the pension obligation. The Pension Protection Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status over time. This level funding strategy helps minimize the volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are both subject to change, we made our annual qualified pension contribution in July 2023. Our non-qualified pension plans are not funded given that they are not subject to statutory minimum contribution requirements. OPEB plans are also not subject to statutory minimum contribution requirements, though we have funded certain plans. For our funded OPEB plans, we consider several factors in determining the level of contributions to these plans, including liabilities management and levels of benefit claims paid. The following table provides our contributions paid to our qualified pension plans, non-qualified pension plans, and OPEB plans for the years ended December 31, 2023, 2022, and 2021: 2023 2022 2021 (b) Pension contributions (a) $ 26 $ 212 $ 231 OPEB contributions 28 26 28 Total contributions $ 54 $ 238 $ 259 __________ (a) In 2023 and 2022, our annual qualified pension contributions were $21 million and $192 million, respectively. The benefit payments to the non-qualified pension plans in 2023 and 2022 were not material. (b) Prior to separation, Exelon allocated contributions related to its legacy Exelon sponsored pension and OPEB plans to its subsidiaries based on accounting cost or employee participation (both active and retired). The following table provides our planned contributions to our qualified pension plans, non-qualified pension plans, and OPEB plans in 2024 (including our benefit payments related to unfunded plans): Qualified Pension Plans Non-Qualified Pension Plans OPEB Total Planned contributions $ 161 $ 13 $ 20 $ 194 Estimated Future Benefit Payments Estimated future benefit payments to participants over the next ten years in all pension and OPEB plans as of December 31, 2023 are as follows: Pension Benefits OPEB 2024 $ 576 $ 117 2025 575 116 2026 581 115 2027 581 114 2028 587 114 2029 through 2033 2,880 546 Total estimated future benefits payments through 2033 $ 5,780 $ 1,122 Plan Assets On a regular basis, we evaluate our investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. We have developed and implemented a liability hedging investment strategy for our qualified pension plans that has reduced the volatility of these pension assets relative to the associated pension obligations. We are likely to continue to gradually increase the liability hedging portfolio as the funded status of the plans improve. The overall objective is to achieve attractive risk-adjusted returns that will balance with the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Trust assets for our OPEB plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility. Actual asset returns have an impact on the costs reported for the pension and OPEB plans. The actual asset returns across our pension and OPEB plans for the year ended December 31, 2023 were 6.50% and 9.50%, respectively, compared to an expected long-term return assumption of 6.50% and 6.50%, respectively. We used an EROA of 6.50% to estimate both our 2024 pension and OPEB costs. Our pension and OPEB plan target asset allocations as of December 31, 2023 and 2022 were as follows: December 31, 2023 December 31, 2022 Asset Category Pension Benefits OPEB Pension Benefits OPEB Equity securities 21 % 17 % 21 % 43 % Fixed income securities 54 % 70 % 54 % 45 % Alternative investments (a) 25 % 13 % 25 % 12 % Total 100 % 100 % 100 % 100 % __________ (a) Alternative investments include private equity, hedge funds, real estate, and private credit. We evaluated our pension and OPEB plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2023. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2023, our pension and OPEB plans held no credit risk concentrations surpassing 10% of plan assets. Fair Value Measurements The following table presents pension and OPEB plan assets measured and recorded at fair value as a net component of Pension obligations and Non-pension postretirement benefit obligations in our Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2023 and 2022: December 31, 2023 December 31, 2022 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Pension plan assets (a) Cash equivalents $ 192 $ — $ — $ 192 $ 216 $ — $ — $ 216 Equities (b) 598 — — 598 776 — — 776 Fixed income 740 2,137 — 2,877 693 1,951 8 2,652 Private equity — — — — — — 180 180 Total assets measured at fair value 1,530 2,137 — 3,667 1,685 1,951 188 3,824 Assets measured at NAV — — — 3,283 — — — 2,879 Pension plan assets subtotal 1,530 2,137 — 6,950 1,685 1,951 188 6,703 OPEB plan assets (a) Cash equivalents — — — $ — 40 — — $ 40 Equities 232 — — 232 152 — — 152 Fixed income 62 94 — 156 67 61 — 128 Total assets measured at fair value 294 94 — 388 259 61 — 320 Assets measured at NAV — — — 304 — — — 414 OPEB plan assets subtotal 294 94 — 692 259 61 — 734 Total pension and OPEB plan assets (c) $ 1,824 $ 2,231 $ — $ 7,642 $ 1,944 $ 2,012 $ 188 $ 7,437 __________ (a) See Note 18 — Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy. (b) Includes derivative instruments of $31 million and $6 million for the years ended December 31, 2023 and 2022, respectively, which have total notional amounts of $1,986 million and $1,879 million as of December 31, 2023 and 2022, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss. (c) Excludes net liabilities of $263 million and $43 million as of December 31, 2023 and 2022, respectively, which include certain derivative assets that have notional amounts of $15 million and $41 million as of December 31, 2023 and 2022, respectively. These items are required to reconcile to the fair value of net plan assets and consist primarily of receivables or payables related to pending securities sales and purchases, and interest and dividends receivable. The following table presents the reconciliation of Level 3 assets and liabilities measured at fair value for pension and OPEB plans for the years ended December 31, 2023 and 2022: Pension Assets Fixed Income Private Equity Total Balance as of January 1, 2023 $ 8 $ 180 $ 188 Actual return on plan assets: Relating to assets still held as of the reporting date — 12 12 Relating to assets sold during the period — (13) (13) Purchases and settlements: Purchases — 8 8 Settlements (a) — (187) (187) Transfers out of Level 3 (8) — (8) Balance as of December 31, 2023 $ — $ — $ — Pension Assets Fixed Income Private Equity Total Balance as of January 1, 2022 $ — $ — $ — Separation-related adjustment 9 — 9 Actual return on plan assets: Relating to assets still held as of the reporting date (1) (54) (55) Purchases and settlements: Purchases — 18 18 Settlements (a) — (4) (4) Transfers out of Level 3 (b) — 220 220 Balance as of December 31, 2022 $ 8 $ 180 $ 188 __________ (a) Represents cash settlements only. (b) Includes certain private equity investments previously measured at fair value using NAV or its equivalent as a practical expedient at separation transferred to Level 3 primarily due to changes in market liquidity or data. Valuation Techniques Used to Determine Fair Value The techniques used to fair value the pension and OPEB assets invested in cash equivalents, equities, fixed income, derivatives, private equity, real estate, and private credit investments are the same as the valuation techniques for these types of investments in NDT funds. See Cash Equivalents and NDT Fund Investments in Note 18 — Fair Value of Financial Assets and Liabilities for further information. Pension and OPEB assets also include investments in hedge funds. Hedge fund investments include those that employ a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or its equivalent as a practical expedient, and therefore, hedge funds are not classified within the fair value hierarchy. We have the ability to redeem these investments at NAV or its equivalent subject to certain restrictions which may include a lock-up period or a gate. Defined Contribution Savings Plan We sponsor the Constellation Employee Savings Plan, a 401(k) defined contribution savings plan. The plan allows employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. We match a percentage of the employee contributions up to certain limits. In addition, certain employees are eligible for a fixed non-discretionary employer contribution in lieu of a pension benefit. The employer contributions to the savings plan were $106 million, $90 million and $53 million for the years ended December 31, 2023, 2022, and 2021, respectively. |
Derivative Financial Instrument
Derivative Financial Instruments | 12 Months Ended |
Dec. 31, 2023 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Financial Instruments | Derivative Financial Instruments We use derivative instruments to manage commodity price risk, interest rate risk, and foreign exchange risk related to ongoing business operations. Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. All derivative instruments, excluding NPNS and cash flow hedges, are recorded at fair value through earnings. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle, and revenue or expense is recognized in earnings as the underlying physical commodity is sold or delivered. Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referenced contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below, which present fair value balances, our energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns. Our use of cash collateral is generally unrestricted unless we were downgraded below investment grade. As our senior unsecured debt rating is currently rated at BBB+ and Baa2 by S&P and Moody's, respectively, it would take a three notch downgrade by S&P or a two notch downgrade by Moody's for us to go below investment grade. Commodity Price Risk We employ established policies and procedures to manage our risks associated with market fluctuations in commodity prices by entering physical and financial derivative contracts, including swaps, futures, forwards, options, and short-term and long-term commitments to purchase and sell energy and energy-related products. We believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices. To the extent the amount of energy we produce or procure differs from the amount of energy we have contracted to sell and in connection with portfolio optimization, we are exposed to market fluctuations in the prices of electricity, natural gas, and other commodities. We use a variety of derivative and non-derivative instruments to manage the commodity price risk of our electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements, and other energy-related products marketed and purchased. To manage these risks, we may enter fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. We are also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis. Additionally, we are exposed to certain market risks through our proprietary trading activities. The proprietary trading activities are a complement to our energy marketing portfolio but represent a small portion of our overall energy marketing activities and are subject to limits established by the Executive Committee. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Gains and losses associated with proprietary trading are reported as Operating revenues in the Consolidated Statements of Operations and Comprehensive Income and are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the years ended December 31, 2023, 2022, and 2021, net pre-tax commodity mark-to-market gains and losses were not material. The following tables provide a summary of the derivative fair value balances recorded as of December 31, 2023 and 2022: December 31, 2023 Economic Proprietary Collateral (a)(b) Netting (a) Total Mark-to-market derivative assets (current) $ 7,927 $ 2 $ 703 $ (7,472) $ 1,160 Mark-to-market derivative assets (noncurrent) 3,345 — 330 (2,682) 993 Total mark-to-market derivative assets 11,272 2 1,033 (10,154) 2,153 Mark-to-market derivative liabilities (current) (9,019) (2) 922 7,472 (627) Mark-to-market derivative liabilities (noncurrent) (3,545) — 445 2,682 (418) Total mark-to-market derivative liabilities (12,564) (2) 1,367 10,154 (1,045) Total mark-to-market derivative net assets (liabilities) $ (1,292) $ — $ 2,400 $ — $ 1,108 December 31, 2022 Mark-to-market derivative assets (current) $ 15,296 $ 10 $ 161 $ (13,123) $ 2,344 Mark-to-market derivative assets (noncurrent) 5,100 — 217 (4,074) 1,243 Total mark-to-market derivative assets 20,396 10 378 (17,197) 3,587 Mark-to-market derivative liabilities (current) (15,049) (6) 374 13,123 (1,558) Mark-to-market derivative liabilities (noncurrent) (5,203) — 146 4,074 (983) Total mark-to-market derivative liabilities (20,252) (6) 520 17,197 (2,541) Total mark-to-market derivative net assets (liabilities) $ 144 $ 4 $ 898 $ — $ 1,046 _________ (a) We net all available amounts allowed in our Consolidated Balance Sheets in accordance with authoritative guidance for derivatives. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. (b) Includes $1,712 million of variation margin posted and $836 million of variation margin held from the exchanges as of December 31, 2023 and 2022, respectively. Economic Hedges (Commodity Price Risk) For the years ended December 31, 2023, 2022, and 2021, we recognized the following net pre-tax commodity mark-to-market gains (losses), which are also included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the Years Ended December 31, Income Statement Location 2023 2022 2021 Operating revenues $ 1,402 $ (1,193) $ (635) Purchased power and fuel (2,368) 167 1,206 Total $ (966) $ (1,026) $ 571 In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on owned and contracted generation positions that have not been hedged. Beginning in 2024, our nuclear fleet is eligible for the nuclear PTC provided by the IRA, an important tool in managing commodity price risk for each nuclear unit not already receiving state support. The nuclear PTC provides increasing levels of support as unit revenues decline below levels established in the IRA and is further adjusted annually for inflation over the duration of the program. In locations and periods where our load serving activities do not naturally offset existing generation portfolio risk, remaining commodity price exposure is managed through portfolio hedging activities. Portfolio hedging activities are generally concentrated in the prompt three years, when customer demand and market liquidity enable effective price risk mitigation. During this prompt three-year period, we seek to mitigate price risk associated with our load serving contracts, non-nuclear generation, and any residual price risk for our nuclear generation that the nuclear PTC and state programs may not fully mitigate. We also enter transactions that further optimize the economic benefits of our overall portfolio. Interest Rate and Foreign Exchange Risk We utilize interest rate swaps to manage our interest rate exposure and foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, both of which are treated as economic hedges. The notional amounts were $562 million and $524 million as of December 31, 2023 and 2022, respectively. The following table provides the mark-to-market derivative assets and liabilities as of December 31, 2023 and 2022: December 31, 2023 December 31, 2022 Economic Netting (a) Total Economic Netting (a) Total Mark-to-market derivative assets (current) $ 20 $ (1) $ 19 $ 29 $ (5) $ 24 Mark-to-market derivative assets (noncurrent) 2 — 2 18 — 18 Total mark-to-market derivative assets 22 (1) 21 47 (5) 42 Mark-to-market derivative liabilities (current) (6) 1 (5) (5) 5 — Mark-to-market derivative liabilities (noncurrent) (1) — (1) — — — Total mark-to-market derivative liabilities (7) 1 (6) (5) 5 — Total mark-to-market derivative net assets (liabilities) $ 15 $ — $ 15 $ 42 $ — $ 42 _________ (a) We net all available amounts in our Consolidated Balance Sheets in accordance with authoritative guidance for derivatives. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements. The mark-to-market gains and losses associated with management of interest rate and foreign currency exchange rate risk for the years ended December 31, 2023, 2022, and 2021 were not material, which are also included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. Credit Risk We would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts as of the reporting date. For commodity derivatives, we enter into enabling agreements that allow for payment netting with our counterparties, which reduces our exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and, with respect to each individual counterparty, netting is limited to t ransactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allows for cross product netting. In addition to payment netting language in the enabling agreement, our credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and other risk management criteria. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with us, as specified in each enabling agreement. Our credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis. The following tables provide information on the credit exposure for all derivative instruments, NPNS and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2023. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk by types of counterparties. The amounts in the tables below exclude credit risk exposure from individual retail counterparties and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX, and Nodal commodity exchanges. Rating as of December 31, 2023 Total Credit Collateral (a) Net Number of Net Exposure of Investment grade $ 1,257 $ 51 $ 1,206 1 $ 222 Non-investment grade 22 7 15 — — No external ratings Internally rated — investment grade 116 — 116 — — Internally rated — non-investment grade 259 45 214 — — Total $ 1,654 $ 103 $ 1,551 1 $ 222 __________ (a) As of December 31, 2023, credit collateral held from counterparties where we had credit exposure included $44 million of cash and $59 million of letters of credit. The credit collateral does not include non-liquid collateral. Net Credit Exposure by Type of Counterparty As of December 31, 2023 Investor-owned utilities, marketers, power producers $ 1,271 Energy cooperatives and municipalities 132 Financial Institutions 49 Other 99 Total $ 1,551 Credit-Risk-Related Contingent Features As part of the normal course of business, we routinely enter into physically or financially settled contracts for the purchase and sale of capacity, electricity, fuels, emissions allowances, and other energy-related products. Certain of our derivative instruments contain provisions that require us to post collateral. We also enter into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon our credit ratings from S&P and Moody's. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if we were to be downgraded or lose our investment grade credit ratings (based on our senior unsecured debt rating), we would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, we believe an amount of several months of future payments (e.g., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below. The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below: As of December 31, Credit-Risk-Related Contingent Features 2023 2022 Gross fair value of derivative contracts containing this feature $ (1,894) $ (4,736) Offsetting fair value of in-the-money contracts under master netting arrangements 925 2,048 Net fair value of derivative contracts containing this feature $ (969) $ (2,688) As of December 31, 2023 and 2022, we posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements. As of December 31, 2023 2022 Cash collateral posted (a) $ 2,449 $ 1,636 Letters of credit posted (a) 777 947 Cash collateral held (a) 64 765 Letters of credit held (a) 61 115 Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1) (b)(c)(d) 1,914 3,337 _________ (a) The cash collateral and letters of credit amounts are inclusive of NPNS contracts. (b) Certain of our contracts contain provisions that allow a counterparty to request additional collateral when there has been a subjective determination that our credit quality has deteriorated, generally termed “adequate assurance.” Due to the subjective nature of these provisions, we estimate the amount of collateral that we may ultimately be required to post in relation to the maximum exposure with the counterparty. (c) The downgrade collateral is inclusive of all contracts in a liability position regardless of accounting treatment and excludes any contracts with individual retail counterparties. (d) A loss of investment grade credit rating would require a significant reduction in credit ratings from their current levels of BBB+ and Baa2 at S&P and Moody's, respectively. We enter into supply forward contracts with certain utilities with one-sided collateral postings only from us. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, we are required to post collateral once certain unsecured credit limits are exceeded. |
Debt and Credit Agreements
Debt and Credit Agreements | 12 Months Ended |
Dec. 31, 2023 | |
Debt Disclosure [Abstract] | |
Debt and Credit Agreements | Debt and Credit Agreements Short-Term Borrowings We meet our short-term liquidity requirements primarily through the issuance of commercial paper. We may use our credit facility for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. Credit Agreements On February 1, 2022, we entered into a credit agreement establishing a $3.5 billion five-year revolving credit facility at a variable interest rate of SOFR plus 1.275% and on February 9, 2022 we entered into a $1 billion five-year liquidity facility with the primary purpose of supporting our letter of credit issuances. Many of our bilateral credit agreements remain in effect. Borrowings under our revolving credit agreement bear interest at a rate based upon either the Daily Simple SOFR rate or a Term SOFR rate, plus an adder based upon our credit ratings. The adders for the Daily Simple SOFR based borrowings and Term SOFR borrowings are 27.5 basis points and 127.5 basis points, respectively. If we lose our investment grade rating, the maximum adders for Daily Simple SOFR rate borrowings and Term SOFR rate borrowings would be 100 basis points and 200 basis points, respectively. The credit agreements also require us to pay facility fees based upon the aggregate commitments. The fee varies depending upon our credit rating. See below for additional details. As of December 31, 2023 and 2022 we had the following aggregate bank commitments, credit facility borrowings and available capacity under our respective credit facilities: Facility Type Aggregate Bank Facility Draws Outstanding Outstanding Commercial Paper(a) Available Capacity as of December 31, 2023 Syndicated Revolver $ 3,500 $ — $ 60 $ 1,107 $ 2,333 Bilaterals 1,500 — 878 — 622 Liquidity Facility 971 — 720 — 191 (b) Project Finance 137 — 117 — 20 Total $ 6,108 $ — $ 1,775 $ 1,107 $ 3,166 Facility Type Aggregate Bank Facility Draws Outstanding Outstanding Commercial Paper(a) Available Capacity as of December 31, 2022 Syndicated Revolver $ 3,500 $ — $ 765 $ 959 $ 1,776 Bilaterals 1,200 — 867 — 333 Liquidity Facility 971 — 732 — 139 (b) Project Finance 131 — 111 — 20 Total $ 5,802 $ — $ 2,475 $ 959 $ 2,268 __________ (a) Our commercial paper program is supported by the revolving credit agreement. In order to maintain our commercial paper program in the amounts indicated above, we must have a credit facility in place, at least equal to the amount of our commercial paper program. As of both December 31, 2023 and 2022, the maximum program size of our commercial paper program was $3.5 billion. We do not issue commercial paper in an aggregate amount exceeding the then available capacity under our credit facility. The weighted average interest rate on commercial paper borrowings was 5.66% and 4.90% as of December 31, 2023 and 2022, respectively. (b) The maximum amount of the bank commitment is not to exceed $971 million. The aggregate available capacity of the facility is subject to market fluctuations based on the value of U.S Treasury Securities which determines the amount of collateral held in the trust. We may post additional collateral to borrow up to the maximum bank commitment. As of December 31, 2023 and 2022, without posting additional collateral, the actual availability of facility, prior to outstanding letters of credit was $911 million and $871 million, respectively. Bilateral Credit Agreements The following table reflects the bilateral credit agreements at December 31, 2023: Date Initiated Latest Amendment Date Maturity Date(a) Amount January 5, 2016 (b) April 4, 2023 April 3, 2026 $ 150 October 25, 2019 (b) N/A N/A 200 November 20, 2019 (b) N/A N/A 300 November 21, 2019 (b) N/A N/A 100 November 21, 2019 (b) November 15, 2022 November 21, 2024 100 May 15, 2020 (b) March 31, 2023 N/A 300 August 12, 2022 (b) N/A N/A 50 March 29, 2023 (b) N/A March 29, 2025 100 December 8, 2023 (b) N/A N/A 200 __________ (a) Credit facilities that do not contain a maturity date are specific to the agreements set within each contract. In some instances, credit facilities are automatically renewed based on the contingency standards set within the specific agreement. (b) Bilateral credit agreements solely support the issuance of letters of credit and do not back our commercial paper program. Short-Term Loan Agreements On March 31, 2020, we entered into a term loan agreement for $300 million. We repaid $100 million of the term loan on March 29, 2022. The remaining $200 million from the loan agreement was renewed on March 29, 2022 and repaid on March 29, 2023. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.80% and all indebtedness thereunder is unsecured. The loan was reflected in Short-term borrowings in the Consolidated Balance Sheets as of December 31, 2022. On January 26, 2023, we entered into a term loan agreement for $100 million. The loan agreement has an expiration of January 25, 2024. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.80% and all indebtedness thereunder is unsecured. The loan was reflected in Short-term borrowings in the Consolidated Balance Sheet as of December 31, 2023. We repaid this loan on January 25, 2024. On February 9, 2023, we entered into a term loan agreement for $400 million. The loan agreement has an expiration of February 8, 2024. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 1.05% and all indebtedness thereunder is unsecured. The loan was reflected in Short-term borrowings in the Consolidated Balance Sheet as of December 31, 2023. We repaid this loan on February 8, 2024. On February 12, 2024, we entered into a term loan agreement for $200 million. The loan agreement has an expiration of February 8, 2025. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.90% and all indebtedness thereunder is unsecured. Long-Term Debt The following table presents the outstanding long-term debt as of December 31, 2023 and 2022: Maturity December 31, Rates 2023 2022 Long-term debt Senior unsecured notes 3.25 % - 6.50 % 2025 - 2053 $ 5,688 $ 2,938 Tax-exempt notes 4.10 % - 4.45 % 2025 - 2053 (a) 435 — Notes payable and other 2.10 % - 5.85 % 2024 - 2029 34 68 Nonrecourse debt: Fixed rates 2.29 % - 6.00 % 2031 - 2037 780 839 Variable rates 7.24 % - 8.57 % 2026 - 2027 740 805 Total long-term debt 7,677 4,650 Unamortized debt discount and premium, net (4) (5) Unamortized debt issuance costs (56) (36) Long-term debt due within one year (121) (143) Long-term debt $ 7,496 $ 4,466 __________ (a) The Tax-exempt notes have a maturity date of March 1, 2025 - April 1, 2053, and a mandatory purchase date that ranges from March 1, 2025 - June 1, 2029. Long-term debt maturities in the periods 2024 through 2028 and thereafter are as follows: 2024 $ 121 2025 1,010 2026 121 2027 705 2028 1,160 Thereafter 4,560 Total $ 7,677 Debt Covenants As of December 31, 2023, we are in compliance with all debt covenants. Nonrecourse Debt We have also issued nonrecourse debt, for which approximately $2 billion of generating assets have been pledged as collateral as of both December 31, 2023 and 2022, respectively. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against us in the event of a default. If a specific project financing entity does not maintain compliance with its specific nonrecourse debt covenants, there could be a requirement to accelerate repayment of the associated debt or other borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy the associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The loan will mature on January 5, 2037. Interest rates on the loan were fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. The advances were completed as of December 31, 2015 and the outstanding loan balance bears interest at an average blended interest rate of 2.82%. As of December 31, 2023 and 2022, approximately $390 million and $415 million were outstanding, respectively. In addition, we have issued letters of credit to support the equity investment in the project, with $36 million and $37 million outstanding as of December 31, 2023 and 2022, respectively. In December 2017, our interests in Antelope Valley were contributed to and are pledged as collateral for the CR financing structures referenced below. Continental Wind, LLC. In September 2013, Continental Wind, our indirect subsidiary, completed the issuance and sale of $613 million senior secured notes. Continental Wind owns and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico and Texas with a total net capacity of 667 MWs. The net proceeds were distributed to us for general business purposes. The notes are scheduled to mature on February 28, 2033. The notes bear interest at a fixed rate of 6.00% with interest payable semi-annually. As of December 31, 2023 and December 31, 2022, approximately $315 million and $345 million were outstanding, respectively. In addition, Continental Wind has a $128 million letter of credit facility and $4 million working capital revolver facility. Continental Wind has issued letters of credit to satisfy certain of its credit support and security obligations. As of December 31, 2023 and 2022, the Continental Wind letter of credit facility had $116 million and $111 million in letters of credit outstanding related to the project, respectively. In 2017, our interests in Continental Wind were contributed to CRP. See Note 22 - Variable Interest Entities for additional information on CRP. Renewable Power Generation. In March 2016, RPG, our indirect subsidiary, issued $150 million aggregate principal amount of nonrecourse senior secured notes. The net proceeds were distributed to us for paydown of long term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general business purposes. The loan is scheduled to mature on March 31, 2035. The term loan bears interest at a fixed rate of 4.11% payable semi-annually. As of December 31, 2023 and December 31, 2022, approximately $70 million and $80 million were outstanding, respectively. In 2017, our interests in RPG were contributed to CRP. See Note 22 - Variable Interest Entities for additional information on CRP. Constellation Renewables. In November 2017, CR, our indirect subsidiary, entered into an $850 million nonrecourse senior secured term loan credit facility agreement with a maturity date of November 28, 2024. In addition to the financing, CR entered into interest rate swaps to manage a portion of the interest rate exposure in connection with the financing. The swap had an initial notional amount of $636 million and fixed the 3-month LIBOR at 2.32%. In December 2020, CR entered into a financing agreement for a $750 million nonrecourse senior secured term loan credit facility, scheduled to mature on December 15, 2027. Beginning in June 2023, the term loan bears interest at a variable rate equal to 3-month SOFR plus 2.76%, subject to a 1% SOFR floor with interest payable quarterly. Redemptions prior to June 2023 were based on LIBOR + 2.50%. In addition to the financing, CR entered into interest rate swaps to manage a portion of the interest rate exposure in connection with the financing. The swap had an initial notional amount of $516 million and fixed the 3-month LIBOR at 1.05%. Beginning in June 2023, the swap fixed the 3-month SOFR at 0.8295%. The proceeds were used to repay the November 2017 nonrecourse senior secured term loan credit facility of $850 million, of which $709 million was outstanding as of the retirement date in December 2020, and to settle the November 2017 interest rate swap. Our interests in CRP and Antelope Valley remain contributed to and pledged as collateral for this financing. As of December 31, 2023 and 2022, $650 million and $690 million was outstanding, respectively. See Note 22 — Variable Interest Entities for additional information on CRP and Note 16 — Derivative Financial Instruments for additional information on interest rate swaps. West Medway II, LLC. On May 13, 2021, West Medway II, LLC (West Medway II), our indirect subsidiary, entered into a financing agreement for a $150 million nonrecourse senior secured term loan credit facility with a maturity date of March 31, 2026. Beginning in May 2023, the term loan bears interest at a variable rate equal to 1-month SOFR plus the variable interest rate of 2.975% - 3.225%, paid quarterly. Redemptions prior to May 2023 were based on LIBOR + 2.875%. In addition to the financing, West Medway II entered into interest rate swaps to manage a portion of the interest rate exposure in connection with the financing. The swaps had an initial notional amount of $113 million and fixed the 1-month LIBOR at 0.61%. Beginning in May, the swap fixed the 1-month SOFR at 0.5365%. We used the net proceeds for general corporate purposes. Our interests in West Medway II, were pledged as collateral for this financing. As of December 31, 2023 and 2022, approximately $85 million and $115 million was outstanding, respectively. See Note 16 — Derivative Financial Instruments for additional information on interest rate swaps. |
Fair Value of Financial Assets
Fair Value of Financial Assets and Liabilities | 12 Months Ended |
Dec. 31, 2023 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Assets and Liabilities | Fair Value of Financial Assets and Liabilities We measure and classify fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows: • Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to liquidate as of the reporting date. • Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. • Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability. Fair Value of Financial Liabilities Recorded at Amortized Cost The following tables present the carrying amounts and fair values of our long-term debt and the SNF obligation as of December 31, 2023 and 2022. We have no financial liabilities classified as Level 1. The carrying amounts of the short-term liabilities as presented in the Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments. December 31, 2023 December 31, 2022 Carrying Amount Fair Value Carrying Amount Fair Value Level 2 Level 3 Total Level 2 Level 3 Total Long-Term Debt, including amounts due within one year $ 7,617 $ 7,140 $ 774 $ 7,914 $ 4,609 $ 3,688 $ 859 $ 4,547 SNF Obligation 1,296 1,222 — 1,222 1,230 1,021 — 1,021 We use the following methods and assumptions to estimate fair value of our financial liabilities recorded at carrying cost: Type Level Valuation Long-term Debt, including amounts due within one year Taxable Debt Securities 2 The fair value is determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. We obtain credit spreads based on trades of our existing debt securities as well as other issuers in the utility sector with similar credit ratings. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. Variable Rate Financing Debt 2 Debt rates are reset on a regular basis and the carrying value approximates fair value. Government Backed Fixed Rate Project Financing Debt 3 The fair value is similar to the process for taxable debt securities. Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable U.S. Treasury rate as well as a current market curve derived from government-backed securities. Non-Government Backed Fixed Rate Nonrecourse Debt 3 Fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project. SNF Obligation SNF Obligation 2 The carrying amount is derived from a contract with the DOE to provide for disposal of SNF from certain of our nuclear generating stations. See Note 19 — Commitments and Contingencies for further details. When determining the fair value of the obligation, the future carrying amount of the SNF obligation is calculated by compounding the current book value of the SNF obligation at the 13-week U.S. Treasury rate. The compounded obligation amount is discounted back to present value using our discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2035. Recurring Fair Value Measurements The following tables present assets and liabilities measured and recorded at fair value in the Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2023 and 2022: As of December 31, 2023 As of December 31, 2022 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Cash equivalents (a) $ 42 $ — $ — $ 42 $ 41 $ — $ — $ 41 NDT fund investments Cash equivalents (b) 356 87 — 443 181 88 — 269 Equities 4,574 1,990 1 6,565 3,462 1,498 — 4,960 Fixed income 2,043 1,523 277 3,843 2,017 1,044 264 3,325 Private credit — — 151 151 — — 159 159 Assets measured at NAV — — — 5,396 — — — 5,414 NDT fund investments subtotal (c) 6,973 3,600 429 16,398 5,660 2,630 423 14,127 Rabbi trust investments 48 33 1 82 40 27 1 68 Investments in equities (d) 372 — — 372 6 — — 6 Commodity derivative assets Economic hedges 2,330 5,821 3,143 11,294 3,505 11,353 5,585 20,443 Proprietary trading — — 2 2 — 4 6 10 Effect of netting and allocation of (e)(f) (1,996) (5,195) (1,931) (9,122) (2,951) (10,348) (3,525) (16,824) Commodity derivative assets subtotal 334 626 1,214 2,174 554 1,009 2,066 3,629 DPP consideration — 1,216 — 1,216 — 515 — 515 Total assets measured at fair value 7,769 5,475 1,644 20,284 6,301 4,181 2,490 18,386 Total assets 7,769 5,475 1,644 20,284 6,301 4,181 2,490 18,386 Liabilities Commodity derivative liabilities Economic hedges (2,681) (7,154) (2,736) (12,571) (3,171) (11,498) (5,588) (20,257) Proprietary trading — — (2) (2) — (4) (2) (6) Effect of netting and allocation of collateral (e)(f) 2,587 6,542 2,393 11,522 3,279 10,700 3,743 17,722 Commodity derivative liabilities subtotal (94) (612) (345) (1,051) 108 (802) (1,847) (2,541) Deferred compensation obligation — (69) — (69) — (57) — (57) Total liabilities (94) (681) (345) (1,120) 108 (859) (1,847) (2,598) Total net assets $ 7,675 $ 4,794 $ 1,299 $ 19,164 $ 6,409 $ 3,322 $ 643 $ 15,788 __________ (a) CEG Parent has $54 million of Level 1 cash equivalents as of December 31, 2023. We exclude cash of $349 million and $390 million as of December 31, 2023 and December 31, 2022, respectively, and restricted cash of $49 million and $70 million as of December 31, 2023 and December 31, 2022, respectively. CEG Parent has excluded an additional $2 million and $19 million of cash as of December 31, 2023 and 2022, respectively. (b) Includes net liabilities of $115 million and $168 million as of December 31, 2023 and 2022, respectively, which include certain derivative assets that have notional amounts of $64 million and $59 million as of December 31, 2023 and 2022, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less. In the prior year net liabilities were excluded, prior year amounts have been updated for consistency with current year presentation. (c) Includes derivative assets and liabilities that are not material, which have total notional amounts of $884 million and $494 million as of December 31, 2023 and 2022, respectively. The notional principal amounts provide one measure of the transaction volume outstanding as of the periods ended and do not represent the amount of our exposure to credit or market loss. (d) Includes an equity investment that became publicly traded in the second quarter of 2023 and now has a readily determinable fair value (and no longer is accounted for as an equity method investment due to lack of significant influence). We record the fair value of this investment in Investments on the Consolidated Balance Sheets based on the quoted market price of the stock at June 30, 2023, which resulted in an unrealized gain of $313 million within Other, net in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2023. (e) Net collateral posted to/(received from) counterparties totaled $591 million, $1,347 million, and $462 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2023. Net collateral posted to/(received from) counterparties totaled $328 million, $352 million, and $218 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2022. (f) Includes $1,712 million of variation margin posted and $836 million of variation margin held from the exchanges as of December 31, 2023 and 2022, respectively. As of December 31, 2023, our NDTs have outstanding commitments to invest in private credit, private equity, and real estate investments of $344 million, $88 million, and $373 million, respectively. These commitments will be funded by our existing NDT funds. Equity Security Investments without Readily Determinable Fair Values. We hold investments without readily determinable fair values with carrying amounts of $103 million and $46 million as of December 31, 2023 and 2022, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the years ended December 31, 2023 and 2022. Reconciliation of Level 3 Assets and Liabilities The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2023 and 2022: For the Year Ended December 31, 2023 NDT Fund Investments Mark-to-Market Life Insurance Contracts Total Balance as of January 1, 2023 $ 423 $ 219 $ 1 $ 643 Total realized / unrealized gains (losses) Included in net income (loss) 2 171 (a) — 173 Included in Payables related to Regulatory Agreement Units 10 — — 10 Change in collateral — 243 — 243 Purchases, sales, issuances and settlements Purchases — 160 — 160 Sales 1 (29) — (28) Settlements (7) 32 — 25 Transfers into Level 3 — 46 (b) — 46 Transfers out of Level 3 — 27 (b) — 27 Balance as of December 31, 2023 $ 429 $ 869 $ 1 $ 1,299 The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2023 $ 2 $ 1,194 $ — $ 1,196 For the Year Ended December 31, 2022 NDT Fund Investments Mark-to-Market Life Insurance Contracts Total Balance as of January 1, 2022 $ 464 $ (94) $ — $ 370 Total realized / unrealized gains (losses) Included in net income (loss) (2) (753) (a) (2) (757) Included in Payables related to Regulatory Agreement Units (10) — — (10) Change in collateral — 253 — 253 Impacts of separation — — 3 3 Purchases, sales, issuances and settlements Purchases 5 594 — 599 Sales — (50) — (50) Settlements (35) (102) — (137) Transfers into Level 3 2 381 (b) — 383 Transfers out of Level 3 (1) (10) (b) — (11) Balance as of December 31, 2022 $ 423 $ 219 $ 1 $ 643 The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2022 $ (2) $ (1,265) $ (2) $ (1,269) __________ (a) Includes a reduction of ($991) million for realized gains and an addition of $410 million for realized losses due to the settlement of derivative contracts for the years ended December 31, 2023 and 2022, respectively. (b) Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable, respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts. The following table presents the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2023, 2022, and 2021: Operating Purchased Other, net 2023 2022 2021 2023 2022 2021 2023 2022 2021 Total gains (losses) included in net income $ 706 $ (860) $ (1,343) $ (503) $ 5 $ 531 $ 2 $ (4) $ 5 Total unrealized gains (losses) 1,673 (1,330) (1,577) (479) 65 355 2 (2) 5 Cash Equivalents. Investments with original maturities of three months or less when purchased, including mutual and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1. NDT Fund Investments. The trust fund investments have been established to satisfy our nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in equities and fixed income. Our NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments, including private credit, private equity, and real estate. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2. Equities. These investments consist of individually held equity securities, equity mutual funds, and equity commingled funds in domestic and foreign markets. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which we are able to independently corroborate. Equity securities held individually, including real estate investment trusts, rights, and warrants, are primarily traded on exchanges that contain only actively traded securities due to the volume trading requirements imposed by these exchanges. The equity securities that are held directly by the trust funds are valued based on quoted prices in active markets and categorized as Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significant unobservable inputs. Equity commingled funds and mutual funds are maintained by investment companies, and fund investments are held in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets on the underlying securities and are not classified within the fair value hierarchy. These investments can typically be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions. Fixed income. For fixed income securities, which consist primarily of corporate debt securities, U.S. government securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds, and derivative instruments, the trustees obtain multiple prices from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class, or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is preferable. We have obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, we selectively corroborate the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2. This includes equity investments sold short during the period, which represent liabilities. Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which are maintained by investment companies and hold fund investments in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions. Derivative instruments. These instruments, consisting primarily of futures and swaps to manage risk, are recorded at fair value. Over-the-counter derivatives are valued daily, based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other than over-the-counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2. Private credit. Private credit investments primarily consist of investments in private debt strategies. These investments are generally less liquid assets with an underlying term of 3 to 5 years and are intended to be held to maturity. The fair value of these investments is determined by the fund manager or administrator using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Private credit investments held directly by us are categorized as Level 3 because they are based largely on inputs that are unobservable and utilize complex valuation models. For certain private credit funds, the fair value is determined using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. These investments are not classified within the fair value hierarchy because their fair value is determined using NAV or its equivalent as a practical expedient. Private equity. These investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments, and investments in natural resources. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on our understanding of the investment funds. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include unobservable inputs such as cost, operating results, discounted future cash flows, and market-based comparable data. These valuation inputs are unobservable. The fair value of private equity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy. Real estate. These investments are funds with a direct investment in pools of real estate properties. These funds are reported by the fund manager and are generally based on independent appraisals of the underlying investments from sources with professional qualifications, typically using a combination of market-based comparable data and discounted cash flows. These valuation inputs are unobservable. Certain real estate investments cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on our understanding of the investments funds. The remaining liquid real estate investments are generally redeemable from the investment vehicle quarterly, with 30 to 90 days of notice. The fair value of real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy. We evaluated our NDT portfolios for the existence of significant concentrations of credit risk as of December 31, 2023. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2023, there were no significant concentrations (generally defined as greater than 10 percent) of risk in the NDT assets. See Note 10 — Asset Retirement Obligations for additional information on the NDT fund investments. Rabbi Trust Investments. The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of executive management and directors. The Rabbi trusts' assets are included in investments in the Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, and life insurance policies. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Deferred Compensation Obligations. Our deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. We include such plans in other current and noncurrent liabilities in the Consolidated Balance Sheets. The value of our deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy. The value of certain employment agreement obligations (which are included with the Deferred compensation obligation in the table above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy. Investments in Equities. We hold certain investments in equity securities with readily determinable fair values in addition to those held within the NDT funds. These equity securities are valued based on quoted prices in active markets and are categorized as Level 1. Deferred Purchase Price Consideration. We have DPP consideration for the sale of certain receivables of retail electricity. This amount is valued based on the sales price of the receivables net of allowance for credit losses based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. Since the DPP consideration is based on the sales price of the receivables, it is categorized as Level 2 in the fair value hierarchy. See Note 6 — Accounts Receivable for additional information on the sale of certain receivables. Mark-to-Market Derivatives. Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that we believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads, and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model considers inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness, and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, model inputs are generally observable. Such instruments are categorized in Level 2. Our derivatives are predominantly at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information, model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility, and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. We consider credit and non-performance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data, in our assessment of credit and non-performance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and non-performance risk were not material to the consolidated financial statements. Disclosed below is detail surrounding our significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. The Level 3 balance generally consists of forward sales and purchases of power and natural gas and certain transmission congestion contracts. We utilize various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties, and credit enhancements. For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, we discount future cash flows using risk-free interest rates with adjustments to reflect the credit quality of each counterparty for assets and our own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $47.76 and $3.09 for power and natural gas, respectively as of December 31, 2023 . Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3. See Note 16 — Derivative Financial Instruments for additional information on mark-to-market derivatives. The following table presents the significant inputs to the forward curve used to value these positions: Type of trade Fair Value as of December 31, 2023 Fair Value as of December 31, 2022 Valuation Unobservable 2023 Range & Arithmetic Average 2022 Range & Arithmetic Average Mark-to-market derivatives—Economic hedges (a)(b) $ 407 $ (3) Discounted Cash Flow Forward power $9.64 - $216 $48 $0.63 - $283 $72 Forward gas $1.20 - $14 $3.09 $1.67 - $26 $4.57 Option Volatility 23% - 200% 87% 97% - 119% 111% __________ (a) The valuation techniques, unobservable inputs, ranges, and arithmetic averages are the same for the asset and liability positions. (b) The fair values do not include cash collateral posted (received) on Level 3 positions of $462 million and $218 million as of December 31, 2023 and December 31, 2022, respectively. The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of our commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give us the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give us the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An incr |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Commercial Commitments. Commercial commitments as of December 31, 2023, representing commitments potentially triggered by future events, were as follows: Expiration within Total 2024 2025 2026 2027 2028 2029 and beyond Letters of credit $ 1,775 $ 1,631 $ 27 $ 1 $ — $ 116 $ — Surety bonds (a) 824 824 — — — — — Total commercial commitments $ 2,599 $ 2,455 $ 27 $ 1 $ — $ 116 $ — __________ (a) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. Nuclear Insurance We are subject to liability, property damage and other risks associated with major incidents at any of our nuclear stations. Our financial exposure to these risks is mitigated through insurance and other industry risk-sharing provisions. The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2023, the current liability limit per incident is $16.2 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment effective November 1, 2018. In accordance with the Price-Anderson Act, we maintain financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2024, the required amount of nuclear energy liability insurance purchased is $500 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson-Act, which could provide up to approximately an additional $15.8 billion per incident at any U.S. nuclear power reactor in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident at any U.S. nuclear power reactor that exceeds the primary layer of financial protection. Our share of this secondary layer would be approximately $3.5 billion, based on our ownership interest in the insured nuclear reactors, however, any amounts payable under this secondary layer would be capped at $520 million per incident within one calendar year. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $16.2 billion limit for a single incident. We are required by the NRC to maintain minimal levels of property insurance that demonstrates to the satisfaction of the NRC that we possess an equivalent amount of protection covering the licensee's obligation, in the event of an accident at the licensee's reactor, to stabilize and decontaminate the reactor and the reactor station site at which the reactor experiencing the accident is located. The insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which we are a member. Currently, NRC requires that we maintain a minimum coverage limit for each reactor site of $1.06 billion, which is what our NEIL policies provide. NEIL may declare distributions to its members as a result of favorable operating experience. In recent years, NEIL has made distributions to its members. Our portion of the annual distribution declared by NEIL is estimated to be $59 million for 2023, and was $30 million and $114 million for 2022 and 2021, respectively. The distributions were recorded as a reduction to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and we cannot predict the level of future assessments, if any. The current maximum aggregate annual retrospective premium obligation for us is approximately $254 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance. NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which we are required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, we are unable to predict the timing of the availability of insurance proceeds to us and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery by us will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses. For our insured losses, we are self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by us. Any such losses could have a material adverse effect on our consolidated financial statements. Spent Nuclear Fuel Obligation Under the NWPA, the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, we are a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from our nuclear generating stations. In accordance with the NWPA and the Standard Contracts, we had previously paid the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. The DOE reduced the SNF disposal fee to zero in May 2014. Until a new fee structure is in effect, we will not accrue any further costs related to SNF disposal fees. This fee may be adjusted prospectively to ensure full cost recovery. We currently assume the DOE will begin accepting SNF in 2035 and use that date for purposes of estimating the nuclear decommissioning AROs. The SNF acceptance date assumption is based on management’s estimate of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance has been, and is expected to remain, delayed. In August 2004, we and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse us, subject to certain damage limitations based on the extent of the government’s breach, for costs associated with storage of SNF at our nuclear stations pending the DOE’s fulfillment of its obligations. That settlement agreement does not expire until all SNF has been collected from the sites that it covers. Calvert Cliffs, Ginna, Nine Mile Point, Fitzpatrick, and STP each have separate settlement agreements in place with the DOE which were extended during 2023 to provide for the reimbursement of SNF storage costs through December 31, 2025. We and the DOE have the option to extend those settlements every three years upon mutual consent. Under the settlement agreements, we received total cumulative cash reimbursements of $1,855 million through December 31, 2023 for costs incurred. After considering the amounts due to co-owners of certain nuclear stations, we received net cumulative cash reimbursements of $1,615 million. As of December 31, 2023 and 2022, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows: December 31, 2023 December 31, 2022 DOE receivable - current (a) $ 229 $ 125 DOE receivable - noncurrent (b) 40 130 Amounts owed to co-owners (c) (23) (12) __________ (a) Recorded in Other accounts receivable. (b) Recorded in Deferred debits and other assets, other. (c) Recorde d primarily in Accounts payable and accrued expenses and Other accounts receivable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilitie s. The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear plants that generated SNF prior to April 7, 1983. The below table outlines the SNF liability recorded as of December 31, 2023 and 2022: December 31, 2023 December 31, 2022 Former ComEd units (a) $ 1,158 $ 1,100 Fitzpatrick (b) 138 130 Total SNF Obligation $ 1,296 $ 1,230 __________ (a) ComEd previously elected to defer payment of the one-time fee of $277 million for its units that began operations before April 7, 1983, with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. The unfunded liabilities for SNF disposal costs, including the one-time fee, were transferred to us as part of Exelon’s 2001 corporate restructuring. See Note 10 — Asset Retirement Obligations for additional detail on Zion Station’s SNF obligation which is included in the table above. (b) A prior owner of FitzPatrick elected to defer payment of the one-time fee of $34 million, with interest to the date of payment, for the FitzPatrick unit. As part of the FitzPatrick acquisition on March 31, 2017, we assumed a SNF liability for the DOE one-time fee obligation with interest related to FitzPatrick along with an offsetting asset, included in Other deferred debits and other assets, for the contractual right to reimbursement from NYPA, a prior owner of FitzPatrick, for amounts paid for the FitzPatrick DOE one-time fee obligation. Interest for our SNF liabilities accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect for calculation of the interest accrual at December 31, 2023 was 5.488% for the deferred amount transferred from ComEd and 5.509% for the deferred FitzPatrick amount. The following table summarizes sites for which we do not have an outstanding SNF Obligation: Description Sites Fees have been paid or began operations after April 7, 1983 Former PECO units, Braidwood, Byron, Calvert Cliffs, Clinton, LaSalle Unit 2, Nine Mile Point Unit 2, and STP Outstanding SNF Obligation remains with former owners Nine Mile Point Unit 1, Ginna and TMI Environmental Remediation Matters General. Our operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, we are generally liable for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances generated by us. We own or lease several real estate parcels, including parcels on which our operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, we are currently involved in proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, we cannot reasonably estimate whether we will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by us, environmental agencies or others. Additional costs could have a material, unfavorable impact on our consolidated financial statements. As of December 31, 2023 and 2022, we had accrued undiscounted amounts for environmental liabilities of $149 million and $119 million, respectively, in Accounts payable and accrued expenses and Other deferred credits and other liabilities in the Consolidated Balance Sheets. Cotter Corporation. The EPA has advised Cotter Corporation (N.S.L.) (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at two sites in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising from these two Missouri superfund sites, West Lake Landfill and Latty Avenue. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to us, and ultimately retained by us per the terms of our separation from Exelon. Refer to Note 1 — Basis of Presentation for additional information on the separation. West Lake Landfill. Including Cotter, there are three PRPs currently participating in the West Lake Landfill remediation proceeding. In September 2018, the EPA issued its Record of Decision Amendment (RODA) for the selection of a final remedy that requires partial excavation of the radiological materials and capping the landfill. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed in 2024. In March 2019, the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. The total estimated cost of the remedy, considering the current EPA technical requirements, is approximately $305 million, including cost escalation on an undiscounted basis. Our investigation has identified several other parties who also may be PRPs and could be liable to contribute to the final remedy. In September 2018, the three identified PRPs, including Cotter, signed an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial Investigation Feasibility Study (RI/FS). The purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. We estimate the undiscounted cost for the groundwater RI/FS to be approximately $50 million. At this time we cannot predict the likelihood, or the extent to which remediation activities, if any, may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. We determined a loss associated with the EPA's partial excavation and landfill cover remedy and the groundwater RI/FS is probable and have recorded a liability for each, both of which are included in the total amount as discussed above, that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. Given the joint and several nature of these two liabilities, the amount of our ultimate liability will depend on the actual costs incurred to implement each required remedy as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. It is reasonably possible that the ultimate cost and Cotter's associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on our consolidated financial statements. Latty Avenue and Vicinity Properties . In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under the Formerly Utilized Sites Remedial Action Program. On August 3, 2020, the DOJ advised Cotter that it is seeking approximately $90 million from all the PRPs. In April 2023, Cotter was informed by the DOJ about potential additional liability for all PRPs of approximately $90 million associated with the Latty Avenue site as well as certain allegedly contaminated properties in the vicinity of Latty Avenue, for which the government alleges that Cotter is a PRP. Pursuant to a series of agreements since 2011, the DOJ and Cotter have extended the Statute of Limitations through August 31, 2024. We have determined that a loss associated with these claims is probable and have recorded an estimated liability, included in the total amount as discussed above, that reflects management's best estimate of Cotter's allocable share of the cost. It is reasonably possible that Cotter's allocable share could differ significantly, which could have a material impact on our consolidated financial statements. Litigation General. We are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. We maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages. Beginning on February 15, 2021, our Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain regions. As a result of the event and outages, we incurred a loss of approximately $800 million for the year ended December 31, 2021. The estimated impact reduced our overall Net loss by approximately $50 million for the year ended December 31, 2022, attributable to a payment to ERCOT from a defaulting market participant, the bankruptcy settlement of a defaulting ERCOT market participant, and the settlement of a dispute related to gas penalties. There was no change to the financial impact in 2023. Various lawsuits have been filed against us since the February 2021 event and outages. On March 5, 2021, we, along with more than 150 power generators and transmission and distribution companies, were sued by approximately 160 individually named plaintiffs, purportedly on behalf of all Texans who allegedly suffered loss of life or sustained personal injury, property damage or other losses as a result of the weather events. The plaintiffs alleged that the defendants failed to properly prepare for the cold weather and failed to properly conduct their operations, seeking compensatory as well as punitive damages. Thereafter, numerous other plaintiffs filed multiple lawsuits against more than 300 defendants, including us, involving similar allegations of liability and claims of personal injury and property damage all arising out of the February weather events. These additional lawsuits allege wrongful death, property damage, or other losses. Co-defendants in these lawsuits include ERCOT, transmission and distribution utilities and other generators. On December 28, 2021, approximately 130 insurance companies which insured Texas homeowners and businesses filed a subrogation lawsuit against multiple defendants alleging that defendants were at fault for the energy failure that resulted from the winter storm, causing significant property damage to the insureds. Subsequently, several hundred other insurance companies filed similar claims. All of these cases were combined in a Multi-District-Litigation (MDL) pending in Texas state court, which established a bellwether process to consider initial motions to dismiss by the different industry groups of defendants. Defendants filed motions to dismiss the amended complaints in five bellwether cases in July 2022. On February 3, 2023, the court granted the motions to dismiss pertaining to us in part and denied them in part, leaving the plaintiffs' negligence and nuisance claims to proceed. Since the motions to dismiss were partially denied, thousands of new claimants, many in multiple mass tort actions, filed lawsuits in various Texas state courts naming us, among hundreds of other defendants. The majority of these cases were transferred to the MDL. The MDL involves over 200 cases brought by approximately 30,000 plaintiffs, including more than 1,300 insurance companies, and we are defendants in the majority of them. We are also named in an alleged class action that seeks to assert claims on behalf of over 4.1 million Texans within ERCOT who lost power during Winter Storm Uri. On December 14, 2023, the Court of Appeals for the First District of Texas granted the power generator defendants' Petition for a Writ of Mandamus in the five bellwether cases and ordered the MDL court to dismiss the remaining claims against the power generator defendants, including our entities. The motions to dismiss in the five bellwether cases are expected to be applied to all of the claims against the power generator defendants in the MDL. Plaintiffs have sought rehearing of the decision with all judges of the court. We dispute liability and deny that we are responsible for any of plaintiffs’ alleged claims and are vigorously contesting them. No loss contingencies have been reflected in the consolidated financial statements with respect to these matters, nor can we currently estimate a range of loss. It is reasonably possible, however, that resolution of these matters could have a material, unfavorable impact on our consolidated financial statements. Asbestos Personal Injury Claims. We maintain a reserve for claims associated with asbestos-related personal injury actions at certain facilities that are currently owned by us or were previously owned by ComEd, PECO, or BGE. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material. At December 31, 2023 and 2022, we recorded estimated liabilities of approximately $131 million and $95 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2023, approximately $20 million of this amount related to 235 open claims presented to us, while the remaining $111 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2055, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, we monitor actual experience against the number of forecasted claims to be received and expected claim payments and evaluate whether adjustments to the estimated liabilities are necessary. |
Shareholders' Equity
Shareholders' Equity | 12 Months Ended |
Dec. 31, 2023 | |
Equity [Abstract] | |
Shareholders' Equity | Shareholders' Equity Share Repurchase Program (CEG Parent) On February 16, 2023, as part of our capital allocation plan, our Board of Directors announced a share repurchase program with a $1 billion authority without expiration. Share repurchases may be made through a variety of methods, which may include open market transactions, privately negotiated transactions, or purchases pursuant to a Rule 10b5-1 trading plan, provided that the amounts spent do not exceed what is authorized. Any repurchased shares are constructively retired and cancelled. The program does not obligate us to acquire a minimum number of shares during any period and our repurchase of CEG's common stock may be limited, suspended, or discontinued at any time at our discretion and without prior notice. Repurchases under this program commenced in March 2023. During 2023, we repurchased from the open market approximately 10.6 million shares of our common stock for a total cost, inclusive of taxes and transaction costs, of $1 billion. On December 12, 2023, our Board of Directors approved an increase to our previously announced $1 billion share repurchase program, authorizing the repurchase of up to an additional $1 billion of the Company’s outstanding common stock. As of December 31, 2023, there was $1 billion of remaining authority to repurchase shares. No other repurchase plans or programs have been authorized by our Board of Directors. Beginning in January 2024 through the date of this filing, we repurchased from the open market approximately 1.2 million shares of our common stock for a total cost, inclusive of taxes and transaction costs, of $150 million. Changes in Accumulated Other Comprehensive Loss (All Registrants) The following tables present changes in AOCI, net of tax, by component: Gains (losses) on Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items (a) Foreign Currency Items Total Balance at December 31, 2020 $ (7) $ — $ (23) $ (30) OCI before reclassifications (1) — — (1) Net current-period OCI (1) — — (1) Balance at December 31, 2021 $ (8) $ — $ (23) $ (31) Separation-related adjustments — (2006) — (2,006) OCI before reclassifications (1) 186 (3) 182 Amounts reclassified from AOCI — 95 — 95 Net current-period OCI (1) (1,725) (3) (1,729) Balance at December 31, 2022 $ (9) $ (1,725) $ (26) $ (1,760) OCI before reclassifications (2) (453) 2 (453) Amounts reclassified from AOCI 1 21 — 22 Net current-period OCI (1) (432) 2 (431) Balance at December 31, 2023 $ (10) $ (2,157) $ (24) $ (2,191) __________ (a) AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 15 — Retirement Benefits for additional information. See our Consolidated Statements of Operations and Comprehensive Income for individual components of AOCI. The following table presents income tax (expense) benefit allocated to each component of our other comprehensive income (loss): Year Ended December 31, 2023 2022 2021 Pension and non-pension postretirement benefit plans: Actuarial loss reclassified to periodic benefit cost $ (10) $ (33) $ — Pension and non-pension postretirement benefit plans valuation adjustment (a) 151 619 — __________ (a) Includes $680 million of income tax benefit related to the separation adjustment for the year ended December 31, 2022. |
Stock-Based Compensation Plans
Stock-Based Compensation Plans | 12 Months Ended |
Dec. 31, 2023 | |
Share-Based Payment Arrangement [Abstract] | |
Stock-Based Compensation Plans | Stock-Based Compensation Plans Effective February 1, 2022, we established our own LTIP and began granting cash and stock-based awards that primarily include performance share awards and restricted stock units. Our LTIP authorized 20,000,000 shares of common stock for these awards. The existing, unvested cash and stock-based awards issued through the Exelon LTIP were modified in connection with the separation to align with our performance metrics and maintain an equivalent value immediately before and after separation. The impact of this modification was not material to our stock-based compensation expense for the year ended December 31, 2022. Our employees were granted stock-based awards through the Exelon LTIP prior to separation, which primarily included performance share awards and restricted stock units. We also granted cash awards. The following table presents the stock-based compensation expense included in the Consolidated Statements of Operations and Comprehensive Income. The information does not include expenses related to the cash awards as they are not considered stock-based compensation plans under the applicable authoritative guidance: Year Ended December 31, 2023 (a) 2022 (a) 2021 (b) Total stock-based compensation expense included in operating and maintenance expense $ 178 $ 116 $ 47 Income tax benefit (45) (29) (12) Total after-tax stock-based compensation expense $ 133 $ 87 $ 35 __________ (a) Costs recognized for the years ended December 31, 2023 and 2022 are related to the Constellation LTIP. (b) Costs recognized for the year ended December 31, 2021 were allocated to us by Exelon under the Exelon LTIP prior to separation. We receive a tax deduction based on the intrinsic value of the award on the distribution date for performance share awards and restricted stock units. The tax deduction related to performance share awards and restricted stock units was not material for the years ended December 31, 2023 and 2022. For each award, throughout the requisite service period, we recognize the tax benefit related to compensation costs. For performance share awards and restricted stock units, our realized tax benefit when distributed was not material for the years ended December 31, 2023 and 2022. Performance Share Awards Performance share awards are granted under the LTIP. The performance share awards are typically settled 50% in common stock and 50% in cash at the end of the three-year performance period, subject to certain ownership thresholds that, if met, may result in cash settlement of the entire award. The common stock portion of the performance share awards is considered an equity award and is valued based on our stock price on the grant date. The cash portion of the performance share awards is considered a liability award which is remeasured each reporting period based on the current stock price. As the value of the common stock and cash portions of the awards are based on the stock price during the performance period, coupled with changes in the total expected payout of the award, the compensation costs are subject to volatility until payout is established. For nonretirement-eligible employees, performance share awards are recognized over the vesting period of three years using the straight-line method. For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant. We process forfeitures as they occur for employees who do not complete the requisite service period. The following table summarizes our unvested performance share awards activity: Shares Weighted Average Grant Date Fair Value (per share) Unvested at December 31, 2022 849,342 $ 47.40 Granted 370,874 83.26 Change in performance 471,561 75.31 Forfeited (20,615) 57.80 Undistributed vested awards (a) (834,837) 90.81 Unvested at December 31, 2023 836,325 $ 61.47 __________ (a) Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2023 and 2022. The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards vested: December 31, 2023 (a) December 31, 2022 (a) Weighted average grant date fair value (per share) $ 83.26 $ 48.33 Total fair value of performance shares vested 76 69 __________ (a) As of December 31, 2023 and 2022 , $39 million and $28 million of total unrecognized compensation costs related to unvested performance shares are expected to be recognized over the remaining weighted-average period of 1.6 years and 1.7 years, respectively. Restricted Stock Units Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost is measured based on the grant date fair value of the restricted stock unit issued. The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three The following table summarizes our unvested restricted stock unit activity: Shares Weighted Average Grant Date Fair Value (per share) Unvested at December 31, 2022 790,668 $ 53.72 Granted 620,002 86.10 Vested (295,370) 53.46 Forfeited (27,922) 69.14 Undistributed vested awards (a) (222,573) 80.52 Unvested at December 31, 2023 864,805 $ 69.42 __________ (a) Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2023 and 2022. The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units vested: December 31, 2023 (a) December 31, 2022 (a) Weighted average grant date fair value (per share) $ 86.10 $ 54.17 Total fair value of restricted stock units vested 34 35 __________ (a) As of December 31, 2023 and 2022, $35 million and $27 million of total unrecognized compensation costs related to unvested restricted stock units are expected to be recognized over the remaining weighted-average period of 1.9 years and 2.0 years. |
Variable Interest Entities
Variable Interest Entities | 12 Months Ended |
Dec. 31, 2023 | |
Variable Interest Entity [Abstract] | |
Variable Interest Entities | Variable Interest Entities As of December 31, 2023 and 2022, we consolidated several VIEs or VIE groups for which we are the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which we do not have the power to direct the entities’ activities and, accordingly, we were not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles. Consolidated VIEs The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements as of December 31, 2023 and 2022. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnotes to the table below, are such that creditors, or beneficiaries, do not have recourse to our general credit. December 31, 2023 December 31, 2022 Cash and cash equivalents $ 48 $ 51 Restricted cash and cash equivalents 47 46 Accounts receivable Customer 19 20 Other 10 9 Inventories, net Materials and supplies 14 12 Other current assets 1,249 549 Total current assets 1,387 687 Property, plant and equipment, net 1,979 1,965 Other noncurrent assets 166 190 Total noncurrent assets 2,145 2,155 Total assets (a) $ 3,532 $ 2,842 Long-term debt due within one year $ 63 $ 60 Accounts payable 11 17 Accrued expenses 20 23 Other current liabilities — 2 Total current liabilities 94 102 Long-term debt 704 764 Asset retirement obligations 190 173 Other noncurrent liabilities 2 3 Total noncurrent liabilities 896 940 Total liabilities (b) $ 990 $ 1,042 _______ (a) Our balances include unrestricted assets f or current unamortized energy contract assets of $22 million and $23 million, disclosed within other current assets in the table above and noncurrent unamortized energy contract assets of $155 million and $178 million, disclosed within other noncurrent assets in the table above as of December 31, 2023 and 2022, respectively. (b) As of December 31, 2023, our balance does not include any liabilities with recourse. Our balance includes liabilities with recourse of $1 million as of December 31, 2022 . As of December 31, 2023 and 2022, our consolidated VIEs included the following: Consolidated VIE or VIE groups: Reason entity is a VIE: Reason we are the primary beneficiary: CRP - A collection of wind and solar project entities. We have a 51% equity ownership in CRP. See additional discussion below. Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. We conduct the operational activities. Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by CRP. Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. We conduct the operational activities. Antelope Valley - A solar generating facility, which is 100% owned by us. Antelope Valley sells all of its output to PG&E through a PPA. The PPA contract absorbs variability through a performance guarantee. We conduct all activities. NER - A bankruptcy remote, special purpose entity which is 100% owned by us, which purchases certain of our customer accounts receivable arising from the sale of retail electricity. NER’s assets will be available first and foremost to satisfy the claims of the creditors of NER. Refer to Note 6 —Accounts Receivable for additional information on the sale of receivables. Equity capitalization is insufficient to support its operations. We conduct all activities. CRP - CRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by CRP. While we or CRP own 100% of the solar entities and 100% of the majority of the wind entities, it has been determined that the wholly owned solar and wind entities are VIEs because the entities' customers absorb price variability from the entities through fixed price power and/or REC purchase agreements. Additionally, for the wind entities that have minority interests, it has been determined that these entities are VIEs because the governance rights of some investors are not proportional to their financial rights. We are the primary beneficiary of these solar and wind entities that qualify as VIEs because we control operations and direct all activities of the facilities. There is limited recourse to us related to certain solar and wind entities. In 2017, our interests in CRP were contributed to and are pledged for the CR non-recourse debt project financing structure. Refer to Note 17 — Debt and Credit Agreements for additional information. Unconsolidated VIEs Our variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected in the Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in the Consolidated Balance Sheets that relate to our involvement with the VIEs are predominantly related to working capital accounts and generally represent the amounts owed by, or owed to, us for the deliveries associated with the current billing cycles under the commercial agreements. As of December 31, 2023 and 2022, we had significant unconsolidated variable interests in several VIEs for which we were not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements. The following table presents summary information about our significant unconsolidated VIE entities: December 31, 2023 December 31, 2022 Commercial Equity Total Commercial Equity Total Total assets (a) $ 704 $ — $ 704 $ 715 $ — $ 715 Total liabilities (a) 77 — 77 54 — 54 Other ownership interests in VIE (a) 627 — 627 661 — 661 __________ (a) These items represent amounts on the unconsolidated VIE balance sheets, not in the Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. We do not have any exposure to loss as we do not have a carrying amount in the equity investment VIEs as o f December 31, 2023 and 2022. As of December 31, 2023 and 2022, the unconsolidated VIEs consist of: Unconsolidated VIE groups: Reason entity is a VIE: Reason we are not the primary beneficiary: Equity investments in distributed energy companies. We have a 90% equity ownership in a distributed energy company. We sold this investment in the fourth quarter of 2022 resulting in it no longer being classified as an unconsolidated VIE . Similar structures to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. We do not conduct the operational activities. Energy Purchase and Sale agreements - We have several energy purchase and sale agreements with generating facilities. PPA contracts that absorb variability through fixed pricing. We do not conduct the operational activities. |
Supplemental Financial Informat
Supplemental Financial Information | 12 Months Ended |
Dec. 31, 2023 | |
Supplemental Financial Information [Abstract] | |
Supplemental Financial Information | Supplemental Financial Information Supplemental Statement of Operations Information The following tables provide additional information about material items recorded in the Consolidated Statements of Operations and Comprehensive Income. Taxes other than income taxes For the Years Ended December 31, 2023 2022 2021 Gross receipts (a) $ 139 $ 130 $ 99 Property 253 274 268 Payroll 142 130 109 __________ (a) Represent gross receipts taxes related to our retail operations. The offsetting collection of gross receipts taxes from customers is recorded in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Other, net For the Years Ended December 31, 2023 2022 2021 Decommissioning-related activities: Net realized income on NDT funds (a) Regulatory Agreement Units $ 657 $ 333 $ 817 Non-Regulatory Agreement Units 335 97 449 Net unrealized (losses) gains on NDT funds Regulatory Agreement Units 397 (1,354) 351 Non-Regulatory Agreement Units 259 (798) 209 Regulatory offset to NDT fund-related activities (b) (845) 820 (917) Total Decommissioning-related activities 803 (902) 909 Non-service net periodic benefit credit (c) 54 110 — Net realized and unrealized (losses) gains from equity investments (d) 307 (13) (160) Return to provision adjustment (e) 19 (49) — Other (f) 85 68 46 Total Other, net $ 1,268 $ (786) $ 795 __________ (a) Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments. (b) Includes the elimination of decommissioning-related activities and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning and the contractual offset suspension for the Byron units. (c) Prior to separation, we were allocated our portion of pension and OPEB non-service credits (costs) from Exelon, which was included in Operating and maintenance expense. Effective February 1, 2022, the non-service credit (cost) components are included in Other, net, in accordance with single employer plan accounting. See Note 15 — Retirement Benefits for additional information. (d) For 2023, includes unrealized gain resulting from equity investment that became publicly traded in the second quarter of 2023 and now has a readily determinable fair value (and no longer is accounted for as an equity method investment due to lack of significant influence). We recorded the fair value of this investment in Investments on the Consolidated Balance Sheets based on quoted market price of the stock. See Note 18 — Fair Value of Financial Assets and Liabilities for additional information. For 2022, represents Net realized and unrealized (losses) gains from equity investments. For 2021, represents Net unrealized (losses) gains from equity investments. (e) This reflects amounts contractually owed to Exelon under the TMA, which is offset in Income taxes. See Note 14 — Income Taxes for additional information. (f) Includes amounts we billed Exelon for services pursuant to the TSA. See Note 1 — Basis of Presentation for additional information. Supplemental Cash Flow Information The following tables provide additional information about material items recorded in the Consolidated Statements of Cash Flows. Depreciation, amortization and accretion For the Years Ended December 31, 2023 2022 2021 Property, plant, and equipment (a) $ 1,073 $ 1,065 $ 2,954 Amortization of intangible assets, net (a) 23 26 49 Amortization of energy contract assets and liabilities (b) 35 35 31 Nuclear fuel (c) 787 758 992 ARO accretion (d) 596 543 514 Total depreciation, amortization, and accretion $ 2,514 $ 2,427 $ 4,540 _________ (a) Included in Depreciation and amortization expense in the Consolidated Statements of Operations and Comprehensive Income. (b) Included in Operating revenues or Purchased power and fuel expense in the Consolidated Statements of Operations and Comprehensive Income. (c) Included in Purchased power and fuel expense in the Consolidated Statements of Operations and Comprehensive Income. (d) Included in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Cash paid during the year For the Years Ended December 31, 2023 2022 2021 Interest (net of amount capitalized) $ 264 $ 230 $ 275 Income taxes (net of refunds) 466 287 426 Other non-cash operating activities CEG Parent Constellation For the Years Ended December 31, For the Years Ended December 31, 2023 2022 2021 2023 2022 2021 Pension and non-pension postretirement benefit costs $ 47 $ 17 $ 123 $ 47 $ 17 $ 123 Other decommissioning-related activity (a) (534) (263) (946) (534) (263) (946) Energy-related options (b) 183 293 125 183 293 125 Asset impairments 71 — 545 71 — 545 (Gain) loss on sale of assets and businesses (27) (1) (201) (27) (1) (201) Severance costs 2 (1) (73) 2 (1) (73) Long-term incentive plan 57 44 — — — — Amortization of operating ROU asset 64 75 119 64 75 119 (Gain) loss on sale of receivables 75 69 36 75 69 36 __________ (a) Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning and the contractual offset suspension for the Byron units. (b) Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. The following table provides a reconciliation of cash, restricted cash, and cash equivalents reported in the Consolidated Balance Sheets that sum to the total of the same amounts in the Consolidated Statements of Cash Flows. December 31, 2023 CEG Parent Constellation Cash and cash equivalents $ 368 $ 366 Restricted cash and cash equivalents 86 74 Total cash, restricted cash, and cash equivalents $ 454 $ 440 December 31, 2022 CEG Parent Constellation Cash and cash equivalents $ 422 $ 403 Restricted cash and cash equivalents 106 98 Total cash, restricted cash, and cash equivalents $ 528 $ 501 December 31, 2021 CEG Parent Constellation Cash and cash equivalents $ 504 $ 504 Restricted cash and cash equivalents 72 72 Total cash, restricted cash, and cash equivalents $ 576 $ 576 For additional information on restricted cash, see Note 1 — Basis of Presentation. Supplemental Balance Sheet Information The following tables provide additional information about material items recorded in the Consolidated Balance Sheets. Investments December 31, 2023 December 31, 2022 Equity method investments (a) $ 7 $ 82 Other investments: Employee benefit trusts and investments (b) 82 68 Equity investments with readily determinable fair values (a)(c) 369 — Equity investments without readily determinable fair values 103 46 Other available for sale debt security investments 2 6 Total investments $ 563 $ 202 __________ (a) An investment previously classified as an equity method investment became publicly traded in the second quarter of 2023 and now has a readily determinable fair value. We recorded the fair value of this investment in Investments on the Consolidated Balance Sheets based on quoted market price of the stock. See Note 18 — Fair Value of Financial Assets and Liabilities for additional information. (b) Debt and equity security investments are recorded at fair market value. (c) Does not include the equity investments with readily determinable fair values that are recorded in Other current assets in the Consolidated Balance Sheets. See Note 18 — Fair Value of Financial Assets and Liabilities for additional information on Investments in equities. Accounts payable and accrued expenses December 31, 2023 CEG Parent Constellation Accounts payable $ 1,302 $ 1,289 Compensation-related accruals (a) 680 576 Taxes accrued 399 390 Accounts payable and accrued expenses December 31, 2022 CEG Parent Constellation Accounts payable $ 2,828 $ 2,810 Compensation-related accruals (a) 540 502 Taxes accrued 257 257 __________ (a) Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2023 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions Prior to completion of the separation on February 1, 2022, we engaged in transactions with affiliates of Exelon in the normal course of business, these affiliate transactions are summarized in the tables below. After February 1, 2022, all transactions with Exelon or its affiliates are no longer related party transactions. Operating revenues from affiliates The following table presents our Operating revenues from affiliates: For the Years Ended December 31, 2022 (a) 2021 ComEd (b) $ 58 $ 376 PECO (c) 33 196 BGE (d) 18 236 PHI 51 366 Pepco (e) 39 270 DPL (f) 10 79 ACE (g) 2 17 Other — 14 Total operating revenues from affiliates $ 160 $ 1,188 __________ (a) Represents only January 2022 costs prior to separation on February 1, 2022. (b) We have an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. We also sell RECs and ZECs to ComEd. (c) We provide electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, we have a ten-year agreement with PECO to sell solar AECs. (d) We provide a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. (e) We provide electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC. (f) We provide a portion of DPL's energy requirements under its MDPSC and DEPSC approved market-based SOS commodity programs. (g) We provide electric supply to ACE under contracts executed through ACE's competitive procurement process. Service Company Costs for Corporate Support We received a variety of corporate support services from Exelon. Through its business services subsidiary, BSC, Exelon provided support services at cost, including legal, human resources, financial, information technology, and supply management services. The costs of BSC were directly charged or allocated to us. Certain of these services continue after the separation and are covered by the TSA. See Note 1 — Basis of Presentation for additional information. The operating and maintenance service company costs from affiliates allocated to us prior to separation were $44 million and $588 million for the years ended December 31, 2022 and 2021, respectively. The capitalized service company costs allocated to us prior to separation were $15 million and $129 million for the years ended December 31, 2022 and 2021, respectively. |
Schedule II - Valuation and Qua
Schedule II - Valuation and Qualifying Accounts | 12 Months Ended |
Dec. 31, 2023 | |
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract] | |
Valuation and Qualifying Accounts | Constellation Energy Corporation and Subsidiary Companies Constellation Energy Generation, LLC and Subsidiary Companies Schedule II – Valuation and Qualifying Accounts Additions and adjustments Description Balance at Charged to Charged Deductions Balance at (In millions) For the year ended December 31, 2023 Allowance for credit losses $ 51 $ 25 $ — $ (15) (a) $ 61 Deferred tax valuation allowance 11 — (1) — 10 Reserve for obsolete materials 238 8 9 (9) 246 For the year ended December 31, 2022 Allowance for credit losses $ 59 $ 10 $ — $ (18) (a) $ 51 Deferred tax valuation allowance 22 — (11) — 11 Reserve for obsolete materials 250 11 (6) (17) 238 For the year ended December 31, 2021 Allowance for credit losses $ 32 $ 34 $ — $ (7) (a) $ 59 Deferred tax valuation allowance 23 — (1) — 22 Reserve for obsolete materials 265 (6) (b) (2) (7) 250 __________ (a) Write-offs, net of recoveries of individual accounts receivable. (b) Primarily reflects expense resulting from materials and supplies inventory reserve adjustments as a result of the decision to early retire Byron, Dresden, and Mystic 8 and 9. See Note 7—Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information. |
Basis of Presentation (Policies
Basis of Presentation (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation On February 21, 2021, the Board of Directors of Exelon authorized management to pursue a plan to separate its competitive generation and customer-facing energy businesses, conducted through Constellation Energy Generation, LLC ( “ Constellation ” , formerly Exelon Generation Company, LLC) and its subsidiaries, into an independent, publicly-traded company. CEG Parent, a direct, wholly owned subsidiary of Exelon, was newly formed for the purpose of separation and had not engaged in any business activities nor had any assets or liabilities prior to the separation. On February 1, 2022, the separation was completed and CEG Parent holds all the interests in Constellation previously held by Exelon. As an individual registrant, Constellation has historically filed consolidated financial statements to reflect its financial position and operating results as a stand-alone, wholly owned subsidiary of Exelon. The accompanying Consolidated Financial Statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC. The Consolidated Financial Statements include the accounts of our subsidiaries and all intercompany transactions have been eliminated. CEG Parent's prior period financial statements have been adjusted to reflect the balances of Constellation in accordance with applicable guidance. Amounts disclosed relate to CEG Parent and Constellation unless specifically noted as relating to CEG Parent only. Unless otherwise indicated or the context otherwise requires, references herein to the terms “we,” “us,” and “our” refer collectively to CEG Parent and Constellation. We own 100% of our significant consolidated subsidiaries, either directly or indirectly, except for certain consolidated VIEs, including CRP, of which we hold a 51% interest. The remaining interests in the consolidated VIEs are included in noncontrolling interests on the Consolidated Balance Sheets. See Note 22 — Variable Interest Entities for additional information on consolidated VIEs. We consolidate the accounts of entities in which we have a controlling financial interest, after the elimination of intercompany transactions. Where we do not have a controlling financial interest in an entity, proportionate consolidation, equity method accounting or accounting for investments in equity securities with or without readily determinable fair value is applied. We apply proportionate consolidation when we have an undivided interest in an asset and are proportionately liable for our share of each liability associated with the asset. We proportionately consolidate our undivided ownership interest in jointly owned electric plants. Under proportionate consolidation, we separately record our proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. See Note 9 — Jointly Owned Electric Plant for additional information on application of proportionate consolidation. We apply equity method accounting when we have a significant influence over an investee through an ownership in equity, which generally approximates a 20% to 50% voting interest. We apply equity method accounting to certain investments and joint ventures. Under equity method accounting, we report our interest in the entity as an investment and our percentage share of the earnings from the entity as single line items in our consolidated financial statements. We use accounting for investments in equity securities with or without readily determinable fair values if we lack a significant influence, which generally results when we hold less than 20% of the common stock of an entity. Under accounting for investments in equity securities with readily determinable fair values, the investments are reported based on quoted prices in active markets and realized and unrealized gains and losses are included in earnings. Under accounting for investments in equity securities without readily determinable fair values, the investments are reported at cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment, and changes in measurement are reported in earnings. |
Separation from Parent | Separation from Exelon On February 1, 2022, Exelon completed the separation through a pro-rata distribution of all of the outstanding shares of our common stock, no par value, on the basis of one such share for every three shares of Exelon common stock held on January 20, 2022, the record date of the distribution. We are an independent, publicly traded company listed on the Nasdaq Stock Market under the symbol “CEG”, and regular-way trading began on February 2, 2022. Exelon no longer retains any ownership interest in CEG Parent or Constellation. Prior to completion of the separation, our financial statements include certain transactions with affiliates of Exelon, which are disclosed as related party transactions. After February 1, 2022, all transactions with Exelon or its affiliates are no longer related party transactions. In order to govern the ongoing relationships with Exelon after the separation, and to facilitate an orderly transition, we entered into several agreements with Exelon, including the following: • Separation Agreement – sets forth the principal actions to be taken in connection with the separation, including the transfer of assets and assumption of liabilities and establishes certain rights and obligations between us following the distribution • Transition Services Agreement (TSA) – governs all matters relating to the provision of services between us and Exelon on a transitional basis, in addition to providing us with certain services for an expected period of two-years, provided that certain services may be longer than the term and services may be extended with approval from both parties; the services include support for information technology, accounting, finance, human resources, security, and various other administrative and operational services • Employee Matters Agreement (EMA) – addresses certain employment, compensation and benefits matters, including the allocation of employees between us and Exelon and the allocation and treatment of certain assets and liabilities relating to our employees and former employees • Tax Matters Agreement (TMA) - governs the respective rights, responsibilities, and obligations between us and Exelon with respect to all tax matters (excluding employee-related taxes covered under EMA), in addition to certain restrictions which generally prohibit us from taking or failing to take any action in the two-year period following the distribution that would prevent the distribution from qualifying as tax-free for U.S. federal income tax purposes, including limitations on our ability to pursue certain equity issuances, strategic transactions, repurchases or other transactions |
Use of Estimates | Use of Estimates |
Revenues | Revenues Operating Revenues. Our operating revenues generally consist of revenues from contracts with customers involving competitive sales of power, natural gas, and other energy-related products and sustainable solutions. We recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that we expect to be entitled to in exchange for those goods or services. At the end of each reporting period, we accrue an estimate for the unbilled amount of power and natural gas delivered or services provided to customers. Commodity Derivatives. Derivative instruments are generally recorded at fair value with subsequent changes in fair value recognized as realized and unrealized revenue or expense. The classification of revenue or expense is based on the intent of the transaction. See Note 16 — Derivative Financial Instruments for additional information. |
Taxes Directly Imposed on Revenue-Producing Transactions | Taxes Directly Imposed on Revenue-Producing Transactions. We collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges and fees, that are levied by state or local governments on the sale or distribution of electricity and natural gas and any taxable energy-related products and services. Some of these taxes are imposed on the customer, but paid by us, while others are imposed on us. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis in revenues. However, where these taxes are imposed on us, such as gross receipts taxes, they are reported on a gross basis in expense. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense in Taxes other than income taxes in the Consolidated Statements of Operations and Comprehensive Income. Se e Note 23 — Supplemental Financial Information for the taxes that are presented on a gross basis. |
Leases | Leases We recognize a ROU asset and lease liability for operating leases with a term of greater than one year. Operating lease ROU assets are included in Other deferred debits and other assets and operating lease liabilities are included in Other current liabilities and Other deferred credits and other liabilities on the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using the rate implicit in the lease whenever that is readily determinable or our incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received) and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. We include non-lease components for most asset classes, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability. Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred and consist primarily of payments for purchases of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease expense and variable lease payments are recorded to Purchased power and fuel expense for contracted generation or Operating and maintenance expense for all other lease agreements in the Consolidated Statements of Operations and Comprehensive Income. Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease payments are recognized in the period in which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Our operating leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. We generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all the economic benefits. We generally do not account for contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. We account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. See Note 11 — Leases for additional information. |
Income Taxes | Income Taxes Deferred federal and state income taxes are recorded on temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. ITCs have been deferred in the Consolidated Balance Sheets and are recognized in book income over the life of the related property. We account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. We recognize accrued interest related to unrecognized tax benefits in Interest expense, net or Other, net (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in the Consolidated Statements of Operations and Comprehensive Income. |
Cash and Cash Equivalents | Cash and Cash Equivalents We consider investments purchased with an original maturity of three months or less to be cash equivalents. Restricted Cash and Cash Equivalents Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2023 and 2022, restricted cash and cash equivalents primarily represented the payment of medical, dental, vision, and long-term disability benefits and project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities. See Note 17 — Debt and Credit Agreements and Note 23 — Supplemental Financial Information for additional information. |
Allowance for Credit Losses on Accounts Receivables | Allowance for Credit Losses on Accounts Receivables The allowance for credit losses reflects our best estimate of losses on the customers' accounts receivable balances based on historical experience, current information, and reasonable and supportable forecasts. The allowance for credit losses for our retail customers is based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. The allowance for credit losses for our wholesale customers is developed using a credit monitoring process, like that used for retail customers. When a wholesale customer’s risk characteristics are no longer aligned with the pooled population, we use specific identification to develop an allowance for credit losses. Adjustments to the allowance for credit losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. |
Variable Interest Entities | Variable Interest Entities We account for our investments in and arrangements with VIEs based on the following specific requirements: • qualitative assessment of factors determinant in whether we have a controlling financial interest, • ongoing reconsideration of this assessment, and • where we consolidate a VIE (as primary beneficiary), disclosure of (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary. See Note 22 — Variable Interest Entities for additional information. |
Inventories | Inventories Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Natural gas, oil, materials and supplies, and emissions allowances are generally included in inventory when purchased. Natural gas, oil, and emissions allowances are expensed to Purchased power and fuel expense when consumed. Materials and supplies generally include items utilized within our generating plants and are expensed to Operating and maintenance or capitalized to Property, plant and equipment, as appropriate, when installed or used. |
Debt and Equity Security Investments | Debt and Equity Security Investments Debt and Equity Investments within NDT funds. We have debt and equity securities held in our NDT funds which are measured and recorded at fair value. Realized and unrealized gains and losses, net of trust level taxes, on our NDT funds associated with the Regulatory Agreement Units are offset in Noncurrent payables related to Regulatory Agreement Units. Realized and unrealized gains and losses, net of trust level taxes, on our NDT funds associated with the Non-Regulatory Agreement Units are included in Other, net in the Consolidated Statements of Operations and Comprehensive Income. For equity securities without readily determinable fair values, we have elected to use the measurement alternative to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Our NDT funds are classified as current or noncurrent assets, depending on the timing of the decommissioning activities and income taxes on trust earnings. See Note 18 — Fair Value of Financial Assets and Liabilities and Note 10 — Asset Retirement Obligations for additional information. Equity Security Investments with Readily Determinable Fair Values. We have certain equity securities with readily determinable fair values. Realized and unrealized gains and losses are included in Other, net in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Fair Value of Financial Assets and Liabilities for additional information. Equity Security Investments without Readily Determinable Fair Values. We have certain equity securities without readily determinable fair values. We have elected to use the measurement alternative to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Changes in measurement are reported in Other, net in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Fair Value of Financial Assets for additional information. |
Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment is recorded at acquired cost. Acquired cost includes construction-related direct labor and material costs. When appropriate, acquired cost also includes capitalized interest. Costs associated with nuclear outages and planned major maintenance activities, are expensed to Operating and maintenance expense or capitalized to Property, plant, and equipment based on the nature of the activities in the period incurred. The cost of repairs and maintenance and minor replacements of property is charged to Operating and maintenance expense as incurred. Upon retirement, the cost of property is generally charged to accumulated depreciation in accordance with the composite and group methods of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to Operating and maintenance expense as incurred. Certain assets follow the unitary method of depreciation and recognize gains and losses in the period of replacement or retirement. These gains and losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized in Property, plant and equipment in the Consolidated Balance Sheets. Similar costs incurred for cloud-based solutions treated as service arrangements are capitalized in Other current assets and Deferred debits and other assets in the Consolidated Balance Sheets. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Capitalized Interest. During construction, we capitalize the costs of debt funds. Most projects will use a debt rate calculated using the general corporate debt pool. In some cases, projects are specifically financed and use a project specific debt rate, which is excluded from the general corporate debt pool. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense. See Note 8 — Property, Plant, and Equipment, Note 9 — Jointly Owned Electric Plant and Note 23 — Supplemental Financial Information for additional information. |
Nuclear Fuel | Nuclear Fuel The cost of nuclear fuel is capitalized in Property, plant and equipment and charged to Purchased power and fuel using the unit-of-production method. Any potential future SNF disposal fees will also be expensed through Purchased power and fuel expense. Additionally, certain on-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 19 — Commitments and Contingencies for additional information regarding the cost of SNF storage and disposal. |
Depreciation and Amortization | Depreciation and Amortization Except for the amortization of nuclear fuel, depreciation, inclusive of ARC, is generally recorded over the estimated service lives of property, plant and equipment on a straight-line basis using the group, composite or unitary methods of depreciation. Two methods of depreciating multiple asset groups exist: the group method and the composite method. The group method is typically for groups of assets that are largely homogenous and have approximately the same useful lives. The composite method is used when the assets are heterogeneous and have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimated service lives are based on a combination of depreciation studies, historical retirements, site licenses and management estimates of operating costs and expected future energy market conditions. See Note 7 — Early Plant Retirements for additional information on the impacts of early plant retirements, Note 8 — Property, Plant, and Equipment for additional information regarding depreciation, and Note 23 — Supplemental Financial Information for additional information regarding nuclear fuel. |
Asset Retirement Obligations | Asset Retirement Obligations We estimate and recognize a liability for our legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. We generally update our nuclear decommissioning ARO annually, unless circumstances warrant more frequent updates, based on our annual evaluation of cost escalation factors and probabilities assigned to the multiple outcome scenarios within our probability-weighted discounted cash flow models. Our multiple outcome scenarios are generally based on decommissioning cost studies which are updated, on a rotational basis, for each of our nuclear units at least every five years, unless circumstances warrant more frequent updates. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income for Non-Regulatory Agreement Units and through an offsetting decrease in noncurrent payables related to Regulatory Agreement Units. See Note 10 — Asset Retirement Obligations for additional information. |
Accounting Implications of the Regulatory Agreement Units | Accounting Implications of the Regulatory Agreement Units Based on the requirements of the ICC, PAPUC, and PUCT that dictate our obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd, former PECO, and STP units, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation are generally offset in the Consolidated Statements of Operations and Comprehensive Income and are recorded as noncurrent payables in the Consolidated Balance Sheets (within Payables related to Regulatory Agreement Units). See Note 10 — Asset Retirement Obligations for additional information. |
Asset Impairments | Asset Impairments Long-Lived Assets. We regularly monitor and evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. We determine if long-lived assets or asset groups are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. Generally, pre-tax impairment losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. See Note 12 — Asset Impairments for additional information. Goodwill. Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or in an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 2 — Mergers, Acquisitions, and Dispositions and Note 13 — Intangible Assets for additional information. Equity Method Investments. We regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature. Additionally, if the entity in which we hold an investment recognizes an impairment loss, we would record their proportionate share of that impairment loss and evaluate the investment for an other-than-temporary decline in value. These impairment losses are recorded in Equity in (losses) earnings of unconsolidated affiliates in the Consolidated Statements of Operations and Comprehensive Income. Equity Security Investments. Equity investments with readily determinable fair values are measured and recorded at fair value with any changes in fair value recorded in Other, net in the Consolidated Statements of Operations and Comprehensive Income. Investments in equity securities without readily determinable fair values are qualitatively assessed for impairment each reporting period. If it is determined that the equity security is impaired, an impairment loss will be recognized in Other, net in the Consolidated Statements of Operations and Comprehensive Income to the amount by which the security’s carrying amount exceeds its fair value. |
Derivative Financial Instruments | Derivative Financial Instruments All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including NPNS. For derivatives intended to serve as economic hedges, changes in fair value are recognized in earnings each period. Amounts classified in earnings are included in Operating revenues, Purchased power and fuel, or Interest expense in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. While most of the derivatives serve as economic hedges, there are also derivatives entered into for proprietary trading purposes, subject to our RMP, and changes in the fair value of those derivatives are recorded in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. As part of the energy marketing business, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. NPNS are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as NPNS are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value. See Note 16 — Derivative Financial Instruments for additional information. |
Retirement Benefits | Retirement Benefits Prior to separation, Exelon sponsored defined benefit pension plans and OPEB plans as described in Note 15 — Retirement Benefits. The plan obligations and costs of providing benefits under these plans were measured as of December 31, 2021. We accounted for our participation in Exelon’s pension and OPEB plans by applying multi-employer accounting. Exelon allocated costs related to its pension and OPEB plans to its subsidiaries based on both active and retired employee participation in each plan. We included the service cost and non-service cost components in Operating and maintenance expense and Property, plant, and equipment, net in the consolidated financial statements. Effective upon separation, we sponsor defined benefit pension and OPEB plans as described in Note 15 — Retirement Benefits. The plan obligations and costs of providing benefits under these plans were measured upon separation as of February 1, 2022 and remeasured as of December 31, 2023 and 2022. The measurements involved various factors, assumptions, and accounting elections. The impact of assumption changes or experience different from that assumed on pension and OPEB obligations is recognized over time rather than immediately recognized in the Consolidated Statements of Operations and Comprehensive Income. Gains or losses more than the greater of ten percent of the PBO or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. Gains or losses more than the greater of ten percent of the APBO or the MRV of plan assets are amortized over the average future remaining lifetime of the current inactive population for the OPEB plans. We report the pension and OPEB service cost and non-service cost (credit) components of net periodic benefit costs (credits) for all plans separately in our Consolidated Statements of Operations and Comprehensive Income. Effective February 1, 2022 , the service cost component continues to be included in Operating and maintenance expense and Property, plant, and equipment, net (where criteria for capitalization of direct labor has been met) while the non-service cost (credit) components are included in Other, net, in accordance with single employer plan accounting. |
Mergers, Acquisitions, and Di_2
Mergers, Acquisitions, and Dispositions (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Mergers, Acquisitions, and Dispositions [Abstract] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the STP acquisition: Cash paid for purchase price $ 1,654 Identifiable assets acquired and liabilities assumed Property, plant, and equipment 1,254 Nuclear decommissioning trust funds 869 Inventories, net 47 Other long-term assets 40 Other current assets 11 Total assets 2,221 Asset retirement obligations 429 Payables related to Regulatory Agreement Units 376 Deferred income taxes and unamortized investment tax credits 65 Accounts payable and accrued expenses 45 Pension and OPEB obligations 25 Other long-term liabilities 5 Total liabilities 945 Total net identifiable assets, at fair value 1,276 Goodwill $ 378 |
Schedule of Changes in Ownership Interest | The following table summarizes the effects of the changes in our ownership interest in CENG in Member's Equity: For the Year Ended December 31, 2021 Net loss attributable to membership interest $ (205) Pre-tax increase in membership interest for purchase of EDF's 49.99% equity interest (a) 1,080 Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest (a) (288) Change from net loss attributable to membership interest and transfers from noncontrolling interest $ 587 __________ (a) Represents non-cash activity in the consolidated financial statements. |
Revenue from Contracts with C_2
Revenue from Contracts with Customers (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Revenue from Contract with Customer [Abstract] | |
Contract with Customer, Contract Asset, Contract Liability, and Receivable | The following table provides a rollforward of the contract assets reflected in the Consolidated Balance Sheets: 2023 2022 Beginning balance as of January 1 $ 130 $ 149 Amounts reclassified to receivables (127) (81) Revenues recognized 79 62 Ending balance as of December 31 $ 82 $ 130 The following table provides a rollforward of the contract liabilities reflected in the Consolidated Balance Sheets: 2023 2022 2021 Beginning balance as of January 1 $ 47 $ 75 $ 84 Consideration received or due 331 339 251 Revenues recognized (338) (367) (263) Contract liabilities reclassified as held for sale — — 3 Ending balance as of December 31 $ 40 $ 47 $ 75 |
Contract with Customer, Prior Year Contract Revenues Recognized in Current Year | The following table reflects revenues recognized in the years ended December 31, 2023, 2022 and 2021, which were included in contract liabilities at December 31, 2022, 2021, and 2020, respectively: 2023 2022 2021 Revenues recognized $ 26 $ 71 $ 82 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2023. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years. This disclosure excludes mark-to-market derivatives and certain power and gas sales contracts which contain variable volumes and/or variable pricing. 2024 2025 2026 2027 2028 and thereafter Total Remaining performance obligations $ 152 $ 44 $ 20 $ 18 $ 130 $ 364 |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Segment Reporting [Abstract] | |
Revenue from External Customers by Geographic Areas | The following tables disaggregate the revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. The disaggregation of revenues reflects our two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. The following tables also show the reconciliation of reportable segment revenues and RNF to our total revenues and RNF for the years ended December 31, 2023, 2022, and 2021. 2023 Revenues from external customers Contracts with customers Other (a) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 5,453 $ (265) $ 5,188 $ (50) $ 5,138 Midwest 4,846 (191) 4,655 3 4,658 New York 1,910 56 1,966 55 2,021 ERCOT 1,232 109 1,341 5 1,346 Other Power Regions 4,956 908 5,864 (13) 5,851 Total Reportable Segment Power Revenues 18,397 617 19,014 — 19,014 Total Natural Gas Revenues 1,859 1,866 3,725 — 3,725 Total Other Revenues (b) 585 1,594 2,179 — 2,179 Total Consolidated Operating Revenues $ 20,841 $ 4,077 $ 24,918 $ — $ 24,918 2022 Revenues from external customers (c) Contracts with customers Other (a) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 5,264 $ (105) $ 5,159 $ 5 $ 5,164 Midwest 5,164 (507) 4,657 (7) 4,650 New York 2,004 (408) 1,596 (1) 1,595 ERCOT 954 602 1,556 (13) 1,543 Other Power Regions 5,035 1,681 6,716 16 6,732 Total Reportable Segment Power Revenues 18,421 1,263 19,684 — 19,684 Total Natural Gas Revenues 2,559 2,408 4,967 — 4,967 Total Other Revenues (b) 591 (802) (211) — (211) Total Consolidated Operating Revenues $ 21,571 $ 2,869 $ 24,440 $ — $ 24,440 2021 Revenues from external customers (c) Contracts with customers Other (a) Total Intersegment Revenues Total Revenues Mid-Atlantic $ 4,381 $ 183 $ 4,564 $ 20 $ 4,584 Midwest 4,265 (205) 4,060 — 4,060 New York 1,633 (57) 1,576 (1) 1,575 ERCOT 896 276 1,172 9 1,181 Other Power Regions 3,937 981 4,918 (28) 4,890 Total Reportable Segment Power Revenues 15,112 1,178 16,290 — 16,290 Total Natural Gas Revenues 1,777 1,602 3,379 — 3,379 Total Other Revenues (b) 365 (385) (20) — (20) Total Consolidated Operating Revenues $ 17,254 $ 2,395 $ 19,649 $ — $ 19,649 __________ (a) Includes revenues from derivatives and leases. (b) Represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $1,399 million and losses of $1,188 million, and $633 million for the years ended December 31, 2023, 2022, and 2021, respectively. (c) Includes all wholesale and retail electric sales to third parties and affiliated sales to Exelon's utility subsidiaries prior to the separation on February 1, 2022. See Note 24 — Related Party Transactions for additional information. 2023 2022 2021 RNF from external Intersegment Total RNF from external (b) Intersegment Total RNF from external (b) Intersegment Total Mid-Atlantic $ 2,972 $ (48) $ 2,924 $ 2,129 $ 9 $ 2,138 $ 2,247 $ 17 $ 2,264 Midwest 3,252 3 3,255 2,765 (1) 2,764 2,717 — 2,717 New York 1,189 62 1,251 1,061 6 1,067 1,151 10 1,161 ERCOT 588 (6) 582 503 (96) 407 (668) (157) (825) Other Power Regions 1,270 (30) 1,240 952 (31) 921 984 (93) 891 Total RNF for Reportable Segments 9,271 (19) 9,252 7,410 (113) 7,297 6,431 (223) 6,208 Other (a) (354) 19 (335) (432) 113 (319) 1,055 223 1,278 Total RNF $ 8,917 $ — $ 8,917 $ 6,978 $ — $ 6,978 $ 7,486 $ — $ 7,486 __________ (a) Other represents activities not allocated to a region. See text above for a description of included activities. Primarily includes: • Unrealized mark-to-market losses of $972 million and $1,013 million and gains of $565 million for the years ended December 31, 2023, 2022, and 2021, respectively; and • Accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 7 - Early Plant Retirements of $148 million for the year ended December 31, 2021. (b) Includes purchases and sales from/to third parties and affiliated sales to Exelon's utility subsidiaries prior to the separation on February 1, 2022. See Note 24 — Related Party Transactions for additional information. |
Accounts Receivable (Tables)
Accounts Receivable (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Receivables [Abstract] | |
Purchases and Sales of Accounts Receivable | The following table summarizes the impact of the sale of certain receivables: As of December 31, 2023 2022 Derecognized receivables transferred at fair value $ 1,516 $ 1,615 Less: Cash proceeds received 300 1,100 DPP $ 1,216 $ 515 For the Years Ended December 31, 2023 2022 2021 Loss on sale of receivables (a) $ 75 $ 69 $ 36 _________ (a) Reflected in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. This represents the amount by which the accounts receivable sold into the Facility are discounted, limited to credit losses. For the Years Ended December 31, 2023 2022 2021 Proceeds from new transfers (a) $ 3,649 $ 6,108 $ 6,095 Cash collections received on DPP and reinvested in the Facility (b) 8,140 4,764 3,502 Cash collections reinvested in the Facility $ 11,789 $ 10,872 $ 9,597 _________ (a) Customer accounts receivable sold into the Facility were $11,746 million, $11,274 million, and $9,747 million for the years ended December 31, 2023, 2022, and 2021, respectively. (b) Does not include the $800 million net cash payments to the Purchasers in 2023, the $200 million net cash proceeds received from the Purchasers in 2022, or $400 million cash proceeds received from the Purchases in 2021. For the Years Ended December 31, 2023 2022 2021 Total receivables sold $ 356 $ 423 $ 147 |
Early Plant Retirements (Tables
Early Plant Retirements (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Implications of Potential Early Plant Retirements [Abstract] | |
Restructuring and Related Costs | The total impact for the year ended December 31, 2021 in the Consolidated Statements of Operations and Comprehensive Income resulting from the initial decision and subsequent reversal of the decision to early retire Byron and Dresden is summarized in the table below: Income statement expense (pre-tax) For the Year Ended December 31, 2021 Depreciation and amortization Accelerated depreciation (a) $ 1,805 Accelerated nuclear fuel amortization 148 Operating and maintenance One-time charges (94) Other charges 9 Contractual offset (b) (451) Total $ 1,417 _________ (a) Includes the accelerated depreciation of plant assets including any ARC. (b) Reflects contractual offset for ARO accretion, ARC depreciation, ARO remeasurement, and excludes any changes in earnings in the NDT funds. Decommissioning-related impacts were not offset for the Byron units starting in the second quarter of 2021 due to the inability to recognize a regulatory asset at ComEd. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. Based on the regulatory agreement with the ICC, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income as long as the net cumulative decommissioning-related activity result in a regulatory liability at ComEd. The offset resulted in an equal adjustment to the noncurrent payables to ComEd. See Note 10 - Asset Retirement Obligations for additional information. |
Property, Plant, and Equipment
Property, Plant, and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant, and Equipment | The following table presents a summary of property, plant, and equipment by asset category as of December 31, 2023 and 2022: Asset Category December 31, 2023 December 31, 2022 Electric $ 32,889 $ 30,804 Nuclear fuel (a) 5,503 5,106 Construction work in progress 1,133 630 Other property, plant, and equipment 14 8 Total property, plant, and equipment 39,539 36,548 Less: accumulated depreciation (b) 17,423 16,726 Property, plant, and equipment, net $ 22,116 $ 19,822 __________ (a) Includes nuclear fuel that is in the fabrication and installation phase of $1,265 million and $937 million as of December 31, 2023 and 2022, respectively. (b) Includes accumulated amortization of nuclear fuel in the reactor core of $2,484 million and $2,657 million as of December 31, 2023 and 2022, respectively. The following table presents the average service life for each asset category in number of years: Asset Category Average Service Life (years) Electric 1-60 Nuclear fuel 1-8 Other property, plant, and equipment 1-10 |
Jointly Owned Electric Plant (T
Jointly Owned Electric Plant (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Public Utilities, Property, Plant and Equipment [Abstract] | |
Schedule of Jointly Owned Utility Plants | Our material undivided ownership interests in jointly owned nuclear plants as of December 31, 2023 and 2022 were as follows: Nuclear Generation Quad Cities Peach Salem Nine Mile Point Unit 2 South Texas Project Operator Constellation Constellation PSEG Nuclear Constellation STPNOC Ownership interest 75.00 % 50.00 % 42.59 % 82.00 % 44.00 % Our share as of December 31, 2023 Plant in service $ 1,263 $ 1,552 $ 781 $ 1,073 $ 1,089 Accumulated depreciation 805 689 357 292 5 Construction work in progress 8 14 49 35 13 Our share as of December 31, 2022 Plant in service $ 1,243 $ 1,534 $ 772 $ 1,063 $ — Accumulated depreciation 761 659 328 256 — Construction work in progress 7 12 23 26 — |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligation Rollforward | The following table provides a rollforward of the nuclear decommissioning AROs reflected in the Consolidated Balance Sheets from January 1, 2022 to December 31, 2023: 2023 2022 Beginning balance as of January 1 $ 12,500 $ 12,676 Net increase (decrease) due to changes in, and timing of, estimated future cash flows 411 (648) Accretion expense 582 532 Acquisition of joint ownership in STP (b) 429 — Costs incurred related to decommissioning plants (31) (60) Ending balance as of December 31 (a) $ 13,891 $ 12,500 __________ (a) Includes $30 million and $40 million as the current portion of the ARO as of December 31, 2023 and 2022, respectively, which is included in Other current liabilities in the Consolidated Balance Sheets. (b) Reflects our estimated share of the STP decommissioning obligation. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. The following table provides a rollforward of the non-nuclear AROs reflected in the Consolidated Balance Sheets from January 1, 2022 to December 31, 2023: 2023 2022 Beginning balance as of January 1 $ 239 $ 216 Net increase due to changes in, and timing of, estimated future cash flows 14 18 Accretion expense 14 11 Asset divestitures (9) (1) Payments (1) (5) Ending balance as of December 31 $ 257 $ 239 . |
Related Party Transactions - Noncurrent Receivables from/Payables to Affiliates | The following table presents our noncurrent payables to ComEd and PECO, as well as CenterPoint Energy Houston Electric, LLC and AEP Texas, Inc. for STP, which are recorded as Payables related to Regulatory Agreement Units in the Consolidated Balance Sheets as of December 31, 2023 and 2022: As of December 31, 2023 2022 ComEd $ 2,955 $ 2,660 PECO 278 237 CenterPoint Energy Houston Electric, LLC 338 — AEP Texas, Inc. 117 — Payables related to Regulatory Agreement Units $ 3,688 $ 2,897 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Leases [Abstract] | |
Components of Lease Cost | The following table outlines other terms and conditions of the lease agreements as of December 31, 2023. We did not have material finance leases in 2023, 2022, or 2021. In Years Remaining lease terms 1-32 Options to extend the term 2-30 Options to terminate within 1 The components of operating lease costs were as follows: For the Years Ended December 31, 2023 2022 2021 Operating lease costs $ 96 $ 109 $ 161 Variable lease costs 146 169 168 Total lease costs (a) $ 242 $ 278 $ 329 __________ (a) Excludes $50 million, $49 million, $44 million of sublease income recorded for each of the years ended December 31, 2023, 2022, and 2021, respectively. The weighted average remaining lease terms, in years, and the weighted average discount rates for operating leases were as follows: As of December 31, 2023 2022 2021 Weighted average remaining lease term 8.4 9.3 10.1 Weighted average discount rate 5.0 % 5.0 % 5.0 % In Years Remaining lease terms 1-17 Options to extend the term 1-20 |
Supplemental Balance Sheet Information Related to Lessee Right-of-Use Assets and Lease Liabilities | The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities in the Consolidated Balance Sheets: As of December 31, 2023 2022 Operating lease ROU assets (a) Other deferred debits and other assets $ 494 $ 545 Operating lease liabilities (a) Other current liabilities 67 67 Other deferred credits and other liabilities 583 643 Total operating lease liabilities $ 650 $ 710 __________ (a) The operating ROU assets and lease liabilities include $212 million and $334 million, respectively, related to contracted generation as of December 31, 2023, and $248 million and $377 million, respectively, as of December 31, 2022. |
Lessee, Operating Lease, Liability, Maturity | The following table reconciles the undiscounted cash flows for our operating leases to the operating lease liabilities recorded on our consolidated balance sheet as of December 31, 2023: 2024 $ 101 2025 104 2026 104 2027 102 2028 103 Thereafter 325 Total lease payments 839 Less: Imputed interest 189 Operating lease liabilities $ 650 |
Lessee, Operating Lease, Supplemental Cash Flow Information | Supplemental cash flow information related to operating leases was as follows: For the Years Ended December 31, 2023 2022 2021 Cash paid for amounts included in the measurement of operating lease liabilities $ 102 $ 114 $ 162 ROU assets obtained in exchange for operating lease obligations 13 14 2 |
Components of Operating Lease Income | The components of lease income were as follows: For the Years Ended December 31, 2023 2022 2021 Operating lease income $ 51 $ 51 $ 47 Variable lease income 248 258 261 |
Lessor, Operating Lease, Payment to be Received, Fiscal Year Maturity | The following table presents maturity analysis of the lease payments we expect to receive as of December 31, 2023: 2024 $ 48 2025 48 2026 49 2027 49 2028 48 Thereafter 85 Total $ 327 |
Intangible Assets (Tables)
Intangible Assets (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule Of Goodwill | The following table presents the carrying amount of goodwill as of December 31, 2023 and 2022. There were no impairment losses during the years ended December 31, 2023, 2022, and 2021 . Goodwill Balance at December 31, 2022 $ 47 Goodwill resulting from acquisition of STP (a) 378 Balance at December 31, 2023 $ 425 __________ (a) See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. |
Schedule of Finite-Lived Intangible Assets | Our other intangible assets and liabilities, included in Other current assets, Other deferred debits and other assets, Other current liabilities, Other deferred credits and other liabilities in the Consolidated Balance Sheets, consisted of the following as of December 31, 2023 and 2022. The intangible assets and liabilities shown below are generally amortized on a straight line basis, except for unamortized energy contracts which are amortized in relation to the expected realization of the underlying cash flows: December 31, 2023 December 31, 2022 Gross Accumulated Amortization Net Gross Accumulated Amortization Net Unamortized Energy Contracts $ 1,892 $ (1,631) $ 261 $ 1,960 $ (1,708) $ 252 Customer Relationships 242 (167) 75 356 (265) 91 Total $ 2,134 $ (1,798) $ 336 $ 2,316 $ (1,973) $ 343 |
Schedule Of Finite-Lived Intangible Assets Amortization Expense | The following table summarizes the amortization expense related to our other intangible assets and liabilities for each of the years ended December 31, 2023, 2022, and 2021: For the Years Ended December 31, Amortization Expense (a) 2023 $ 58 2022 61 2021 80 __________ (a) See Note 23 — Supplemental Financial Information for additional information related to the amortization of unamortized energy contracts. |
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense | The following table summarizes the estimated future amortization expense related to our other intangible assets and liabilities as of December 31, 2023: For the Years Ending December 31, Estimated Future Amortization Expense 2024 $ 62 2025 58 2026 51 2027 37 2028 31 2029 and thereafter 97 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Tax Expense (Benefit) | Income taxes are comprised of the following components: For the Years Ended December 31, 2023 2022 2021 Federal Current $ 464 $ 219 $ 394 Deferred 301 (655) (153) ITC amortization (15) (15) (15) State Current 142 34 36 Deferred (33) 29 (37) Total income tax (benefit) expense $ 859 $ (388) $ 225 |
Effective Income Tax Rate Reconciliation | The effective income tax rate varies from the U.S. federal statutory rate principally due to the following: For the Years Ended December 31, 2023 (a) 2022 (b) 2021 (a) U.S. federal statutory rate 21.0 % 21.0 % 21.0 % (Decrease) increase due to: State income taxes, net of federal income tax benefit (c) 3.5 (9.2) — Qualified NDT fund income and losses 10.3 46.3 165.1 Amortization of investment tax credit, including deferred taxes on basis differences (0.5) 2.2 (9.0) Production tax credits and other credits (0.6) 7.7 (28.7) Noncontrolling interests 0.4 (0.3) (3.0) Other (d) 1.0 3.9 2.6 Effective income tax rate (e) 35.1 % 71.6 % 148.0 % _________ (a) Positive percentages represent income tax expense. Negative percentages represent income tax benefit. (b) As there was a pre-tax loss during 2022, negative percentages represent income tax expense. Positive percentages represent income tax benefit. (c) Includes ($4) million and $30 million related to state rate changes and certain state tax positions in 2023 and 2022, respectively. (d) Primarily related to disallowed excess officer compensation in 2023 and $32 million prior period income tax adjustment recorded in 2022. (e) The change in effective tax rate in 2023 is primarily due to the impacts of higher realized NDT Income and significant pretax income in 2023 compared to pretax loss in 2022. |
Tax Effects of Temporary Differences | The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2023 and 2022 are presented below: December 31, 2023 December 31, 2022 Plant basis differences $ (3,130) $ (3,005) Accrual-based contracts (32) (35) Derivatives and other financial instruments 984 43 Deferred pension and postretirement obligation (314) 287 Nuclear decommissioning activities (640) (371) Tax loss carryforward, net of valuation allowances 47 67 Tax credit carryforward — 179 Investment in partnerships (193) (205) Other, net 460 407 Deferred income tax liabilities (net) (2,818) (2,633) Unamortized ITCs (339) (354) Total deferred income tax liabilities (net) and $ (3,157) $ (2,987) |
Summary of Loss Carryforwards | The following table provides our carryforwards, of which the state-related items are presented on a post-apportioned basis, and any corresponding valuation allowances as of December 31, 2023: Federal December 31, 2023 Federal general business credits carryforwards and other carryforwards $ — Year in which net operating loss or credit carryforwards will begin to expire 2043 State State net operating losses and other carryforwards 477 Deferred taxes on state tax attributes (net) 21 Valuation allowance on state tax attributes (10) Foreign Foreign net operating losses and other carryforwards 145 Deferred taxes on foreign tax attributes (net) 36 |
Summary of Income Tax Examinations | Description of tax years open to assessment by major jurisdiction Major Jurisdiction Open Years (a) Federal consolidated income tax returns 2010-2022 Illinois unitary corporate income tax returns 2012-2022 New Jersey separate corporate income tax returns 2017-2018 New Jersey combined corporate income tax returns 2019-2022 New York combined corporate income tax returns 2015-2022 Pennsylvania separate corporate income tax returns 2020-2022 __________ (a) Tax years open to assessment include years when we were consolidated by Exelon. See discussion below under the Tax Matters Agreement for responsibility of taxes of these open years. |
Retirement Benefits (Tables)
Retirement Benefits (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Retirement Benefits [Abstract] | |
Defined Benefit Plan, Plan with Projected Benefit Obligation in Excess of Plan Assets | The following tables provide a rollforward of the changes in the benefit obligations and plan assets for the years ended December 31, 2023 and 2022 for all plans combined: Pension Benefits OPEB 2023 2022 2023 2022 Change in benefit obligation: Benefit obligation as of the beginning of the year $ 7,275 $ — $ 1,360 $ 847 Separation-related adjustment — 9,220 — 933 Benefit obligation as of February 1, 2022 — 9,220 — 1,780 Service cost 89 115 16 23 Interest cost 394 269 74 52 Plan participants' contributions — — 23 20 Actuarial loss/(gain), net 368 (1,756) 99 (401) Acquisition-related adjustment (a) 187 — 14 — Settlements — (15) — — Gross benefits paid (543) (558) (143) (114) Benefit obligation as of the end of year $ 7,770 $ 7,275 $ 1,443 $ 1,360 __________ (a) Pension and OPEB adjustment related to the acquisition of STP in 2023. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. Pension Benefits OPEB 2023 2022 2023 2022 Change in plan assets: Plan assets as of the beginning of year (a) $ 6,660 $ 1,683 $ 734 $ — Separation-related adjustment — 6,584 — 904 Fair value of plan assets as of February 1, 2022 — 8,267 — 904 Actual return (loss) on plan assets 374 (1,245) 50 (99) Employer contributions 26 211 — — Plan participants' contributions — — 18 15 Gross benefits paid (543) (558) (110) (86) Acquisition-related adjustment (b) 170 — — — Settlements — (15) — — Fair value of plan assets as of the end of year $ 6,687 $ 6,660 $ 692 $ 734 Over (under) funded status (Plan assets less benefit obligations) $ (1,083) $ (615) $ (751) $ (626) __________ (a) The balance on January 1, 2022 was reflected as a prepaid pension asset. (b) |
Schedule of Defined Benefit Plans Disclosures | We present our benefit obligations net of plan assets on our Consolidated Balance Sheets within the following line items: Pension Benefits OPEB 2023 2022 2023 2022 Other current liabilities $ (13) $ (10) $ (19) $ (17) Pension obligations (1,070) (605) — — Non-pension postretirement benefit — — (732) (609) The following table provides the ABO and fair value of plan assets for all pension plans with an ABO in excess of plan assets. ABO in Excess of Plan Assets December 31, 2023 December 31, 2022 ABO $ (7,567) $ (7,121) Fair value of net plan assets 6,687 6,660 We recognize the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on our balance sheet, with offsetting entries to AOCI. The following tables provide the pre-tax components of AOCI for the years ended December 31, 2023 and 2022, for all plans combined: Pension Benefits OPEB 2023 2022 2023 2022 Changes in plan assets and benefit obligations recognized in AOCI: Separation-related adjustment $ — $ 2,664 $ — $ 22 Current year actuarial (gain) loss 509 11 94 (253) Amortization of actuarial (loss) gain (46) (134) 14 1 Amortization of prior service (cost) credit (1) (1) 6 7 Settlements — (6) — — Total recognized in AOCI $ 462 $ 2,534 $ 114 $ (223) The following table provides the components of gross accumulated other comprehensive loss that have not been recognized as components of periodic benefit cost as of December 31, 2023 and 2022, for all plans combined: Pension Benefits OPEB 2023 2022 2023 2022 Prior service (credit) cost $ 9 $ 10 $ (24) $ (30) Actuarial (gain) loss 2,985 2,524 (85) (193) Total $ 2,994 $ 2,534 $ (109) $ (223) The resulting average remaining service periods for pension and OPEB were as follows as of December 31, 2023 and 2022: December 31, 2023 December 31, 2022 Pension plans 12.4 12.2 OPEB plans: Benefit Eligibility Age 7.5 7.4 Expected Retirement 8.3 8.3 The following assumptions were used to determine the benefit obligations for the plans as of December 31, 2023 and December 31, 2022. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs. Pension Benefits OPEB December 31, 2023 December 31, 2022 December 31, 2023 December 31, 2022 Discount rate (a) 5.17 % 5.52 % 5.15 % 5.50 % Investment crediting rate (b) 5.07 % 5.15 % N/A N/A Rate of compensation increase (c) 4.25 % 3.75 % 4.25 % 3.75 % Mortality table Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Healthcare cost trend on covered charges N/A N/A Initial and ultimate rate of 5.00% Initial and ultimate rate of 5.00% __________ (a) The discount rates above represent the blended rates used to calculate the majority of Constellation's pension and OPEB costs. (b) The investment crediting rate above represents a weighted average rate. (c) Includes 4.25% average for the 5 year period (2024-2028) and 3.75% average thereafter. The following assumptions were used to determine the net periodic benefit cost for the plans for the years ended December 31, 2023 and 2022. Pension Benefits OPEB 2023 2022 2023 2022 Discount rate (a) 5.52 % 3.23 % 5.50 % 3.21 % Investment crediting rate (b) 5.15 % 3.86 % N/A N/A Expected return on plan assets (c) 6.50 % 6.50 % 6.51 % 6.39 % Rate of compensation increase 3.75 % 3.75 % 3.75 % 3.75 % Mortality table Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Pri-2012 table with MP-2021 improvement scale (adjusted) Healthcare cost trend on covered charges N/A N/A Initial and ultimate rate of 5.00% Initial and ultimate rate of 5.00% __________ (a) The discount rates above represent the blended rates used to calculate the majority of Constellation's pension and OPEB costs. (b) The investment crediting rate above represents a weighted average rate. (c) Applicable to our pension and OPEB plans with plan assets, with the OPEB rate representing a weighted average. Estimated future benefit payments to participants over the next ten years in all pension and OPEB plans as of December 31, 2023 are as follows: Pension Benefits OPEB 2024 $ 576 $ 117 2025 575 116 2026 581 115 2027 581 114 2028 587 114 2029 through 2033 2,880 546 Total estimated future benefits payments through 2033 $ 5,780 $ 1,122 Our pension and OPEB plan target asset allocations as of December 31, 2023 and 2022 were as follows: December 31, 2023 December 31, 2022 Asset Category Pension Benefits OPEB Pension Benefits OPEB Equity securities 21 % 17 % 21 % 43 % Fixed income securities 54 % 70 % 54 % 45 % Alternative investments (a) 25 % 13 % 25 % 12 % Total 100 % 100 % 100 % 100 % __________ (a) Alternative investments include private equity, hedge funds, real estate, and private credit. |
Calculation of Net Periodic Benefit Costs | The following table presents the components of our net periodic benefit (credits) costs, prior to capitalization and co-owner allocations, for the years ended December 31 2023, 2022 and 2021: Pension Benefits OPEB Total Pension Benefits and OPEB 2023 2022 2021 (a) 2023 2022 2021 (a) 2023 2022 2021 (a) Components of net periodic benefit (credit) cost: Service cost $ 89 $ 126 $ 145 $ 16 $ 25 $ 29 $ 105 $ 151 $ 174 Non-service components of pension benefits & OPEB (credit) cost: Interest cost 404 290 235 76 55 45 480 345 280 Expected return on assets (520) (565) (493) (45) (55) (58) (565) (620) (551) Amortization of: Prior service (credit) cost 1 1 1 (10) (7) (9) (9) (6) (8) Actuarial (gain) loss 48 148 199 (12) (1) 10 36 147 209 Settlement charges — 6 20 — — — — 6 20 Non-service components of pension benefits & OPEB credit (cost) (b) (67) (120) (38) 9 (8) (12) (58) (128) (50) Net periodic benefit (credit) cost (c)(d)(e) $ 22 $ 6 $ 107 $ 25 $ 17 $ 17 $ 47 $ 23 $ 124 __________ (a) Costs recognized for the year ended December 31, 2021 were allocated to us by Exelon under the Exelon sponsored pension and OPEB plans prior to separation. (b) Effective February 1, 2022, these non-service (credits) costs are reflected in Other, net in the Consolidated Statements of Operations and Comprehensive Income. (c) The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2023 totaled $94 million. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2023 totaled ($54) million. (d) The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2022 totaled $131 million. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2022 totaled ($116) million. Our portion of the total net periodic benefit (credits) costs allocated to us from Exelon in January 2022 prior to separation was not material and remains in total Operating and maintenance expense. (e) The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2021 totaled $144 million. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2021 totaled ($50) million. |
Schedule of Allocation of Plan Assets | The following table presents pension and OPEB plan assets measured and recorded at fair value as a net component of Pension obligations and Non-pension postretirement benefit obligations in our Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2023 and 2022: December 31, 2023 December 31, 2022 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Pension plan assets (a) Cash equivalents $ 192 $ — $ — $ 192 $ 216 $ — $ — $ 216 Equities (b) 598 — — 598 776 — — 776 Fixed income 740 2,137 — 2,877 693 1,951 8 2,652 Private equity — — — — — — 180 180 Total assets measured at fair value 1,530 2,137 — 3,667 1,685 1,951 188 3,824 Assets measured at NAV — — — 3,283 — — — 2,879 Pension plan assets subtotal 1,530 2,137 — 6,950 1,685 1,951 188 6,703 OPEB plan assets (a) Cash equivalents — — — $ — 40 — — $ 40 Equities 232 — — 232 152 — — 152 Fixed income 62 94 — 156 67 61 — 128 Total assets measured at fair value 294 94 — 388 259 61 — 320 Assets measured at NAV — — — 304 — — — 414 OPEB plan assets subtotal 294 94 — 692 259 61 — 734 Total pension and OPEB plan assets (c) $ 1,824 $ 2,231 $ — $ 7,642 $ 1,944 $ 2,012 $ 188 $ 7,437 __________ (a) See Note 18 — Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy. (b) Includes derivative instruments of $31 million and $6 million for the years ended December 31, 2023 and 2022, respectively, which have total notional amounts of $1,986 million and $1,879 million as of December 31, 2023 and 2022, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss. (c) Excludes net liabilities of $263 million and $43 million as of December 31, 2023 and 2022, respectively, which include certain derivative assets that have notional amounts of $15 million and $41 million as of December 31, 2023 and 2022, respectively. These items are required to reconcile to the fair value of net plan assets and consist primarily of receivables or payables related to pending securities sales and purchases, and interest and dividends receivable. |
Pension And Other Postretirement Benefit Contributions | The following table provides our contributions paid to our qualified pension plans, non-qualified pension plans, and OPEB plans for the years ended December 31, 2023, 2022, and 2021: 2023 2022 2021 (b) Pension contributions (a) $ 26 $ 212 $ 231 OPEB contributions 28 26 28 Total contributions $ 54 $ 238 $ 259 __________ (a) In 2023 and 2022, our annual qualified pension contributions were $21 million and $192 million, respectively. The benefit payments to the non-qualified pension plans in 2023 and 2022 were not material. (b) Prior to separation, Exelon allocated contributions related to its legacy Exelon sponsored pension and OPEB plans to its subsidiaries based on accounting cost or employee participation (both active and retired). The following table provides our planned contributions to our qualified pension plans, non-qualified pension plans, and OPEB plans in 2024 (including our benefit payments related to unfunded plans): Qualified Pension Plans Non-Qualified Pension Plans OPEB Total Planned contributions $ 161 $ 13 $ 20 $ 194 |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation | The following table presents the reconciliation of Level 3 assets and liabilities measured at fair value for pension and OPEB plans for the years ended December 31, 2023 and 2022: Pension Assets Fixed Income Private Equity Total Balance as of January 1, 2023 $ 8 $ 180 $ 188 Actual return on plan assets: Relating to assets still held as of the reporting date — 12 12 Relating to assets sold during the period — (13) (13) Purchases and settlements: Purchases — 8 8 Settlements (a) — (187) (187) Transfers out of Level 3 (8) — (8) Balance as of December 31, 2023 $ — $ — $ — Pension Assets Fixed Income Private Equity Total Balance as of January 1, 2022 $ — $ — $ — Separation-related adjustment 9 — 9 Actual return on plan assets: Relating to assets still held as of the reporting date (1) (54) (55) Purchases and settlements: Purchases — 18 18 Settlements (a) — (4) (4) Transfers out of Level 3 (b) — 220 220 Balance as of December 31, 2022 $ 8 $ 180 $ 188 __________ (a) Represents cash settlements only. (b) Includes certain private equity investments previously measured at fair value using NAV or its equivalent as a practical expedient at separation transferred to Level 3 primarily due to changes in market liquidity or data. |
Derivative Financial Instrume_2
Derivative Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Summary of the Derivative Fair Value | The following tables provide a summary of the derivative fair value balances recorded as of December 31, 2023 and 2022: December 31, 2023 Economic Proprietary Collateral (a)(b) Netting (a) Total Mark-to-market derivative assets (current) $ 7,927 $ 2 $ 703 $ (7,472) $ 1,160 Mark-to-market derivative assets (noncurrent) 3,345 — 330 (2,682) 993 Total mark-to-market derivative assets 11,272 2 1,033 (10,154) 2,153 Mark-to-market derivative liabilities (current) (9,019) (2) 922 7,472 (627) Mark-to-market derivative liabilities (noncurrent) (3,545) — 445 2,682 (418) Total mark-to-market derivative liabilities (12,564) (2) 1,367 10,154 (1,045) Total mark-to-market derivative net assets (liabilities) $ (1,292) $ — $ 2,400 $ — $ 1,108 December 31, 2022 Mark-to-market derivative assets (current) $ 15,296 $ 10 $ 161 $ (13,123) $ 2,344 Mark-to-market derivative assets (noncurrent) 5,100 — 217 (4,074) 1,243 Total mark-to-market derivative assets 20,396 10 378 (17,197) 3,587 Mark-to-market derivative liabilities (current) (15,049) (6) 374 13,123 (1,558) Mark-to-market derivative liabilities (noncurrent) (5,203) — 146 4,074 (983) Total mark-to-market derivative liabilities (20,252) (6) 520 17,197 (2,541) Total mark-to-market derivative net assets (liabilities) $ 144 $ 4 $ 898 $ — $ 1,046 _________ (a) We net all available amounts allowed in our Consolidated Balance Sheets in accordance with authoritative guidance for derivatives. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. (b) Includes $1,712 million of variation margin posted and $836 million of variation margin held from the exchanges as of December 31, 2023 and 2022, respectively. The following table provides the mark-to-market derivative assets and liabilities as of December 31, 2023 and 2022: December 31, 2023 December 31, 2022 Economic Netting (a) Total Economic Netting (a) Total Mark-to-market derivative assets (current) $ 20 $ (1) $ 19 $ 29 $ (5) $ 24 Mark-to-market derivative assets (noncurrent) 2 — 2 18 — 18 Total mark-to-market derivative assets 22 (1) 21 47 (5) 42 Mark-to-market derivative liabilities (current) (6) 1 (5) (5) 5 — Mark-to-market derivative liabilities (noncurrent) (1) — (1) — — — Total mark-to-market derivative liabilities (7) 1 (6) (5) 5 — Total mark-to-market derivative net assets (liabilities) $ 15 $ — $ 15 $ 42 $ — $ 42 _________ (a) |
Economic Hedges (Commodity Price Risk) | For the years ended December 31, 2023, 2022, and 2021, we recognized the following net pre-tax commodity mark-to-market gains (losses), which are also included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the Years Ended December 31, Income Statement Location 2023 2022 2021 Operating revenues $ 1,402 $ (1,193) $ (635) Purchased power and fuel (2,368) 167 1,206 Total $ (966) $ (1,026) $ 571 |
Disclosure of Credit Derivatives | The following tables provide information on the credit exposure for all derivative instruments, NPNS and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2023. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk by types of counterparties. The amounts in the tables below exclude credit risk exposure from individual retail counterparties and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX, and Nodal commodity exchanges. Rating as of December 31, 2023 Total Credit Collateral (a) Net Number of Net Exposure of Investment grade $ 1,257 $ 51 $ 1,206 1 $ 222 Non-investment grade 22 7 15 — — No external ratings Internally rated — investment grade 116 — 116 — — Internally rated — non-investment grade 259 45 214 — — Total $ 1,654 $ 103 $ 1,551 1 $ 222 __________ (a) As of December 31, 2023, credit collateral held from counterparties where we had credit exposure included $44 million of cash and $59 million of letters of credit. The credit collateral does not include non-liquid collateral. Net Credit Exposure by Type of Counterparty As of December 31, 2023 Investor-owned utilities, marketers, power producers $ 1,271 Energy cooperatives and municipalities 132 Financial Institutions 49 Other 99 Total $ 1,551 |
Fair Value of Derivatives with Credit- Risk Related Contingent Features | The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below: As of December 31, Credit-Risk-Related Contingent Features 2023 2022 Gross fair value of derivative contracts containing this feature $ (1,894) $ (4,736) Offsetting fair value of in-the-money contracts under master netting arrangements 925 2,048 Net fair value of derivative contracts containing this feature $ (969) $ (2,688) |
Cash Collateral and Letters of Credit on Derivative Contracts | As of December 31, 2023 and 2022, we posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements. As of December 31, 2023 2022 Cash collateral posted (a) $ 2,449 $ 1,636 Letters of credit posted (a) 777 947 Cash collateral held (a) 64 765 Letters of credit held (a) 61 115 Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1) (b)(c)(d) 1,914 3,337 _________ (a) The cash collateral and letters of credit amounts are inclusive of NPNS contracts. (b) Certain of our contracts contain provisions that allow a counterparty to request additional collateral when there has been a subjective determination that our credit quality has deteriorated, generally termed “adequate assurance.” Due to the subjective nature of these provisions, we estimate the amount of collateral that we may ultimately be required to post in relation to the maximum exposure with the counterparty. (c) The downgrade collateral is inclusive of all contracts in a liability position regardless of accounting treatment and excludes any contracts with individual retail counterparties. (d) |
Debt and Credit Agreements (Tab
Debt and Credit Agreements (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Debt Disclosure [Abstract] | |
Schedule of Commercial Paper, Credit Facilities and Borrowing Rates | As of December 31, 2023 and 2022 we had the following aggregate bank commitments, credit facility borrowings and available capacity under our respective credit facilities: Facility Type Aggregate Bank Facility Draws Outstanding Outstanding Commercial Paper(a) Available Capacity as of December 31, 2023 Syndicated Revolver $ 3,500 $ — $ 60 $ 1,107 $ 2,333 Bilaterals 1,500 — 878 — 622 Liquidity Facility 971 — 720 — 191 (b) Project Finance 137 — 117 — 20 Total $ 6,108 $ — $ 1,775 $ 1,107 $ 3,166 Facility Type Aggregate Bank Facility Draws Outstanding Outstanding Commercial Paper(a) Available Capacity as of December 31, 2022 Syndicated Revolver $ 3,500 $ — $ 765 $ 959 $ 1,776 Bilaterals 1,200 — 867 — 333 Liquidity Facility 971 — 732 — 139 (b) Project Finance 131 — 111 — 20 Total $ 5,802 $ — $ 2,475 $ 959 $ 2,268 __________ (a) Our commercial paper program is supported by the revolving credit agreement. In order to maintain our commercial paper program in the amounts indicated above, we must have a credit facility in place, at least equal to the amount of our commercial paper program. As of both December 31, 2023 and 2022, the maximum program size of our commercial paper program was $3.5 billion. We do not issue commercial paper in an aggregate amount exceeding the then available capacity under our credit facility. The weighted average interest rate on commercial paper borrowings was 5.66% and 4.90% as of December 31, 2023 and 2022, respectively. (b) The maximum amount of the bank commitment is not to exceed $971 million. The aggregate available capacity of the facility is subject to market fluctuations based on the value of U.S Treasury Securities which determines the amount of collateral held in the trust. We may post additional collateral to borrow up to the maximum bank commitment. As of December 31, 2023 and 2022, without posting additional collateral, the actual availability of facility, prior to outstanding letters of credit was $911 million and $871 million, respectively. |
Schedule of Bilateral Credit Agreements | Bilateral Credit Agreements The following table reflects the bilateral credit agreements at December 31, 2023: Date Initiated Latest Amendment Date Maturity Date(a) Amount January 5, 2016 (b) April 4, 2023 April 3, 2026 $ 150 October 25, 2019 (b) N/A N/A 200 November 20, 2019 (b) N/A N/A 300 November 21, 2019 (b) N/A N/A 100 November 21, 2019 (b) November 15, 2022 November 21, 2024 100 May 15, 2020 (b) March 31, 2023 N/A 300 August 12, 2022 (b) N/A N/A 50 March 29, 2023 (b) N/A March 29, 2025 100 December 8, 2023 (b) N/A N/A 200 __________ (a) Credit facilities that do not contain a maturity date are specific to the agreements set within each contract. In some instances, credit facilities are automatically renewed based on the contingency standards set within the specific agreement. (b) Bilateral credit agreements solely support the issuance of letters of credit and do not back our commercial paper program. |
Schedule of Long-term Debt Instruments | Long-Term Debt The following table presents the outstanding long-term debt as of December 31, 2023 and 2022: Maturity December 31, Rates 2023 2022 Long-term debt Senior unsecured notes 3.25 % - 6.50 % 2025 - 2053 $ 5,688 $ 2,938 Tax-exempt notes 4.10 % - 4.45 % 2025 - 2053 (a) 435 — Notes payable and other 2.10 % - 5.85 % 2024 - 2029 34 68 Nonrecourse debt: Fixed rates 2.29 % - 6.00 % 2031 - 2037 780 839 Variable rates 7.24 % - 8.57 % 2026 - 2027 740 805 Total long-term debt 7,677 4,650 Unamortized debt discount and premium, net (4) (5) Unamortized debt issuance costs (56) (36) Long-term debt due within one year (121) (143) Long-term debt $ 7,496 $ 4,466 __________ (a) The Tax-exempt notes have a maturity date of March 1, 2025 - April 1, 2053, and a mandatory purchase date that ranges from March 1, 2025 - June 1, 2029. |
Schedule of Maturities of Long-term Debt | Long-term debt maturities in the periods 2024 through 2028 and thereafter are as follows: 2024 $ 121 2025 1,010 2026 121 2027 705 2028 1,160 Thereafter 4,560 Total $ 7,677 |
Fair Value of Financial Asset_2
Fair Value of Financial Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Liabilities Recorded at Amortized Cost | The following tables present the carrying amounts and fair values of our long-term debt and the SNF obligation as of December 31, 2023 and 2022. We have no financial liabilities classified as Level 1. The carrying amounts of the short-term liabilities as presented in the Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments. December 31, 2023 December 31, 2022 Carrying Amount Fair Value Carrying Amount Fair Value Level 2 Level 3 Total Level 2 Level 3 Total Long-Term Debt, including amounts due within one year $ 7,617 $ 7,140 $ 774 $ 7,914 $ 4,609 $ 3,688 $ 859 $ 4,547 SNF Obligation 1,296 1,222 — 1,222 1,230 1,021 — 1,021 |
Assets and Liabilities Measured and Recorded at Fair Value on Recurring Basis | The following tables present assets and liabilities measured and recorded at fair value in the Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2023 and 2022: As of December 31, 2023 As of December 31, 2022 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Cash equivalents (a) $ 42 $ — $ — $ 42 $ 41 $ — $ — $ 41 NDT fund investments Cash equivalents (b) 356 87 — 443 181 88 — 269 Equities 4,574 1,990 1 6,565 3,462 1,498 — 4,960 Fixed income 2,043 1,523 277 3,843 2,017 1,044 264 3,325 Private credit — — 151 151 — — 159 159 Assets measured at NAV — — — 5,396 — — — 5,414 NDT fund investments subtotal (c) 6,973 3,600 429 16,398 5,660 2,630 423 14,127 Rabbi trust investments 48 33 1 82 40 27 1 68 Investments in equities (d) 372 — — 372 6 — — 6 Commodity derivative assets Economic hedges 2,330 5,821 3,143 11,294 3,505 11,353 5,585 20,443 Proprietary trading — — 2 2 — 4 6 10 Effect of netting and allocation of (e)(f) (1,996) (5,195) (1,931) (9,122) (2,951) (10,348) (3,525) (16,824) Commodity derivative assets subtotal 334 626 1,214 2,174 554 1,009 2,066 3,629 DPP consideration — 1,216 — 1,216 — 515 — 515 Total assets measured at fair value 7,769 5,475 1,644 20,284 6,301 4,181 2,490 18,386 Total assets 7,769 5,475 1,644 20,284 6,301 4,181 2,490 18,386 Liabilities Commodity derivative liabilities Economic hedges (2,681) (7,154) (2,736) (12,571) (3,171) (11,498) (5,588) (20,257) Proprietary trading — — (2) (2) — (4) (2) (6) Effect of netting and allocation of collateral (e)(f) 2,587 6,542 2,393 11,522 3,279 10,700 3,743 17,722 Commodity derivative liabilities subtotal (94) (612) (345) (1,051) 108 (802) (1,847) (2,541) Deferred compensation obligation — (69) — (69) — (57) — (57) Total liabilities (94) (681) (345) (1,120) 108 (859) (1,847) (2,598) Total net assets $ 7,675 $ 4,794 $ 1,299 $ 19,164 $ 6,409 $ 3,322 $ 643 $ 15,788 __________ (a) CEG Parent has $54 million of Level 1 cash equivalents as of December 31, 2023. We exclude cash of $349 million and $390 million as of December 31, 2023 and December 31, 2022, respectively, and restricted cash of $49 million and $70 million as of December 31, 2023 and December 31, 2022, respectively. CEG Parent has excluded an additional $2 million and $19 million of cash as of December 31, 2023 and 2022, respectively. (b) Includes net liabilities of $115 million and $168 million as of December 31, 2023 and 2022, respectively, which include certain derivative assets that have notional amounts of $64 million and $59 million as of December 31, 2023 and 2022, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less. In the prior year net liabilities were excluded, prior year amounts have been updated for consistency with current year presentation. (c) Includes derivative assets and liabilities that are not material, which have total notional amounts of $884 million and $494 million as of December 31, 2023 and 2022, respectively. The notional principal amounts provide one measure of the transaction volume outstanding as of the periods ended and do not represent the amount of our exposure to credit or market loss. (d) Includes an equity investment that became publicly traded in the second quarter of 2023 and now has a readily determinable fair value (and no longer is accounted for as an equity method investment due to lack of significant influence). We record the fair value of this investment in Investments on the Consolidated Balance Sheets based on the quoted market price of the stock at June 30, 2023, which resulted in an unrealized gain of $313 million within Other, net in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2023. (e) Net collateral posted to/(received from) counterparties totaled $591 million, $1,347 million, and $462 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2023. Net collateral posted to/(received from) counterparties totaled $328 million, $352 million, and $218 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2022. (f) Includes $1,712 million of variation margin posted and $836 million of variation margin held from the exchanges as of December 31, 2023 and 2022, respectively. |
Fair Value Reconciliation of Level 3 Assets and Liabilities Measured at Fair Value on a Recurring Basis | The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2023 and 2022: For the Year Ended December 31, 2023 NDT Fund Investments Mark-to-Market Life Insurance Contracts Total Balance as of January 1, 2023 $ 423 $ 219 $ 1 $ 643 Total realized / unrealized gains (losses) Included in net income (loss) 2 171 (a) — 173 Included in Payables related to Regulatory Agreement Units 10 — — 10 Change in collateral — 243 — 243 Purchases, sales, issuances and settlements Purchases — 160 — 160 Sales 1 (29) — (28) Settlements (7) 32 — 25 Transfers into Level 3 — 46 (b) — 46 Transfers out of Level 3 — 27 (b) — 27 Balance as of December 31, 2023 $ 429 $ 869 $ 1 $ 1,299 The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2023 $ 2 $ 1,194 $ — $ 1,196 For the Year Ended December 31, 2022 NDT Fund Investments Mark-to-Market Life Insurance Contracts Total Balance as of January 1, 2022 $ 464 $ (94) $ — $ 370 Total realized / unrealized gains (losses) Included in net income (loss) (2) (753) (a) (2) (757) Included in Payables related to Regulatory Agreement Units (10) — — (10) Change in collateral — 253 — 253 Impacts of separation — — 3 3 Purchases, sales, issuances and settlements Purchases 5 594 — 599 Sales — (50) — (50) Settlements (35) (102) — (137) Transfers into Level 3 2 381 (b) — 383 Transfers out of Level 3 (1) (10) (b) — (11) Balance as of December 31, 2022 $ 423 $ 219 $ 1 $ 643 The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2022 $ (2) $ (1,265) $ (2) $ (1,269) __________ (a) Includes a reduction of ($991) million for realized gains and an addition of $410 million for realized losses due to the settlement of derivative contracts for the years ended December 31, 2023 and 2022, respectively. (b) Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable, respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts. |
Total Realized and Unrealized Gains (Losses) Included in Income for Level 3 Assets and Liabilities Measured at Fair Value on a Recurring Basis | The following table presents the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2023, 2022, and 2021: Operating Purchased Other, net 2023 2022 2021 2023 2022 2021 2023 2022 2021 Total gains (losses) included in net income $ 706 $ (860) $ (1,343) $ (503) $ 5 $ 531 $ 2 $ (4) $ 5 Total unrealized gains (losses) 1,673 (1,330) (1,577) (479) 65 355 2 (2) 5 |
Fair Value Reconciliation of Level 3 Assets and Liabilities Measured at Fair Value on a Recurring Basis, Valuation Technique | The following table presents the significant inputs to the forward curve used to value these positions: Type of trade Fair Value as of December 31, 2023 Fair Value as of December 31, 2022 Valuation Unobservable 2023 Range & Arithmetic Average 2022 Range & Arithmetic Average Mark-to-market derivatives—Economic hedges (a)(b) $ 407 $ (3) Discounted Cash Flow Forward power $9.64 - $216 $48 $0.63 - $283 $72 Forward gas $1.20 - $14 $3.09 $1.67 - $26 $4.57 Option Volatility 23% - 200% 87% 97% - 119% 111% __________ (a) The valuation techniques, unobservable inputs, ranges, and arithmetic averages are the same for the asset and liability positions. (b) The fair values do not include cash collateral posted (received) on Level 3 positions of $462 million and $218 million as of December 31, 2023 and December 31, 2022, respectively. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
Other Commitments | Commercial commitments as of December 31, 2023, representing commitments potentially triggered by future events, were as follows: Expiration within Total 2024 2025 2026 2027 2028 2029 and beyond Letters of credit $ 1,775 $ 1,631 $ 27 $ 1 $ — $ 116 $ — Surety bonds (a) 824 824 — — — — — Total commercial commitments $ 2,599 $ 2,455 $ 27 $ 1 $ — $ 116 $ — __________ (a) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
Schedule of Government Settlement Agreements | As of December 31, 2023 and 2022, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows: December 31, 2023 December 31, 2022 DOE receivable - current (a) $ 229 $ 125 DOE receivable - noncurrent (b) 40 130 Amounts owed to co-owners (c) (23) (12) __________ (a) Recorded in Other accounts receivable. (b) Recorded in Deferred debits and other assets, other. (c) Recorde d primarily in Accounts payable and accrued expenses and Other accounts receivable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilitie |
Spent Nuclear Fuel Obligation | The below table outlines the SNF liability recorded as of December 31, 2023 and 2022: December 31, 2023 December 31, 2022 Former ComEd units (a) $ 1,158 $ 1,100 Fitzpatrick (b) 138 130 Total SNF Obligation $ 1,296 $ 1,230 __________ (a) ComEd previously elected to defer payment of the one-time fee of $277 million for its units that began operations before April 7, 1983, with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. The unfunded liabilities for SNF disposal costs, including the one-time fee, were transferred to us as part of Exelon’s 2001 corporate restructuring. See Note 10 — Asset Retirement Obligations for additional detail on Zion Station’s SNF obligation which is included in the table above. (b) A prior owner of FitzPatrick elected to defer payment of the one-time fee of $34 million, with interest to the date of payment, for the FitzPatrick unit. As part of the FitzPatrick acquisition on March 31, 2017, we assumed a SNF liability for the DOE one-time fee obligation with interest related to FitzPatrick along with an offsetting asset, included in Other deferred debits and other assets, for the contractual right to reimbursement from NYPA, a prior owner of FitzPatrick, for amounts paid for the FitzPatrick DOE one-time fee obligation. |
Shareholders' Equity (Tables)
Shareholders' Equity (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Equity [Abstract] | |
Schedule Of Changes In Accumulated Other Comprehensive Income (Loss) | The following tables present changes in AOCI, net of tax, by component: Gains (losses) on Cash Flow Hedges Pension and Non-Pension Postretirement Benefit Plan Items (a) Foreign Currency Items Total Balance at December 31, 2020 $ (7) $ — $ (23) $ (30) OCI before reclassifications (1) — — (1) Net current-period OCI (1) — — (1) Balance at December 31, 2021 $ (8) $ — $ (23) $ (31) Separation-related adjustments — (2006) — (2,006) OCI before reclassifications (1) 186 (3) 182 Amounts reclassified from AOCI — 95 — 95 Net current-period OCI (1) (1,725) (3) (1,729) Balance at December 31, 2022 $ (9) $ (1,725) $ (26) $ (1,760) OCI before reclassifications (2) (453) 2 (453) Amounts reclassified from AOCI 1 21 — 22 Net current-period OCI (1) (432) 2 (431) Balance at December 31, 2023 $ (10) $ (2,157) $ (24) $ (2,191) __________ (a) AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 15 — Retirement Benefits for additional information. See our Consolidated Statements of Operations and Comprehensive Income for individual components of AOCI. The following table presents income tax (expense) benefit allocated to each component of our other comprehensive income (loss): Year Ended December 31, 2023 2022 2021 Pension and non-pension postretirement benefit plans: Actuarial loss reclassified to periodic benefit cost $ (10) $ (33) $ — Pension and non-pension postretirement benefit plans valuation adjustment (a) 151 619 — __________ (a) Includes $680 million of income tax benefit related to the separation adjustment for the year ended December 31, 2022. |
Stock-Based Compensation Plans
Stock-Based Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Share-Based Payment Arrangement [Abstract] | |
Share-based Payment Arrangement, Cost by Plan | The following table presents the stock-based compensation expense included in the Consolidated Statements of Operations and Comprehensive Income. The information does not include expenses related to the cash awards as they are not considered stock-based compensation plans under the applicable authoritative guidance: Year Ended December 31, 2023 (a) 2022 (a) 2021 (b) Total stock-based compensation expense included in operating and maintenance expense $ 178 $ 116 $ 47 Income tax benefit (45) (29) (12) Total after-tax stock-based compensation expense $ 133 $ 87 $ 35 __________ (a) Costs recognized for the years ended December 31, 2023 and 2022 are related to the Constellation LTIP. (b) Costs recognized for the year ended December 31, 2021 were allocated to us by Exelon under the Exelon LTIP prior to separation. |
Share-Based Payment Arrangement, Performance Shares, Activity | The following table summarizes our unvested performance share awards activity: Shares Weighted Average Grant Date Fair Value (per share) Unvested at December 31, 2022 849,342 $ 47.40 Granted 370,874 83.26 Change in performance 471,561 75.31 Forfeited (20,615) 57.80 Undistributed vested awards (a) (834,837) 90.81 Unvested at December 31, 2023 836,325 $ 61.47 __________ (a) Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2023 and 2022. The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards vested: December 31, 2023 (a) December 31, 2022 (a) Weighted average grant date fair value (per share) $ 83.26 $ 48.33 Total fair value of performance shares vested 76 69 __________ (a) As of December 31, 2023 and 2022 , $39 million and $28 million of total unrecognized compensation costs related to unvested performance shares are expected to be recognized over the remaining weighted-average period of 1.6 years and 1.7 years, respectively. The following table summarizes our unvested restricted stock unit activity: Shares Weighted Average Grant Date Fair Value (per share) Unvested at December 31, 2022 790,668 $ 53.72 Granted 620,002 86.10 Vested (295,370) 53.46 Forfeited (27,922) 69.14 Undistributed vested awards (a) (222,573) 80.52 Unvested at December 31, 2023 864,805 $ 69.42 __________ (a) Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2023 and 2022. The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units vested: December 31, 2023 (a) December 31, 2022 (a) Weighted average grant date fair value (per share) $ 86.10 $ 54.17 Total fair value of restricted stock units vested 34 35 __________ (a) As of December 31, 2023 and 2022, $35 million and $27 million of total unrecognized compensation costs related to unvested restricted stock units are expected to be recognized over the remaining weighted-average period of 1.9 years and 2.0 years. |
Variable Interest Entities (Tab
Variable Interest Entities (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Variable Interest Entity [Abstract] | |
Consolidated VIEs - Assets and Liabilities | The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements as of December 31, 2023 and 2022. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnotes to the table below, are such that creditors, or beneficiaries, do not have recourse to our general credit. December 31, 2023 December 31, 2022 Cash and cash equivalents $ 48 $ 51 Restricted cash and cash equivalents 47 46 Accounts receivable Customer 19 20 Other 10 9 Inventories, net Materials and supplies 14 12 Other current assets 1,249 549 Total current assets 1,387 687 Property, plant and equipment, net 1,979 1,965 Other noncurrent assets 166 190 Total noncurrent assets 2,145 2,155 Total assets (a) $ 3,532 $ 2,842 Long-term debt due within one year $ 63 $ 60 Accounts payable 11 17 Accrued expenses 20 23 Other current liabilities — 2 Total current liabilities 94 102 Long-term debt 704 764 Asset retirement obligations 190 173 Other noncurrent liabilities 2 3 Total noncurrent liabilities 896 940 Total liabilities (b) $ 990 $ 1,042 _______ (a) Our balances include unrestricted assets f or current unamortized energy contract assets of $22 million and $23 million, disclosed within other current assets in the table above and noncurrent unamortized energy contract assets of $155 million and $178 million, disclosed within other noncurrent assets in the table above as of December 31, 2023 and 2022, respectively. (b) As of December 31, 2023, our balance does not include any liabilities with recourse. Our balance includes liabilities with recourse of $1 million as of December 31, 2022 . |
Schedule of Variable Interest Entities | As of December 31, 2023 and 2022, our consolidated VIEs included the following: Consolidated VIE or VIE groups: Reason entity is a VIE: Reason we are the primary beneficiary: CRP - A collection of wind and solar project entities. We have a 51% equity ownership in CRP. See additional discussion below. Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. We conduct the operational activities. Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by CRP. Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. We conduct the operational activities. Antelope Valley - A solar generating facility, which is 100% owned by us. Antelope Valley sells all of its output to PG&E through a PPA. The PPA contract absorbs variability through a performance guarantee. We conduct all activities. NER - A bankruptcy remote, special purpose entity which is 100% owned by us, which purchases certain of our customer accounts receivable arising from the sale of retail electricity. NER’s assets will be available first and foremost to satisfy the claims of the creditors of NER. Refer to Note 6 —Accounts Receivable for additional information on the sale of receivables. Equity capitalization is insufficient to support its operations. We conduct all activities. As of December 31, 2023 and 2022, the unconsolidated VIEs consist of: Unconsolidated VIE groups: Reason entity is a VIE: Reason we are not the primary beneficiary: Equity investments in distributed energy companies. We have a 90% equity ownership in a distributed energy company. We sold this investment in the fourth quarter of 2022 resulting in it no longer being classified as an unconsolidated VIE . Similar structures to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. We do not conduct the operational activities. Energy Purchase and Sale agreements - We have several energy purchase and sale agreements with generating facilities. PPA contracts that absorb variability through fixed pricing. We do not conduct the operational activities. |
Schedule of Variable Interest Entities | The following table presents summary information about our significant unconsolidated VIE entities: December 31, 2023 December 31, 2022 Commercial Equity Total Commercial Equity Total Total assets (a) $ 704 $ — $ 704 $ 715 $ — $ 715 Total liabilities (a) 77 — 77 54 — 54 Other ownership interests in VIE (a) 627 — 627 661 — 661 __________ (a) These items represent amounts on the unconsolidated VIE balance sheets, not in the Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. We do not have any exposure to loss as we do not have a carrying amount in the equity investment VIEs as o f December 31, 2023 and 2022. |
Supplemental Financial Inform_2
Supplemental Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Supplemental Financial Information [Abstract] | |
Schedule Of Taxes Excluding Income And Excise Taxes | The following tables provide additional information about material items recorded in the Consolidated Statements of Operations and Comprehensive Income. Taxes other than income taxes For the Years Ended December 31, 2023 2022 2021 Gross receipts (a) $ 139 $ 130 $ 99 Property 253 274 268 Payroll 142 130 109 __________ (a) Represent gross receipts taxes related to our retail operations. The offsetting collection of gross receipts taxes from customers is recorded in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. |
Schedule of Other Nonoperating Income, by Component | Other, net For the Years Ended December 31, 2023 2022 2021 Decommissioning-related activities: Net realized income on NDT funds (a) Regulatory Agreement Units $ 657 $ 333 $ 817 Non-Regulatory Agreement Units 335 97 449 Net unrealized (losses) gains on NDT funds Regulatory Agreement Units 397 (1,354) 351 Non-Regulatory Agreement Units 259 (798) 209 Regulatory offset to NDT fund-related activities (b) (845) 820 (917) Total Decommissioning-related activities 803 (902) 909 Non-service net periodic benefit credit (c) 54 110 — Net realized and unrealized (losses) gains from equity investments (d) 307 (13) (160) Return to provision adjustment (e) 19 (49) — Other (f) 85 68 46 Total Other, net $ 1,268 $ (786) $ 795 __________ (a) Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments. (b) Includes the elimination of decommissioning-related activities and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning and the contractual offset suspension for the Byron units. (c) Prior to separation, we were allocated our portion of pension and OPEB non-service credits (costs) from Exelon, which was included in Operating and maintenance expense. Effective February 1, 2022, the non-service credit (cost) components are included in Other, net, in accordance with single employer plan accounting. See Note 15 — Retirement Benefits for additional information. (d) For 2023, includes unrealized gain resulting from equity investment that became publicly traded in the second quarter of 2023 and now has a readily determinable fair value (and no longer is accounted for as an equity method investment due to lack of significant influence). We recorded the fair value of this investment in Investments on the Consolidated Balance Sheets based on quoted market price of the stock. See Note 18 — Fair Value of Financial Assets and Liabilities for additional information. For 2022, represents Net realized and unrealized (losses) gains from equity investments. For 2021, represents Net unrealized (losses) gains from equity investments. (e) This reflects amounts contractually owed to Exelon under the TMA, which is offset in Income taxes. See Note 14 — Income Taxes for additional information. (f) Includes amounts we billed Exelon for services pursuant to the TSA. See Note 1 — Basis of Presentation for additional information. |
Cash Flow Supplemental Disclosures | The following tables provide additional information about material items recorded in the Consolidated Statements of Cash Flows. Depreciation, amortization and accretion For the Years Ended December 31, 2023 2022 2021 Property, plant, and equipment (a) $ 1,073 $ 1,065 $ 2,954 Amortization of intangible assets, net (a) 23 26 49 Amortization of energy contract assets and liabilities (b) 35 35 31 Nuclear fuel (c) 787 758 992 ARO accretion (d) 596 543 514 Total depreciation, amortization, and accretion $ 2,514 $ 2,427 $ 4,540 _________ (a) Included in Depreciation and amortization expense in the Consolidated Statements of Operations and Comprehensive Income. (b) Included in Operating revenues or Purchased power and fuel expense in the Consolidated Statements of Operations and Comprehensive Income. (c) Included in Purchased power and fuel expense in the Consolidated Statements of Operations and Comprehensive Income. (d) Included in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Cash paid during the year For the Years Ended December 31, 2023 2022 2021 Interest (net of amount capitalized) $ 264 $ 230 $ 275 Income taxes (net of refunds) 466 287 426 Other non-cash operating activities CEG Parent Constellation For the Years Ended December 31, For the Years Ended December 31, 2023 2022 2021 2023 2022 2021 Pension and non-pension postretirement benefit costs $ 47 $ 17 $ 123 $ 47 $ 17 $ 123 Other decommissioning-related activity (a) (534) (263) (946) (534) (263) (946) Energy-related options (b) 183 293 125 183 293 125 Asset impairments 71 — 545 71 — 545 (Gain) loss on sale of assets and businesses (27) (1) (201) (27) (1) (201) Severance costs 2 (1) (73) 2 (1) (73) Long-term incentive plan 57 44 — — — — Amortization of operating ROU asset 64 75 119 64 75 119 (Gain) loss on sale of receivables 75 69 36 75 69 36 __________ (a) Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning and the contractual offset suspension for the Byron units. (b) Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. The following table provides a reconciliation of cash, restricted cash, and cash equivalents reported in the Consolidated Balance Sheets that sum to the total of the same amounts in the Consolidated Statements of Cash Flows. December 31, 2023 CEG Parent Constellation Cash and cash equivalents $ 368 $ 366 Restricted cash and cash equivalents 86 74 Total cash, restricted cash, and cash equivalents $ 454 $ 440 December 31, 2022 CEG Parent Constellation Cash and cash equivalents $ 422 $ 403 Restricted cash and cash equivalents 106 98 Total cash, restricted cash, and cash equivalents $ 528 $ 501 December 31, 2021 CEG Parent Constellation Cash and cash equivalents $ 504 $ 504 Restricted cash and cash equivalents 72 72 Total cash, restricted cash, and cash equivalents $ 576 $ 576 For additional information on restricted cash, see Note 1 — Basis of Presentation. |
Supplemental Balance Sheet Information | The following tables provide additional information about material items recorded in the Consolidated Balance Sheets. Investments December 31, 2023 December 31, 2022 Equity method investments (a) $ 7 $ 82 Other investments: Employee benefit trusts and investments (b) 82 68 Equity investments with readily determinable fair values (a)(c) 369 — Equity investments without readily determinable fair values 103 46 Other available for sale debt security investments 2 6 Total investments $ 563 $ 202 __________ (a) An investment previously classified as an equity method investment became publicly traded in the second quarter of 2023 and now has a readily determinable fair value. We recorded the fair value of this investment in Investments on the Consolidated Balance Sheets based on quoted market price of the stock. See Note 18 — Fair Value of Financial Assets and Liabilities for additional information. (b) Debt and equity security investments are recorded at fair market value. (c) Does not include the equity investments with readily determinable fair values that are recorded in Other current assets in the Consolidated Balance Sheets. See Note 18 — Fair Value of Financial Assets and Liabilities for additional information on Investments in equities. Accounts payable and accrued expenses December 31, 2023 CEG Parent Constellation Accounts payable $ 1,302 $ 1,289 Compensation-related accruals (a) 680 576 Taxes accrued 399 390 Accounts payable and accrued expenses December 31, 2022 CEG Parent Constellation Accounts payable $ 2,828 $ 2,810 Compensation-related accruals (a) 540 502 Taxes accrued 257 257 __________ (a) Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits. |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Related Party Transactions [Abstract] | |
Schedule of Related Party Transactions | The following table presents our Operating revenues from affiliates: For the Years Ended December 31, 2022 (a) 2021 ComEd (b) $ 58 $ 376 PECO (c) 33 196 BGE (d) 18 236 PHI 51 366 Pepco (e) 39 270 DPL (f) 10 79 ACE (g) 2 17 Other — 14 Total operating revenues from affiliates $ 160 $ 1,188 __________ (a) Represents only January 2022 costs prior to separation on February 1, 2022. (b) We have an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. We also sell RECs and ZECs to ComEd. (c) We provide electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, we have a ten-year agreement with PECO to sell solar AECs. (d) We provide a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. (e) We provide electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC. (f) We provide a portion of DPL's energy requirements under its MDPSC and DEPSC approved market-based SOS commodity programs. (g) We provide electric supply to ACE under contracts executed through ACE's competitive procurement process. |
Basis of Presentation (Details)
Basis of Presentation (Details) $ in Millions | 12 Months Ended | ||||
Jan. 31, 2022 USD ($) creditAgreement | Dec. 31, 2023 USD ($) segment | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Jan. 20, 2022 | |
Significant Accounting Policies Additional Narrative Information [Line Items] | |||||
Number of reportable segments | segment | 5 | ||||
Conversion ratio | 0.3333 | ||||
Contributions from member | $ 1,750 | $ 0 | $ 1,750 | $ 64 | |
Short-term borrowings | $ 200 | 1,644 | 1,159 | ||
Number of credit agreements | creditAgreement | 2 | ||||
Credit facility term | 5 years | ||||
Credit facility | $ 4,500 | 6,108 | 5,802 | ||
Billings from related party | 151 | 266 | |||
Billings to related party | $ 14 | $ 43 | |||
Software and Software Development Costs | |||||
Significant Accounting Policies Additional Narrative Information [Line Items] | |||||
Expected life | 5 years | ||||
Pension Benefits | |||||
Significant Accounting Policies Additional Narrative Information [Line Items] | |||||
Contributions from member | 192 | ||||
Exelon Consolidation | |||||
Significant Accounting Policies Additional Narrative Information [Line Items] | |||||
Payables to affiliates | $ 258 | ||||
Constellation Renewables | |||||
Significant Accounting Policies Additional Narrative Information [Line Items] | |||||
Ownership interest | 51% | 51% |
Mergers, Acquisitions, and Di_3
Mergers, Acquisitions, and Dispositions - Narrative (Details) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||
Nov. 01, 2023 USD ($) MW | Aug. 06, 2021 USD ($) | Mar. 31, 2021 USD ($) | Dec. 08, 2020 site MW | Apr. 01, 2014 USD ($) | Jun. 30, 2021 USD ($) | Dec. 31, 2023 USD ($) decommissioningTrustFund | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
Mergers, Acquisitions, and Dispositions [Line Items] | |||||||||
Number of decommissioning trust funds | decommissioningTrustFund | 2 | ||||||||
Other | $ 917 | $ 731 | |||||||
Deferred tax adjustment related to acquisition of CENG noncontrolling interest | $ (288) | ||||||||
Solar Business | Disposal Group, Disposed of by Sale, Not Discontinued Operations | |||||||||
Mergers, Acquisitions, and Dispositions [Line Items] | |||||||||
Purchase price | $ 810 | ||||||||
MW of generation | MW | 360 | ||||||||
Number of sites | site | 600 | ||||||||
Cash proceeds received | 675 | ||||||||
Long-term debt assumed by buyer | 125 | ||||||||
Pre-tax gain on disposition | $ 68 | ||||||||
Constellation Energy Generation, LLC | |||||||||
Mergers, Acquisitions, and Dispositions [Line Items] | |||||||||
Other | $ 911 | 718 | |||||||
Deferred tax adjustment related to acquisition of CENG noncontrolling interest | $ (288) | ||||||||
Constellation Energy Generation, LLC | Albany Green Energy biomass facility | |||||||||
Mergers, Acquisitions, and Dispositions [Line Items] | |||||||||
Pre-tax impairment charge | $ 140 | ||||||||
Purchase price | $ 36 | ||||||||
Constellation Energy Generation, LLC | CENG | |||||||||
Mergers, Acquisitions, and Dispositions [Line Items] | |||||||||
Special distribution | $ 400 | ||||||||
Return per annum | 8.50% | ||||||||
Advance notice period | 60 days | ||||||||
Pre-tax increase in membership interest for purchase of EDF's 49.99% equity interest | $ 885 | 1,080 | |||||||
Deferred tax adjustment related to acquisition of CENG noncontrolling interest | $ 288 | ||||||||
Constellation Energy Generation, LLC | CENG | Affiliated Entities | |||||||||
Mergers, Acquisitions, and Dispositions [Line Items] | |||||||||
Other | $ 400 | ||||||||
CENG | Constellation Energy Generation, LLC | |||||||||
Mergers, Acquisitions, and Dispositions [Line Items] | |||||||||
Equity interest | 49.99% | ||||||||
NRG Energy, Inc. | |||||||||
Mergers, Acquisitions, and Dispositions [Line Items] | |||||||||
MW of generation | MW | 2,645 | ||||||||
Consideration | $ 1,654 | ||||||||
NRG Energy, Inc. | |||||||||
Mergers, Acquisitions, and Dispositions [Line Items] | |||||||||
Ownership interest | 44% | ||||||||
NRG Energy, Inc. | STP Nuclear Operating Company | |||||||||
Mergers, Acquisitions, and Dispositions [Line Items] | |||||||||
Ownership interest | 40% | ||||||||
NRG Energy, Inc. | City of Austin | |||||||||
Mergers, Acquisitions, and Dispositions [Line Items] | |||||||||
Ownership interest | 16% | ||||||||
CENG | Constellation Energy Generation, LLC | |||||||||
Mergers, Acquisitions, and Dispositions [Line Items] | |||||||||
Ownership interest | 50.01% | ||||||||
CENG | Constellation Energy Generation, LLC | Nine Mile Point Unit 2 | |||||||||
Mergers, Acquisitions, and Dispositions [Line Items] | |||||||||
Ownership interest | 82% |
Mergers, Acquisitions, and Di_4
Mergers, Acquisitions, and Dispositions - Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Millions | Nov. 01, 2023 | Dec. 31, 2023 | Dec. 31, 2022 |
Schedule of Changes in Ownership Interest [Line Items] | |||
Goodwill | $ 425 | $ 47 | |
NRG Energy, Inc. | |||
Schedule of Changes in Ownership Interest [Line Items] | |||
Cash paid for purchase price | $ 1,654 | ||
Property, plant, and equipment | 1,254 | ||
Nuclear decommissioning trust funds | 869 | ||
Inventories, net | 47 | ||
Other long-term assets | 40 | ||
Other current assets | 11 | ||
Total assets | 2,221 | ||
Asset retirement obligations | 429 | ||
Payables related to Regulatory Agreement Units | 376 | ||
Deferred income taxes and unamortized investment tax credits | 65 | ||
Accounts payable and accrued expenses | 45 | ||
Pension and OPEB obligations | 25 | ||
Other long-term liabilities | 5 | ||
Total liabilities | 945 | ||
Total net identifiable assets, at fair value | 1,276 | ||
Goodwill | $ 378 |
Mergers, Acquisitions, and Di_5
Mergers, Acquisitions, and Dispositions - Changes in Ownership Equity (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Aug. 06, 2021 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Schedule of Changes in Ownership Interest [Line Items] | ||||
Net Income (Loss) | $ 1,623 | $ (160) | $ (205) | |
Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest | 288 | |||
Constellation Energy Generation, LLC | ||||
Schedule of Changes in Ownership Interest [Line Items] | ||||
Net Income (Loss) | $ 1,623 | (160) | (205) | |
Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest | $ 288 | |||
Constellation Energy Generation, LLC | CENG | ||||
Schedule of Changes in Ownership Interest [Line Items] | ||||
Equity interest | 49.99% | |||
CENG | Constellation Energy Generation, LLC | ||||
Schedule of Changes in Ownership Interest [Line Items] | ||||
Net Income (Loss) | (205) | |||
Pre-tax increase in membership interest for purchase of EDF's 49.99% equity interest | $ 885 | 1,080 | ||
Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest | (288) | |||
Change from net loss attributable to membership interest and transfers from noncontrolling interest | $ 587 |
Regulatory Matters (Details)
Regulatory Matters (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Mar. 06, 2020 | Dec. 31, 2023 | Dec. 31, 2022 | |
Regulatory Matters Additional Narrative Information [Line Items] | |||
Bonuses | $ 120 | $ 109 | |
Peach Bottom Units 2 and 3 | |||
Regulatory Matters Additional Narrative Information [Line Items] | |||
Operating license renewal period | 20 years |
Revenue from Contracts with C_3
Revenue from Contracts with Customers - Narrative (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Jun. 30, 2023 | Dec. 31, 2023 | Dec. 31, 2022 | |
Revenue from Contract with Customer [Abstract] | |||
Average contract term | 18 months | ||
ZEC revenue recognized | $ 218 | ||
Bonuses | $ 120 | $ 109 |
Revenue from Contracts with C_4
Revenue from Contracts with Customers - Contract Assets (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Change in Contract with Customer, Asset [Abstract] | ||
Beginning Balance | $ 130 | $ 149 |
Amounts reclassified to receivables | (127) | (81) |
Revenues recognized | 79 | 62 |
Ending Balance | $ 82 | $ 130 |
Revenue from Contracts with C_5
Revenue from Contracts with Customer - Contract Liabilities (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Contract Liabilities [Roll Forward] | |||
Beginning Balance | $ 47 | $ 75 | $ 84 |
Consideration received or due | 331 | 339 | 251 |
Revenues recognized | (338) | (367) | (263) |
Contract liabilities reclassified as held for sale | 0 | 0 | 3 |
Ending Balance | $ 40 | $ 47 | $ 75 |
Revenue from Contracts with C_6
Revenue from Contracts with Customers - Performance Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |||
Revenues recognized | $ 24,918 | $ 24,440 | $ 19,649 |
Remaining performance obligations | 364 | ||
Contract Liability | |||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |||
Revenues recognized | 26 | $ 71 | $ 82 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | |||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |||
Remaining performance obligations | $ 152 | ||
Remaining performance obligations, timing | 1 year | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | |||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |||
Remaining performance obligations | $ 44 | ||
Remaining performance obligations, timing | 1 year | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | |||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |||
Remaining performance obligations | $ 20 | ||
Remaining performance obligations, timing | 1 year | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | |||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |||
Remaining performance obligations | $ 18 | ||
Remaining performance obligations, timing | 1 year | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | |||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |||
Remaining performance obligations | $ 130 | ||
Remaining performance obligations, timing | 1 year |
Segment Information - Narrative
Segment Information - Narrative (Details) | 12 Months Ended |
Dec. 31, 2023 segment | |
Segment Reporting [Abstract] | |
Number of reportable segments | 5 |
Segment Information - Generatio
Segment Information - Generation Total Revenues (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Segment Reporting Information [Line Items] | |||
Revenue from contracts with customers | $ 20,841 | $ 21,571 | $ 17,254 |
Revenue not from contracts | 4,077 | 2,869 | 2,395 |
Revenues | 24,918 | 24,440 | 19,649 |
Electricity | |||
Segment Reporting Information [Line Items] | |||
Revenues | 19,014 | 19,684 | 16,290 |
Mid-Atlantic | Electricity | |||
Segment Reporting Information [Line Items] | |||
Revenues | 5,138 | 5,164 | 4,584 |
Midwest | Electricity | |||
Segment Reporting Information [Line Items] | |||
Revenues | 4,658 | 4,650 | 4,060 |
New York | Electricity | |||
Segment Reporting Information [Line Items] | |||
Revenues | 2,021 | 1,595 | 1,575 |
ERCOT | Electricity | |||
Segment Reporting Information [Line Items] | |||
Revenues | 1,346 | 1,543 | 1,181 |
Other Power Regions | Electricity | |||
Segment Reporting Information [Line Items] | |||
Revenues | 5,851 | 6,732 | 4,890 |
Operating Segments | Electricity | |||
Segment Reporting Information [Line Items] | |||
Revenue from contracts with customers | 18,397 | 18,421 | 15,112 |
Revenue not from contracts | 617 | 1,263 | 1,178 |
Revenues | 19,014 | 19,684 | 16,290 |
Operating Segments | Mid-Atlantic | Electricity | |||
Segment Reporting Information [Line Items] | |||
Revenue from contracts with customers | 5,453 | 5,264 | 4,381 |
Revenue not from contracts | (265) | (105) | 183 |
Revenues | 5,188 | 5,159 | 4,564 |
Operating Segments | Midwest | Electricity | |||
Segment Reporting Information [Line Items] | |||
Revenue from contracts with customers | 4,846 | 5,164 | 4,265 |
Revenue not from contracts | (191) | (507) | (205) |
Revenues | 4,655 | 4,657 | 4,060 |
Operating Segments | New York | Electricity | |||
Segment Reporting Information [Line Items] | |||
Revenue from contracts with customers | 1,910 | 2,004 | 1,633 |
Revenue not from contracts | 56 | (408) | (57) |
Revenues | 1,966 | 1,596 | 1,576 |
Operating Segments | ERCOT | Electricity | |||
Segment Reporting Information [Line Items] | |||
Revenue from contracts with customers | 1,232 | 954 | 896 |
Revenue not from contracts | 109 | 602 | 276 |
Revenues | 1,341 | 1,556 | 1,172 |
Operating Segments | Other Power Regions | Electricity | |||
Segment Reporting Information [Line Items] | |||
Revenue from contracts with customers | 4,956 | 5,035 | 3,937 |
Revenue not from contracts | 908 | 1,681 | 981 |
Revenues | 5,864 | 6,716 | 4,918 |
Intersegment Revenues | Mid-Atlantic | Electricity | |||
Segment Reporting Information [Line Items] | |||
Revenues | (50) | 5 | 20 |
Intersegment Revenues | Midwest | Electricity | |||
Segment Reporting Information [Line Items] | |||
Revenues | 3 | (7) | 0 |
Intersegment Revenues | New York | Electricity | |||
Segment Reporting Information [Line Items] | |||
Revenues | 55 | (1) | (1) |
Intersegment Revenues | ERCOT | Electricity | |||
Segment Reporting Information [Line Items] | |||
Revenues | 5 | (13) | 9 |
Intersegment Revenues | Other Power Regions | Electricity | |||
Segment Reporting Information [Line Items] | |||
Revenues | (13) | 16 | (28) |
Segment Reconciling Items | |||
Segment Reporting Information [Line Items] | |||
Unrealized mark-to-market gains (losses) | (972) | (1,013) | 565 |
Segment Reconciling Items | Natural Gas | |||
Segment Reporting Information [Line Items] | |||
Revenue from contracts with customers | 1,859 | 2,559 | 1,777 |
Revenue not from contracts | 1,866 | 2,408 | 1,602 |
Revenues | 3,725 | 4,967 | 3,379 |
Segment Reconciling Items | Product and Service, Other | |||
Segment Reporting Information [Line Items] | |||
Revenue from contracts with customers | 585 | 591 | 365 |
Revenue not from contracts | 1,594 | (802) | (385) |
Revenues | 2,179 | (211) | (20) |
Unrealized mark-to-market gains (losses) | $ 1,399 | $ (1,188) | $ (633) |
Segment Information - Generat_2
Segment Information - Generation Total Revenues Net of Purchased Power and Fuel Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Segment Reporting Information [Line Items] | |||
Total RNF for Reportable Segments | $ 9,252 | $ 7,297 | $ 6,208 |
Other | (335) | (319) | 1,278 |
Total RNF | 8,917 | 6,978 | 7,486 |
Mid-Atlantic | |||
Segment Reporting Information [Line Items] | |||
Total RNF for Reportable Segments | 2,924 | 2,138 | 2,264 |
Midwest | |||
Segment Reporting Information [Line Items] | |||
Total RNF for Reportable Segments | 3,255 | 2,764 | 2,717 |
New York | |||
Segment Reporting Information [Line Items] | |||
Total RNF for Reportable Segments | 1,251 | 1,067 | 1,161 |
ERCOT | |||
Segment Reporting Information [Line Items] | |||
Total RNF for Reportable Segments | 582 | 407 | (825) |
Other Power Regions | |||
Segment Reporting Information [Line Items] | |||
Total RNF for Reportable Segments | 1,240 | 921 | 891 |
Operating Segments | |||
Segment Reporting Information [Line Items] | |||
Total RNF for Reportable Segments | 9,271 | 7,410 | 6,431 |
Operating Segments | Mid-Atlantic | |||
Segment Reporting Information [Line Items] | |||
Total RNF for Reportable Segments | 2,972 | 2,129 | 2,247 |
Operating Segments | Midwest | |||
Segment Reporting Information [Line Items] | |||
Total RNF for Reportable Segments | 3,252 | 2,765 | 2,717 |
Operating Segments | New York | |||
Segment Reporting Information [Line Items] | |||
Total RNF for Reportable Segments | 1,189 | 1,061 | 1,151 |
Operating Segments | ERCOT | |||
Segment Reporting Information [Line Items] | |||
Total RNF for Reportable Segments | 588 | 503 | (668) |
Operating Segments | Other Power Regions | |||
Segment Reporting Information [Line Items] | |||
Total RNF for Reportable Segments | 1,270 | 952 | 984 |
Segment Reconciling Items | |||
Segment Reporting Information [Line Items] | |||
Other | (354) | (432) | 1,055 |
Unrealized mark-to-market gains (losses) | (972) | (1,013) | 565 |
Nuclear Fuel Amortization | 148 | ||
Intersegment Revenues | |||
Segment Reporting Information [Line Items] | |||
Total RNF for Reportable Segments | (19) | (113) | (223) |
Other | (19) | (113) | (223) |
Intersegment Revenues | Mid-Atlantic | |||
Segment Reporting Information [Line Items] | |||
Total RNF for Reportable Segments | (48) | 9 | 17 |
Intersegment Revenues | Midwest | |||
Segment Reporting Information [Line Items] | |||
Total RNF for Reportable Segments | 3 | (1) | 0 |
Intersegment Revenues | New York | |||
Segment Reporting Information [Line Items] | |||
Total RNF for Reportable Segments | 62 | 6 | 10 |
Intersegment Revenues | ERCOT | |||
Segment Reporting Information [Line Items] | |||
Total RNF for Reportable Segments | (6) | (96) | (157) |
Intersegment Revenues | Other Power Regions | |||
Segment Reporting Information [Line Items] | |||
Total RNF for Reportable Segments | $ (30) | $ (31) | $ (93) |
Accounts Receivable - Narrative
Accounts Receivable - Narrative (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Aug. 16, 2022 | Jan. 31, 2022 | Apr. 08, 2020 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||||
Unbilled customer revenues | $ 372 | $ 564 | |||
Credit facility | $ 6,108 | $ 5,802 | $ 4,500 | ||
Sale of Accounts Receivable | |||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||||
Credit facility | $ 1,100 | $ 900 |
Accounts Receivable - Purchases
Accounts Receivable - Purchases and Sales of Accounts Receivable (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
(Gain) loss on sale of receivables | $ 75 | $ 69 | $ 36 |
Proceeds from new transfers | 3,649 | 6,108 | 6,095 |
Cash collections received on DPP and reinvested in the Facility | 8,140 | 4,764 | 3,502 |
Cash collections reinvested in the Facility | 11,789 | 10,872 | 9,597 |
Total receivables sold | 356 | 423 | 147 |
Purchasers | |||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Cash collections received on DPP and reinvested in the Facility | 800 | 200 | 400 |
Sale of Accounts Receivable | |||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Derecognized receivables transferred at fair value | 1,516 | 1,615 | |
Less: Cash proceeds received | 300 | 1,100 | |
DPP | 1,216 | 515 | |
Customer accounts receivable sold into the Facility | $ 11,746 | $ 11,274 | $ 9,747 |
Early Plant Retirements - Narra
Early Plant Retirements - Narrative (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Sep. 30, 2021 | Dec. 31, 2023 | Dec. 31, 2021 | |
Nuclear Fleet | |||
Property, Plant and Equipment [Line Items] | |||
Operating license renewal period | 80 years | ||
Byron Dresden | Facility Closing | |||
Property, Plant and Equipment [Line Items] | |||
Other one-time charges | $ (9) | ||
Constellation Energy Generation, LLC | Byron Dresden | Facility Closing | |||
Property, Plant and Equipment [Line Items] | |||
Severance costs | $ (81) | ||
Other one-time charges | $ (13) |
Early Plant Retirements - Preta
Early Plant Retirements - Pretax Expense (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended |
Sep. 30, 2021 | Dec. 31, 2021 | |
Restructuring Cost and Reserve [Line Items] | ||
Restructuring, Incurred Cost, Statement of Income or Comprehensive Income [Extensible Enumeration] | Operating and maintenance | |
Facility Closing | Byron Dresden | ||
Restructuring Cost and Reserve [Line Items] | ||
Accelerated depreciation | $ 1,805 | |
Accelerated nuclear fuel amortization | 148 | |
One-time charges | (94) | |
Other charges | 9 | |
Contractual offset | (451) | |
Total | $ 1,417 | |
Constellation Energy Generation, LLC | Facility Closing | Byron Dresden | ||
Restructuring Cost and Reserve [Line Items] | ||
Other charges | $ 13 |
Property, Plant, and Equipmen_2
Property, Plant, and Equipment - Summary of Property, Plant and Equipment (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 39,539 | $ 36,548 |
Less: accumulated depreciation | 17,423 | 16,726 |
Property, plant, and equipment, net | 22,116 | 19,822 |
Nuclear fuel - work in progress | 1,265 | 937 |
Electric | ||
Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 32,889 | 30,804 |
Electric | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Average Service Life (years) | 1 year | |
Electric | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Average Service Life (years) | 60 years | |
Nuclear fuel | ||
Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 5,503 | 5,106 |
Less: accumulated depreciation | $ 2,484 | 2,657 |
Nuclear fuel | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Average Service Life (years) | 1 year | |
Nuclear fuel | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Average Service Life (years) | 8 years | |
Construction work in progress | ||
Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 1,133 | 630 |
Other property, plant, and equipment | ||
Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 14 | $ 8 |
Other property, plant, and equipment | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Average Service Life (years) | 1 year | |
Other property, plant, and equipment | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Average Service Life (years) | 10 years |
Property, Plant, and Equipmen_3
Property, Plant, and Equipment - Narrative (Details) | Mar. 06, 2020 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Peach Bottom Units 2 and 3 | ||||
Property, Plant and Equipment [Line Items] | ||||
Operating license renewal period | 20 years | |||
Electric | ||||
Property, Plant and Equipment [Line Items] | ||||
Annual depreciation rate | 3.26% | 3.46% | 8.67% |
Jointly Owned Electric Plant (D
Jointly Owned Electric Plant (Details) - Nuclear Plant - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Quad Cities | ||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ||
Ownership interest | 75% | |
Plant in service | $ 1,263 | $ 1,243 |
Accumulated depreciation | 805 | 761 |
Construction work in progress | $ 8 | 7 |
Peach Bottom | ||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ||
Ownership interest | 50% | |
Plant in service | $ 1,552 | 1,534 |
Accumulated depreciation | 689 | 659 |
Construction work in progress | $ 14 | 12 |
Salem | ||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ||
Ownership interest | 42.59% | |
Plant in service | $ 781 | 772 |
Accumulated depreciation | 357 | 328 |
Construction work in progress | $ 49 | 23 |
Nine Mile Point Unit 2 | ||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ||
Ownership interest | 82% | |
Plant in service | $ 1,073 | 1,063 |
Accumulated depreciation | 292 | 256 |
Construction work in progress | $ 35 | 26 |
South Texas Project | ||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ||
Ownership interest | 44% | |
Plant in service | $ 1,089 | 0 |
Accumulated depreciation | 5 | 0 |
Construction work in progress | $ 13 | $ 0 |
Asset Retirement Obligations -
Asset Retirement Obligations - Nuclear Decommissioning Asset Retirement Obligation Rollforward (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Accretion expense | $ 596 | $ 543 | $ 514 |
Nuclear Decommissioning | |||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Beginning balance | 12,500 | 12,676 | |
Net increase (decrease) due to changes in, and timing of, estimated future cash flows | 411 | (648) | |
Accretion expense | 582 | 532 | |
Acquisition of joint ownership in STP | 429 | 0 | |
Costs incurred related to decommissioning plants | (31) | (60) | |
Ending balance | 13,891 | 12,500 | $ 12,676 |
ARO, current obligation | $ 30 | $ 40 |
Asset Retirement Obligations _2
Asset Retirement Obligations - Narrative (Details) - USD ($) | 12 Months Ended | |||||
Mar. 31, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Nov. 01, 2023 | Jan. 31, 2022 | |
Asset Retirement Obligations [Line Items] | ||||||
Shortfall of decommissioning funds with recourse | $ 50,000,000 | |||||
Percent of additional decommissioning shortfall with recourse | 5% | |||||
Nuclear decommissioning trust funds | $ 16,398,000,000 | $ 14,114,000,000 | ||||
Number of years used in present value measurement | 30 years | |||||
Annual average accretion of the ARO | 4% | |||||
Historical five-year annual average pre-tax return on NDT funds | 8% | |||||
NRG Energy, Inc. | ||||||
Asset Retirement Obligations [Line Items] | ||||||
Ownership interest | 44% | |||||
Minimum | ||||||
Asset Retirement Obligations [Line Items] | ||||||
Number of years used in present value measurement | 10 years | |||||
Estimated targeted annual pre-tax return on nuclear decommissioning funds | 6.10% | |||||
Maximum | ||||||
Asset Retirement Obligations [Line Items] | ||||||
Number of years used in present value measurement | 70 years | |||||
Estimated targeted annual pre-tax return on nuclear decommissioning funds | 7.10% | |||||
Constellation Energy Generation, LLC | ||||||
Asset Retirement Obligations [Line Items] | ||||||
Nuclear decommissioning trust funds | $ 16,398,000,000 | 14,114,000,000 | ||||
Estimated annual after-tax return on nuclear decommissioning funds | 2% | |||||
PECO Energy Co | ||||||
Asset Retirement Obligations [Line Items] | ||||||
Estimated annual after-tax return on nuclear decommissioning funds | 3% | |||||
Nuclear Decommissioning | ||||||
Asset Retirement Obligations [Line Items] | ||||||
Net increase (decrease) due to changes in, and timing of, estimated future cash flows | $ 411,000,000 | (648,000,000) | ||||
Net increase due to revisions to projected decommission schedule | 610,000,000 | 320,000,000 | ||||
Net increase due to cost assumptions | 470,000,000 | |||||
Net decrease due to changes in assumed retirement dates | (675,000,000) | (235,000,000) | ||||
Net increase (decrease) in operating and maintenance expense | (68,000,000) | |||||
Net decrease due to increase in discount rates | (790,000,000) | |||||
Net increase due to higher estimated decommissioning costs | 75,000,000 | |||||
Increase (decrease) in ARO for impacts of revised decommissioning cost estimates | (226,000,000) | |||||
Asset retirement obligation | $ 13,891,000,000 | 12,500,000,000 | $ 12,676,000,000 | |||
Nine Mile Point Unit 2 | ||||||
Asset Retirement Obligations [Line Items] | ||||||
Percent of additional decommissioning shortfall with recourse | 50% | |||||
Nuclear decommissioning trust funds | $ 15,000,000 | |||||
Zion Station | ||||||
Asset Retirement Obligations [Line Items] | ||||||
Asset retirement obligation | $ 139,000,000 | 138,000,000 | ||||
Nonnuclear Decommissioning Asset Retirement Obligation | ||||||
Asset Retirement Obligations [Line Items] | ||||||
Asset retirement obligation | 257,000,000 | 239,000,000 | 216,000,000 | |||
Nuclear Decommissioning Byron | ||||||
Asset Retirement Obligations [Line Items] | ||||||
Decommissioning related activities | $ 193,000,000 | |||||
Nuclear Decommissioning Trust Fund Investments | ||||||
Asset Retirement Obligations [Line Items] | ||||||
Annual recovery | $ 4,000,000 | |||||
Assets, Total | ||||||
Asset Retirement Obligations [Line Items] | ||||||
Nuclear decommissioning trust funds | 16,398,000,000 | 14,127,000,000 | ||||
Assets, Total | Zion Station | ||||||
Asset Retirement Obligations [Line Items] | ||||||
Nuclear decommissioning trust funds | 62,000,000 | 58,000,000 | ||||
Other Current Assets | ||||||
Asset Retirement Obligations [Line Items] | ||||||
Nuclear decommissioning trust funds | $ 0 | $ 13,000,000 |
Asset Retirement Obligations _3
Asset Retirement Obligations - Noncurrent Related Party Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Asset Retirement Obligations [Line Items] | ||
Payables related to Regulatory Agreement Units | $ 3,688 | $ 2,897 |
Affiliated Entities | ||
Asset Retirement Obligations [Line Items] | ||
Payables related to Regulatory Agreement Units | 3,688 | 2,897 |
Affiliated Entities | ComEd | ||
Asset Retirement Obligations [Line Items] | ||
Payables related to Regulatory Agreement Units | 2,955 | 2,660 |
Affiliated Entities | PECO | ||
Asset Retirement Obligations [Line Items] | ||
Payables related to Regulatory Agreement Units | 278 | 237 |
Affiliated Entities | CenterPoint Energy Houston Electric, LLC | ||
Asset Retirement Obligations [Line Items] | ||
Payables related to Regulatory Agreement Units | 338 | 0 |
Affiliated Entities | AEP Texas, Inc. | ||
Asset Retirement Obligations [Line Items] | ||
Payables related to Regulatory Agreement Units | $ 117 | $ 0 |
Asset Retirement Obligations _4
Asset Retirement Obligations - Non-Nuclear Asset Retirement Obligations Rollforward (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Accretion expense | $ 596 | $ 543 | $ 514 |
Nonnuclear Decommissioning Asset Retirement Obligation | |||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Beginning balance | 239 | 216 | |
Other one-time charges | 14 | 18 | |
Accretion expense | 14 | 11 | |
Asset divestitures | (9) | (1) | |
Payments | (1) | (5) | |
Ending balance | $ 257 | $ 239 | $ 216 |
Leases - Lease Terms (Details)
Leases - Lease Terms (Details) | 12 Months Ended |
Dec. 31, 2023 | |
Minimum | |
Lessor, Lease, Description [Line Items] | |
Remaining lease terms | 1 year |
Options to extend the term | 2 years |
Options to terminate within | 1 year |
Remaining lease terms | 1 year |
Options to extend the term | 1 year |
Maximum | |
Lessor, Lease, Description [Line Items] | |
Remaining lease terms | 32 years |
Options to extend the term | 30 years |
Remaining lease terms | 17 years |
Options to extend the term | 20 years |
Leases - Components of Lease Co
Leases - Components of Lease Cost (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Leases [Abstract] | |||
Operating lease costs | $ 96 | $ 109 | $ 161 |
Variable lease costs | 146 | 169 | 168 |
Total lease costs | 242 | 278 | 329 |
Sublease income | $ 50 | $ 49 | $ 44 |
Leases - Supplemental Balance S
Leases - Supplemental Balance Sheet Information (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Supplemental Balance Sheet Information [Line Items] | ||
Operating lease ROU assets | $ 494 | $ 545 |
Other current liabilities | 67 | 67 |
Other deferred credits and other liabilities | 583 | 643 |
Operating lease liabilities | $ 650 | $ 710 |
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Other | Other |
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration] | Other | Other |
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration] | Other Liabilities, Noncurrent | Other Liabilities, Noncurrent |
Long-term Contract for Purchase of Electric Power | ||
Supplemental Balance Sheet Information [Line Items] | ||
Operating lease ROU assets | $ 212 | $ 248 |
Operating lease liabilities | $ 334 | $ 377 |
Leases - Operating Leases (Deta
Leases - Operating Leases (Details) | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Lessee, Lease, Description [Line Items] | |||
Weighted average remaining lease term | 8 years 4 months 24 days | 9 years 3 months 18 days | 10 years 1 month 6 days |
Weighted average discount rate | 5% | 5% | 5% |
Lessee - Lessee Future Minimum
Lessee - Lessee Future Minimum Operating Lease Maturity Payments (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Leases [Abstract] | ||
2024 | $ 101 | |
2025 | 104 | |
2026 | 104 | |
2027 | 102 | |
2028 | 103 | |
Thereafter | 325 | |
Total lease payments | 839 | |
Less: Imputed interest | 189 | |
Operating lease liabilities | $ 650 | $ 710 |
Leases - Supplemental Cash Flow
Leases - Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Leases [Abstract] | |||
Cash paid for amounts included in the measurement of operating lease liabilities | $ 102 | $ 114 | $ 162 |
ROU assets obtained in exchange for operating lease obligations | $ 13 | $ 14 | $ 2 |
Lessor - Components of Operatin
Lessor - Components of Operating Lease Income (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Leases [Abstract] | |||
Operating lease income | $ 51 | $ 51 | $ 47 |
Variable lease income | $ 248 | $ 258 | $ 261 |
Lessor - Operating Lease, Payme
Lessor - Operating Lease, Payments, Fiscal Year Maturity (Details) $ in Millions | Dec. 31, 2023 USD ($) |
Leases [Abstract] | |
2024 | $ 48 |
2025 | 48 |
2026 | 49 |
2027 | 49 |
2028 | 48 |
Thereafter | 85 |
Total | $ 327 |
Asset Impairments (Details)
Asset Impairments (Details) - Constellation Energy Generation, LLC - Constellation New England $ in Millions | 3 Months Ended |
Jun. 30, 2021 USD ($) | |
Property, Plant and Equipment [Line Items] | |
Pre-tax impairment charge | $ 350 |
Impairment, Long-Lived Asset, Held-for-Use, Statement of Income or Comprehensive Income [Extensible Enumeration] | Operating and maintenance |
Intangible Assets - Schedule of
Intangible Assets - Schedule of Goodwill (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2023 USD ($) | |
Goodwill [Roll Forward] | |
Beginning balance | $ 47 |
Goodwill resulting from acquisition of STP | 378 |
Ending balance | $ 425 |
Intangible Assets - Schedule _2
Intangible Assets - Schedule of Other Intangible Assets (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Finite-Lived Intangible Assets [Line Items] | ||
Gross | $ 2,134 | $ 2,316 |
Accumulated Amortization | (1,798) | (1,973) |
Net | 336 | 343 |
Unamortized Energy Contracts | ||
Finite-Lived Intangible Assets [Line Items] | ||
Gross | 1,892 | 1,960 |
Accumulated Amortization | (1,631) | (1,708) |
Net | 261 | 252 |
Customer Relationships | ||
Finite-Lived Intangible Assets [Line Items] | ||
Gross | 242 | 356 |
Accumulated Amortization | (167) | (265) |
Net | $ 75 | $ 91 |
Intangible Assets - Summary of
Intangible Assets - Summary of Amortization Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |||
Amortization Expense | $ 58 | $ 61 | $ 80 |
Intangible Assets - Schedule _3
Intangible Assets - Schedule of Finite-Lived Intangible Assets, Future Amortization Expense (Details) $ in Millions | Dec. 31, 2023 USD ($) |
Goodwill and Intangible Assets Disclosure [Abstract] | |
2024 | $ 62 |
2025 | 58 |
2026 | 51 |
2027 | 37 |
2028 | 31 |
2029 and thereafter | $ 97 |
Income Taxes - Components of In
Income Taxes - Components of Income Tax Expense (Benefit) from Continuing Operations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Federal | |||
Current | $ 464 | $ 219 | $ 394 |
Deferred | 301 | (655) | (153) |
ITC amortization | (15) | (15) | (15) |
State | |||
Current | 142 | 34 | 36 |
Deferred | (33) | 29 | (37) |
Total income tax (benefit) expense | $ 859 | $ (388) | $ 225 |
Income Taxes - Reconciliation t
Income Taxes - Reconciliation to Effective Tax Rate (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |||
U.S. federal statutory rate | 21% | 21% | 21% |
State income taxes, net of federal income tax benefit | 3.50% | (9.20%) | 0% |
Qualified NDT fund income and losses | 10.30% | 46.30% | 165.10% |
Amortization of investment tax credit, including deferred taxes on basis differences | (0.50%) | 2.20% | (9.00%) |
Production tax credits and other credits | (0.60%) | 7.70% | (28.70%) |
Noncontrolling interests | 0.40% | (0.30%) | (3.00%) |
Other | 1% | 3.90% | 2.60% |
Effective income tax rate | 35.10% | 71.60% | 148% |
State rate changes and tax positions | $ (4) | $ 30 | |
Prior period income tax adjustment | $ 32 |
Income Taxes - Tax Effects of T
Income Taxes - Tax Effects of Temporary Differences and Carryforwards (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Income Tax Disclosure [Abstract] | ||
Plant basis differences | $ (3,130) | $ (3,005) |
Accrual-based contracts | (32) | (35) |
Derivatives and other financial instruments | 984 | 43 |
Deferred pension and postretirement obligation | 287 | |
Deferred pension and postretirement obligation | (314) | |
Nuclear decommissioning activities | (640) | (371) |
Tax loss carryforward, net of valuation allowances | 47 | 67 |
Tax credit carryforward | 0 | 179 |
Investment in partnerships | (193) | (205) |
Other, net | 460 | 407 |
Deferred income tax liabilities (net) | 2,818 | 2,633 |
Unamortized ITCs | (339) | (354) |
Total deferred income tax liabilities (net) and unamortized ITCs | $ 3,157 | $ 2,987 |
Income Taxes - Schedule of Carr
Income Taxes - Schedule of Carryforwards and Corresponding Valuation Allowances (Details) $ in Millions | Dec. 31, 2023 USD ($) |
Federal | |
Operating Loss Carryforwards [Line Items] | |
Federal general business credits carryforwards and other carryforwards | $ 0 |
State | |
Operating Loss Carryforwards [Line Items] | |
State net operating losses and other carryforwards | 477 |
Deferred taxes on state tax attributes (net) | 21 |
Valuation allowance on state tax attributes | (10) |
Foreign | |
Operating Loss Carryforwards [Line Items] | |
State net operating losses and other carryforwards | 145 |
Deferred taxes on state tax attributes (net) | $ 36 |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) - USD ($) | Feb. 26, 2024 | Dec. 31, 2023 | Dec. 31, 2022 | Feb. 01, 2022 | Dec. 31, 2021 |
Income Taxes [Line Items] | |||||
Allocation of federal benefits under tax sharing agreement | $ 64,000,000 | ||||
Deferred income taxes and unamortized ITCs | $ 3,209,000,000 | $ 3,031,000,000 | |||
Other | 917,000,000 | 731,000,000 | |||
Other deferred debits and other assets | 1,910,000,000 | 2,059,000,000 | |||
Separation from Parent | |||||
Income Taxes [Line Items] | |||||
Deferred income taxes and unamortized ITCs | $ 508,000,000 | ||||
Other | 336,000,000 | 168,000,000 | 11,000,000 | ||
Other deferred debits and other assets | 178,000,000 | 362,000,000 | 497,000,000 | ||
Separation from Parent | Subsequent Event | |||||
Income Taxes [Line Items] | |||||
Other | $ 152,000,000 | ||||
Separation from Parent | Affiliated Entities | |||||
Income Taxes [Line Items] | |||||
Payable for tax liabilities upon separation | 103,000,000 | ||||
Separation from Parent | Accounts Payable | Affiliated Entities | |||||
Income Taxes [Line Items] | |||||
Payable for tax liabilities upon separation | 53,000,000 | ||||
Separation from Parent | Other Noncurrent Liabilities | Affiliated Entities | |||||
Income Taxes [Line Items] | |||||
Payable for tax liabilities upon separation | 37,000,000 | 50,000,000 | $ 50,000,000 | ||
Separation from Parent | Other Receivables, Net, Current | Affiliated Entities | |||||
Income Taxes [Line Items] | |||||
Payable for tax liabilities upon separation | 11,000,000 | 18,000,000 | |||
Separation from Parent | Accounts Payable and Accrued Liabilities | Affiliated Entities | |||||
Income Taxes [Line Items] | |||||
Payable for tax liabilities upon separation | $ 0 | $ 0 |
Retirement Benefits - Narrative
Retirement Benefits - Narrative (Details) $ in Millions | 11 Months Ended | 12 Months Ended | ||||
Feb. 01, 2022 USD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2023 USD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Dec. 31, 2024 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Actuarial losses and prior service costs | $ 2,006 | |||||
Matching contributions to savings plan | $ 106 | $ 90 | $ 53 | |||
Pension Benefits | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Pension obligations | 953 | |||||
Pension plan assets | 8,267 | $ 6,660 | 6,687 | 6,660 | 1,683 | |
Acquisition-related adjustment | 0 | $ 187 | ||||
Actual long-term rate of return on plan assets | 0.0650 | |||||
Expected long-term rate of return on plan assets | 0.0650 | |||||
Pension Benefits | Forecast | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Expected long-term rate of return on plan assets | 0.0650 | |||||
Pension Benefits | South Texas Project | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Acquisition-related adjustment | $ 17 | |||||
OPEB | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Pension obligations | 876 | |||||
Pension plan assets | $ 904 | 734 | 692 | $ 734 | $ 0 | |
Acquisition-related adjustment | $ 0 | $ 14 | ||||
Actual long-term rate of return on plan assets | 0.0950 | |||||
Expected long-term rate of return on plan assets | 0.0650 | |||||
OPEB | Forecast | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Expected long-term rate of return on plan assets | 0.0650 | |||||
OPEB | South Texas Project | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Acquisition-related adjustment | $ 14 |
Retirement Benefits - Benefit O
Retirement Benefits - Benefit Obligation and Plan Assets (Details) - USD ($) $ in Millions | 1 Months Ended | 11 Months Ended | 12 Months Ended | ||
Jan. 31, 2022 | Dec. 31, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Change in benefit obligation: | |||||
Service cost | $ 105 | $ 151 | $ 174 | ||
Pension Benefits | |||||
Change in benefit obligation: | |||||
Beginning balance | $ 0 | 7,275 | 0 | ||
Separation-related adjustment | 9,220 | ||||
Ending balance | $ 7,275 | 7,770 | 7,275 | 0 | |
Service cost | 115 | 89 | 126 | 145 | |
Interest cost | 269 | 394 | |||
Plan participants' contributions | 0 | 0 | |||
Actuarial loss/(gain), net | (1,756) | 368 | |||
Acquisition-related adjustment | 0 | 187 | |||
Settlements | (15) | 0 | |||
Gross benefits paid | (558) | (543) | |||
Change in plan assets: | |||||
Beginning balance | 1,683 | 6,660 | 1,683 | ||
Separation-related adjustment | 6,584 | ||||
Ending balance | 6,660 | 6,687 | 6,660 | 1,683 | |
Actual return (loss) on plan assets | (1,245) | 374 | |||
Employer contributions | 211 | 26 | |||
Plan participants' contributions | 0 | 0 | |||
Gross benefits paid | (558) | (543) | |||
Acquisition-related adjustment | 0 | 170 | |||
Settlements | (15) | 0 | |||
Over (under) funded status (Plan assets less benefit obligations) | (615) | (1,083) | (615) | ||
Pension Benefits | South Texas Project | |||||
Change in benefit obligation: | |||||
Acquisition-related adjustment | 17 | ||||
OPEB | |||||
Change in benefit obligation: | |||||
Beginning balance | 847 | 1,360 | 847 | ||
Separation-related adjustment | 933 | ||||
Ending balance | 1,360 | 1,443 | 1,360 | 847 | |
Service cost | 23 | 16 | 25 | 29 | |
Interest cost | 52 | 74 | |||
Plan participants' contributions | 20 | 23 | |||
Actuarial loss/(gain), net | (401) | 99 | |||
Acquisition-related adjustment | 0 | 14 | |||
Settlements | 0 | 0 | |||
Gross benefits paid | (114) | (143) | |||
Change in plan assets: | |||||
Beginning balance | 0 | 734 | 0 | ||
Separation-related adjustment | $ 904 | ||||
Ending balance | 734 | 692 | 734 | $ 0 | |
Actual return (loss) on plan assets | (99) | 50 | |||
Employer contributions | 0 | 0 | |||
Plan participants' contributions | 15 | 18 | |||
Gross benefits paid | (86) | (110) | |||
Acquisition-related adjustment | 0 | 0 | |||
Settlements | 0 | 0 | |||
Over (under) funded status (Plan assets less benefit obligations) | $ (626) | (751) | $ (626) | ||
OPEB | South Texas Project | |||||
Change in benefit obligation: | |||||
Acquisition-related adjustment | $ 14 |
Retirement Benefits - Benefit_2
Retirement Benefits - Benefit Obligations Net of Plan Assets, Balance Sheet (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Pension Benefits | ||
Defined Contribution Plan Disclosure [Line Items] | ||
Other current liabilities | $ (13) | $ (10) |
Pension obligations | (1,070) | (605) |
Non-pension postretirement benefit obligations | 0 | 0 |
OPEB | ||
Defined Contribution Plan Disclosure [Line Items] | ||
Other current liabilities | (19) | (17) |
Pension obligations | 0 | 0 |
Non-pension postretirement benefit obligations | $ (732) | $ (609) |
Retirement Benefits - Accumulat
Retirement Benefits - Accumulated Benefit Obligation (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Retirement Benefits [Abstract] | ||
ABO | $ (7,567) | $ (7,121) |
Fair value of net plan assets | $ 6,687 | $ 6,660 |
Retirement Benefits - Net Benef
Retirement Benefits - Net Benefit Costs (Details) - USD ($) $ in Millions | 11 Months Ended | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Defined Contribution Plan Disclosure [Line Items] | ||||
Service cost | $ 105 | $ 151 | $ 174 | |
Interest cost | $ 480 | $ 345 | $ 280 | |
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Interest Cost, Statement of Income or Comprehensive Income [Extensible Enumeration] | Other, net | Other, net | Other, net | |
Expected return on assets | $ (565) | $ (620) | $ (551) | |
Defined Benefit Plan, Net Periodic Benefit (Cost) Credit, Expected Return (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Other, net | Other, net | Other, net | |
Prior service (credit) cost | $ (9) | $ (6) | $ (8) | |
Actuarial (gain) loss | $ 36 | $ 147 | $ 209 | |
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) Excluding Service Cost, Statement of Income or Comprehensive Income [Extensible Enumeration] | Other, net | Other, net | Other, net | |
Settlement charges | $ 0 | $ 6 | $ 20 | |
Non-service components of pension benefits & OPEB credit | (58) | (128) | (50) | |
Net periodic benefit cost | 47 | 23 | 124 | |
Pension Benefits | ||||
Defined Contribution Plan Disclosure [Line Items] | ||||
Service cost | $ 115 | 89 | 126 | 145 |
Interest cost | 404 | 290 | 235 | |
Expected return on assets | (520) | (565) | (493) | |
Prior service (credit) cost | 1 | 1 | 1 | |
Actuarial (gain) loss | 48 | 148 | 199 | |
Settlement charges | 0 | 6 | 20 | |
Non-service components of pension benefits & OPEB credit | (67) | (120) | (38) | |
Net periodic benefit cost | 22 | 6 | 107 | |
OPEB | ||||
Defined Contribution Plan Disclosure [Line Items] | ||||
Service cost | $ 23 | 16 | 25 | 29 |
Interest cost | 76 | 55 | 45 | |
Expected return on assets | (45) | (55) | (58) | |
Prior service (credit) cost | (10) | (7) | (9) | |
Actuarial (gain) loss | (12) | (1) | 10 | |
Settlement charges | 0 | 0 | 0 | |
Non-service components of pension benefits & OPEB credit | 9 | (8) | (12) | |
Net periodic benefit cost | 25 | 17 | 17 | |
Pension Plan and Other Postretirement Benefits Plan | ||||
Defined Contribution Plan Disclosure [Line Items] | ||||
Non-service components of pension benefits & OPEB credit | (54) | (116) | (50) | |
Net periodic benefit cost | $ 94 | $ 131 | $ 144 |
Retirement Benefits - Changes i
Retirement Benefits - Changes in Plan Assets Recognized in AOCI (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Pension Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Separation-related adjustment | $ 0 | $ 2,664 |
Current year actuarial (gain) loss | 509 | 11 |
Amortization of actuarial (loss) gain | (46) | (134) |
Amortization of prior service (cost) credit | (1) | (1) |
Settlements | 0 | (6) |
Total recognized in AOCI | 462 | 2,534 |
Prior service (credit) cost | 9 | 10 |
Actuarial (gain) loss | 2,985 | 2,524 |
Total | 2,994 | 2,534 |
OPEB | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Separation-related adjustment | 0 | 22 |
Current year actuarial (gain) loss | 94 | (253) |
Amortization of actuarial (loss) gain | 14 | 1 |
Amortization of prior service (cost) credit | 6 | 7 |
Settlements | 0 | 0 |
Total recognized in AOCI | 114 | (223) |
Prior service (credit) cost | (24) | (30) |
Actuarial (gain) loss | (85) | (193) |
Total | $ (109) | $ (223) |
Retirement Benefits - Remaining
Retirement Benefits - Remaining Service Period (Details) | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Pension Benefits | ||
Defined Contribution Plan Disclosure [Line Items] | ||
Pension plans | 12 years 4 months 24 days | 12 years 2 months 12 days |
OPEB | ||
Defined Contribution Plan Disclosure [Line Items] | ||
Benefit Eligibility Age | 7 years 6 months | 7 years 4 months 24 days |
Expected Retirement | 8 years 3 months 18 days | 8 years 3 months 18 days |
Retirement Benefits - Assumptio
Retirement Benefits - Assumptions (Details) | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | ||
5 year period average rate | 4.25% | |
After 5 year period average rate | 3.75% | |
Pension Benefits | ||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | ||
Discount rate | 5.17% | 5.52% |
Investment crediting rate | 5.07% | 5.15% |
Rate of compensation increase | 4.25% | 3.75% |
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||
Discount rate | 5.52% | 3.23% |
Investment crediting rate | 5.15% | 3.86% |
Expected long-term rate of return on plan assets | 6.50% | 6.50% |
Rate of compensation increase | 3.75% | 3.75% |
OPEB | ||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | ||
Discount rate | 5.15% | 5.50% |
Rate of compensation increase | 4.25% | 3.75% |
Healthcare cost trend on covered charges | 5% | 5% |
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | ||
Discount rate | 5.50% | 3.21% |
Expected long-term rate of return on plan assets | 6.51% | 6.39% |
Rate of compensation increase | 3.75% | 3.75% |
Retirement Benefits - Contribut
Retirement Benefits - Contributions Made to Pension and Other Postretirement Benefit Plans (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Total contributions | $ 54 | $ 238 | $ 259 |
Planned contributions | 194 | ||
Pension Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total contributions | 26 | 212 | 231 |
Planned contributions | 161 | ||
Pension Benefits | Qualified Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total contributions | 21 | 192 | |
OPEB | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total contributions | 28 | $ 26 | $ 28 |
Planned contributions | 20 | ||
Non-Qualified Pension Plans | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Planned contributions | $ 13 |
Retirement Benefits - Estimated
Retirement Benefits - Estimated Future Benefit Payments (Details) $ in Millions | Dec. 31, 2023 USD ($) |
Pension Benefits | |
Defined Contribution Plan Disclosure [Line Items] | |
2024 | $ 576 |
2025 | 575 |
2026 | 581 |
2027 | 581 |
2028 | 587 |
2029 through 2033 | 2,880 |
Total estimated future benefits payments through 2033 | 5,780 |
OPEB | |
Defined Contribution Plan Disclosure [Line Items] | |
2024 | 117 |
2025 | 116 |
2026 | 115 |
2027 | 114 |
2028 | 114 |
2029 through 2033 | 546 |
Total estimated future benefits payments through 2033 | $ 1,122 |
Retirement Benefits - Target Al
Retirement Benefits - Target Allocation (Details) | Dec. 31, 2023 | Dec. 31, 2022 |
Pension Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Total | 100% | 100% |
OPEB | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Total | 100% | 100% |
Equities | Pension Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Total | 21% | 21% |
Equities | OPEB | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Total | 17% | 43% |
Fixed income | Pension Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Total | 54% | 54% |
Fixed income | OPEB | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Total | 70% | 45% |
Alternative investments | Pension Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Total | 25% | 25% |
Alternative investments | OPEB | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Total | 13% | 12% |
Retirement Benefits - Fair Valu
Retirement Benefits - Fair Value of Plan Assets (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Feb. 01, 2022 | Dec. 31, 2021 |
Defined Benefit Plan Disclosure [Line Items] | ||||
Notational amount | $ 15 | $ 41 | ||
Net liabilities excluded | 263 | 43 | ||
Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 6,687 | 6,660 | $ 8,267 | $ 1,683 |
Derivative instruments | 31 | 6 | ||
Notational amount | 1,986 | 1,879 | ||
OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 692 | 734 | $ 904 | $ 0 |
Fair Value, Recurring | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 7,642 | 7,437 | ||
Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 6,950 | 6,703 | ||
Fair Value, Recurring | OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 692 | 734 | ||
Total assets measured at fair value | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 3,667 | 3,824 | ||
Total assets measured at fair value | Fair Value, Recurring | OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 388 | 320 | ||
Level 1 | Fair Value, Recurring | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 1,824 | 1,944 | ||
Level 1 | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 1,530 | 1,685 | ||
Level 1 | Fair Value, Recurring | OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 294 | 259 | ||
Level 2 | Fair Value, Recurring | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 2,231 | 2,012 | ||
Level 2 | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 2,137 | 1,951 | ||
Level 2 | Fair Value, Recurring | OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 94 | 61 | ||
Level 3 | Fair Value, Recurring | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 0 | 188 | ||
Level 3 | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 0 | 188 | ||
Level 3 | Fair Value, Recurring | OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 0 | 0 | ||
Assets measured at NAV | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 3,283 | 2,879 | ||
Assets measured at NAV | Fair Value, Recurring | OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 304 | 414 | ||
Cash equivalents | Total assets measured at fair value | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 192 | 216 | ||
Cash equivalents | Total assets measured at fair value | Fair Value, Recurring | OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 0 | 40 | ||
Cash equivalents | Level 1 | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 192 | 216 | ||
Cash equivalents | Level 1 | Fair Value, Recurring | OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 0 | 40 | ||
Cash equivalents | Level 2 | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 0 | 0 | ||
Cash equivalents | Level 2 | Fair Value, Recurring | OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 0 | 0 | ||
Cash equivalents | Level 3 | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 0 | 0 | ||
Cash equivalents | Level 3 | Fair Value, Recurring | OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 0 | 0 | ||
Equities | Total assets measured at fair value | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 598 | 776 | ||
Equities | Total assets measured at fair value | Fair Value, Recurring | OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 232 | 152 | ||
Equities | Level 1 | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 598 | 776 | ||
Equities | Level 1 | Fair Value, Recurring | OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 232 | 152 | ||
Equities | Level 2 | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 0 | 0 | ||
Equities | Level 2 | Fair Value, Recurring | OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 0 | 0 | ||
Equities | Level 3 | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 0 | 0 | ||
Equities | Level 3 | Fair Value, Recurring | OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 0 | 0 | ||
Fixed income | Total assets measured at fair value | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 2,877 | 2,652 | ||
Fixed income | Total assets measured at fair value | Fair Value, Recurring | OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 156 | 128 | ||
Fixed income | Level 1 | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 740 | 693 | ||
Fixed income | Level 1 | Fair Value, Recurring | OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 62 | 67 | ||
Fixed income | Level 2 | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 2,137 | 1,951 | ||
Fixed income | Level 2 | Fair Value, Recurring | OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 94 | 61 | ||
Fixed income | Level 3 | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 0 | 8 | ||
Fixed income | Level 3 | Fair Value, Recurring | OPEB | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 0 | 0 | ||
Private equity | Total assets measured at fair value | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 0 | 180 | ||
Private equity | Level 1 | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 0 | 0 | ||
Private equity | Level 2 | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | 0 | 0 | ||
Private equity | Level 3 | Fair Value, Recurring | Pension Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension plan assets | $ 0 | $ 180 |
Retirement Benefits - Reconcili
Retirement Benefits - Reconciliation of Unobservable Inputs (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Defined Benefit Plan Disclosure [Line Items] | ||
Beginning Balance | $ 188 | $ 0 |
Separation-related adjustment | 9 | |
Relating to assets still held as of the reporting date | 12 | (55) |
Relating to assets sold during the period | (13) | |
Purchases | 8 | 18 |
Settlements | (187) | (4) |
Transfers into Level 3 | (8) | (220) |
Ending Balance | 0 | 188 |
Fixed income | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Beginning Balance | 8 | 0 |
Separation-related adjustment | 9 | |
Relating to assets still held as of the reporting date | 0 | (1) |
Relating to assets sold during the period | 0 | |
Purchases | 0 | 0 |
Settlements | 0 | 0 |
Transfers into Level 3 | (8) | 0 |
Ending Balance | 0 | 8 |
Private credit | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Beginning Balance | 180 | 0 |
Separation-related adjustment | 0 | |
Relating to assets still held as of the reporting date | 12 | (54) |
Relating to assets sold during the period | (13) | |
Purchases | 8 | 18 |
Settlements | (187) | (4) |
Transfers into Level 3 | 0 | (220) |
Ending Balance | $ 0 | $ 180 |
Derivative Financial Instrume_3
Derivative Financial Instruments - Summary of Derivative Fair Value Balances (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Derivative [Line Items] | ||
Mark-to-market derivative assets (current) | $ 1,179 | $ 2,368 |
Mark-to-market derivative assets (noncurrent) | 995 | 1,261 |
Mark-to-market derivative liabilities (current) | (632) | (1,558) |
Mark-to-market derivative liabilities (noncurrent) | (419) | (983) |
Variation margin | 1,712 | 836 |
Commodity Contract | ||
Derivative [Line Items] | ||
Mark-to-market derivative assets (current) | 1,160 | 2,344 |
Mark-to-market derivative assets (noncurrent) | 993 | 1,243 |
Total mark-to-market derivative assets | 2,153 | 3,587 |
Mark-to-market derivative liabilities (current) | (627) | (1,558) |
Mark-to-market derivative liabilities (noncurrent) | (418) | (983) |
Total mark-to-market derivative liabilities | (1,045) | (2,541) |
Total mark-to-market derivative net assets (liabilities) | 1,108 | 1,046 |
Commodity Contract | Collateral | ||
Derivative [Line Items] | ||
Mark-to-market derivative assets (current) | 703 | 161 |
Mark-to-market derivative assets (noncurrent) | 330 | 217 |
Total mark-to-market derivative assets | 1,033 | 378 |
Mark-to-market derivative liabilities (current) | 922 | 374 |
Mark-to-market derivative liabilities (noncurrent) | 445 | 146 |
Total mark-to-market derivative liabilities | 1,367 | 520 |
Total mark-to-market derivative net assets (liabilities) | 2,400 | 898 |
Commodity Contract | Netting | ||
Derivative [Line Items] | ||
Mark-to-market derivative assets (current) | (7,472) | (13,123) |
Mark-to-market derivative assets (noncurrent) | (2,682) | (4,074) |
Total mark-to-market derivative assets | (10,154) | (17,197) |
Mark-to-market derivative liabilities (current) | 7,472 | 13,123 |
Mark-to-market derivative liabilities (noncurrent) | 2,682 | 4,074 |
Total mark-to-market derivative liabilities | 10,154 | 17,197 |
Total mark-to-market derivative net assets (liabilities) | 0 | 0 |
Commodity Contract | Economic Hedges | ||
Derivative [Line Items] | ||
Mark-to-market derivative assets (current) | 7,927 | 15,296 |
Mark-to-market derivative assets (noncurrent) | 3,345 | 5,100 |
Total mark-to-market derivative assets | 11,272 | 20,396 |
Mark-to-market derivative liabilities (current) | (9,019) | (15,049) |
Mark-to-market derivative liabilities (noncurrent) | (3,545) | (5,203) |
Total mark-to-market derivative liabilities | (12,564) | (20,252) |
Total mark-to-market derivative net assets (liabilities) | (1,292) | 144 |
Commodity Contract | Proprietary Trading | ||
Derivative [Line Items] | ||
Mark-to-market derivative assets (current) | 2 | 10 |
Mark-to-market derivative assets (noncurrent) | 0 | 0 |
Total mark-to-market derivative assets | 2 | 10 |
Mark-to-market derivative liabilities (current) | (2) | (6) |
Mark-to-market derivative liabilities (noncurrent) | 0 | 0 |
Total mark-to-market derivative liabilities | (2) | (6) |
Total mark-to-market derivative net assets (liabilities) | 0 | 4 |
Interest Rate Swap | ||
Derivative [Line Items] | ||
Mark-to-market derivative assets (current) | 19 | 24 |
Mark-to-market derivative assets (noncurrent) | 2 | 18 |
Total mark-to-market derivative assets | 21 | 42 |
Mark-to-market derivative liabilities (current) | (5) | 0 |
Mark-to-market derivative liabilities (noncurrent) | (1) | 0 |
Total mark-to-market derivative liabilities | (6) | 0 |
Total mark-to-market derivative net assets (liabilities) | 15 | 42 |
Interest Rate Swap | Netting | ||
Derivative [Line Items] | ||
Mark-to-market derivative assets (current) | (1) | (5) |
Mark-to-market derivative assets (noncurrent) | 0 | 0 |
Total mark-to-market derivative assets | (1) | (5) |
Mark-to-market derivative liabilities (current) | 1 | 5 |
Mark-to-market derivative liabilities (noncurrent) | 0 | 0 |
Total mark-to-market derivative liabilities | 1 | 5 |
Total mark-to-market derivative net assets (liabilities) | 0 | 0 |
Interest Rate Swap | Economic Hedges | ||
Derivative [Line Items] | ||
Mark-to-market derivative assets (current) | 20 | 29 |
Mark-to-market derivative assets (noncurrent) | 2 | 18 |
Total mark-to-market derivative assets | 22 | 47 |
Mark-to-market derivative liabilities (current) | (6) | (5) |
Mark-to-market derivative liabilities (noncurrent) | (1) | 0 |
Total mark-to-market derivative liabilities | (7) | (5) |
Total mark-to-market derivative net assets (liabilities) | $ 15 | $ 42 |
Derivative Financial Instrume_4
Derivative Financial Instruments - Summary of Economic Hedges (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Derivative [Line Items] | |||
Gains (Losses) | $ (996) | $ (986) | $ 568 |
Economic Hedges | Commodity Contract | |||
Derivative [Line Items] | |||
Gains (Losses) | (966) | (1,026) | 571 |
Economic Hedges | Commodity Contract | Operating revenues | |||
Derivative [Line Items] | |||
Gains (Losses) | 1,402 | (1,193) | (635) |
Economic Hedges | Commodity Contract | Purchased power and fuel | |||
Derivative [Line Items] | |||
Gains (Losses) | $ (2,368) | $ 167 | $ 1,206 |
Derivative Financial Instrume_5
Derivative Financial Instruments - Narrative (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Derivative [Line Items] | ||
Notational amount | $ 15 | $ 41 |
Economic Hedges | ||
Derivative [Line Items] | ||
Notational amount | $ 562 | $ 524 |
Derivative Financial Instrume_6
Derivative Financial Instruments - Summary of Credit Risk Exposure (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2023 USD ($) counterparty | |
Derivative [Line Items] | |
Cash collateral | $ 44 |
Letters of credit held | 59 |
Total Exposure Before Credit Collateral | |
Derivative [Line Items] | |
Total | 1,654 |
Total Exposure Before Credit Collateral | Internally rated — investment grade | |
Derivative [Line Items] | |
Total | 116 |
Total Exposure Before Credit Collateral | Internally rated — non-investment grade | |
Derivative [Line Items] | |
Total | 259 |
Total Exposure Before Credit Collateral | Investment grade | |
Derivative [Line Items] | |
Total | 1,257 |
Total Exposure Before Credit Collateral | Non-investment grade | |
Derivative [Line Items] | |
Total | 22 |
Credit Collateral | |
Derivative [Line Items] | |
Total | 103 |
Credit Collateral | Internally rated — investment grade | |
Derivative [Line Items] | |
Total | 0 |
Credit Collateral | Internally rated — non-investment grade | |
Derivative [Line Items] | |
Total | 45 |
Credit Collateral | Investment grade | |
Derivative [Line Items] | |
Total | 51 |
Credit Collateral | Non-investment grade | |
Derivative [Line Items] | |
Total | 7 |
Net Exposure | |
Derivative [Line Items] | |
Total | 1,551 |
Net Exposure | Investor-owned utilities, marketers, power producers | |
Derivative [Line Items] | |
Total | 1,271 |
Net Exposure | Energy cooperatives and municipalities | |
Derivative [Line Items] | |
Total | 132 |
Net Exposure | Financial Institutions | |
Derivative [Line Items] | |
Total | 49 |
Net Exposure | Other | |
Derivative [Line Items] | |
Total | 99 |
Net Exposure | Internally rated — investment grade | |
Derivative [Line Items] | |
Total | 116 |
Net Exposure | Internally rated — non-investment grade | |
Derivative [Line Items] | |
Total | 214 |
Net Exposure | Investment grade | |
Derivative [Line Items] | |
Total | 1,206 |
Net Exposure | Non-investment grade | |
Derivative [Line Items] | |
Total | $ 15 |
Number of Counterparties Greater than 10% of Net Exposure | |
Derivative [Line Items] | |
Number of counterparties | counterparty | 1,000,000 |
Number of Counterparties Greater than 10% of Net Exposure | Internally rated — investment grade | |
Derivative [Line Items] | |
Number of counterparties | counterparty | 0 |
Number of Counterparties Greater than 10% of Net Exposure | Internally rated — non-investment grade | |
Derivative [Line Items] | |
Number of counterparties | counterparty | 0 |
Number of Counterparties Greater than 10% of Net Exposure | Investment grade | |
Derivative [Line Items] | |
Number of counterparties | counterparty | 1,000,000 |
Number of Counterparties Greater than 10% of Net Exposure | Non-investment grade | |
Derivative [Line Items] | |
Number of counterparties | counterparty | 0 |
Net Exposure of Counterparties Greater than 10% of Net Exposure | |
Derivative [Line Items] | |
Total | $ 222 |
Net Exposure of Counterparties Greater than 10% of Net Exposure | Internally rated — investment grade | |
Derivative [Line Items] | |
Total | 0 |
Net Exposure of Counterparties Greater than 10% of Net Exposure | Internally rated — non-investment grade | |
Derivative [Line Items] | |
Total | 0 |
Net Exposure of Counterparties Greater than 10% of Net Exposure | Investment grade | |
Derivative [Line Items] | |
Total | 222 |
Net Exposure of Counterparties Greater than 10% of Net Exposure | Non-investment grade | |
Derivative [Line Items] | |
Total | $ 0 |
Derivative Financial Instrume_7
Derivative Financial Instruments - Summary of Credit Risk Related Contingent Features (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Gross fair value of derivative contracts containing this feature | $ (1,894) | $ (4,736) |
Offsetting fair value of in-the-money contracts under master netting arrangements | 925 | 2,048 |
Net fair value of derivative contracts containing this feature | $ (969) | $ (2,688) |
Derivative Financial Instrume_8
Derivative Financial Instruments - Summary of Cash Collateral and Letters of Credit (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Cash collateral posted | $ 2,449 | $ 1,636 |
Letters of credit posted | 777 | 947 |
Cash collateral held | 64 | 765 |
Letters of credit held | 61 | 115 |
Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1) | $ 1,914 | $ 3,337 |
Debt and Credit Agreements - Na
Debt and Credit Agreements - Narrative (Details) $ in Millions | 1 Months Ended | 6 Months Ended | 7 Months Ended | 12 Months Ended | 30 Months Ended | ||||||||||||||||||
Feb. 12, 2024 USD ($) | Feb. 09, 2023 USD ($) | Jan. 26, 2023 USD ($) | Mar. 29, 2022 USD ($) | Feb. 09, 2022 USD ($) | Feb. 01, 2022 USD ($) | May 13, 2021 USD ($) | May 31, 2023 | Nov. 30, 2017 USD ($) | Dec. 31, 2023 USD ($) | Jun. 30, 2023 | Dec. 31, 2023 USD ($) | Dec. 31, 2023 USD ($) MW | May 31, 2023 | Apr. 30, 2023 | Dec. 31, 2022 USD ($) | Jan. 31, 2022 USD ($) | Dec. 31, 2020 USD ($) | Mar. 31, 2020 USD ($) | Mar. 31, 2016 USD ($) | Dec. 31, 2015 | Sep. 30, 2013 USD ($) | Dec. 31, 2011 USD ($) | |
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Credit facility | $ 6,108 | $ 6,108 | $ 6,108 | $ 5,802 | $ 4,500 | ||||||||||||||||||
Short-term borrowings | 1,644 | 1,644 | 1,644 | 1,159 | $ 200 | ||||||||||||||||||
Loan | 0 | 0 | 0 | 0 | |||||||||||||||||||
Loan balance | 7,677 | 7,677 | 7,677 | ||||||||||||||||||||
Letters of credit outstanding | 1,775 | 1,775 | 1,775 | 2,475 | |||||||||||||||||||
Total long-term debt | 7,677 | 7,677 | 7,677 | 4,650 | |||||||||||||||||||
Nonrecourse | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Nonrecourse debt | 2,000 | 2,000 | 2,000 | 2,000 | |||||||||||||||||||
Syndicated Revolver | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Credit facility | $ 3,500 | 3,500 | 3,500 | 3,500 | 3,500 | ||||||||||||||||||
Debt instrument term | 5 years | ||||||||||||||||||||||
Loan | 0 | 0 | 0 | 0 | |||||||||||||||||||
Letters of credit outstanding | 60 | 60 | 60 | 765 | |||||||||||||||||||
Liquidity Facility | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Credit facility | $ 1,000 | 971 | 971 | 971 | 971 | ||||||||||||||||||
Debt instrument term | 5 years | ||||||||||||||||||||||
Loan | 0 | 0 | 0 | 0 | |||||||||||||||||||
Letters of credit outstanding | 720 | 720 | $ 720 | 732 | |||||||||||||||||||
Daily Simple SOFR Rate | Maximum | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Basis spread | 0.275% | ||||||||||||||||||||||
Daily Simple SOFR Rate | Non-investment grade | Maximum | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Basis spread | 1% | ||||||||||||||||||||||
Term SOFR Rate | Maximum | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Basis spread | 1.275% | ||||||||||||||||||||||
Term SOFR Rate | Non-investment grade | Maximum | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Basis spread | 2% | ||||||||||||||||||||||
Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Syndicated Revolver | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Line of credit facility, interest rate at period end | 1.275% | ||||||||||||||||||||||
Short Term Loan Agreements | Unsecured notes | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Short-term borrowings | $ 400 | $ 100 | $ 200 | $ 300 | |||||||||||||||||||
Repayments of short-term debt | $ 100 | ||||||||||||||||||||||
Short Term Loan Agreements | Unsecured notes | Subsequent Event | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Short-term borrowings | $ 200 | ||||||||||||||||||||||
Short Term Loan Agreements | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Unsecured notes | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Basis spread | 1.05% | 0.80% | 0.80% | ||||||||||||||||||||
Short Term Loan Agreements | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Unsecured notes | Subsequent Event | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Basis spread | 0.90% | ||||||||||||||||||||||
Continetal Wind | Nonrecourse | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Credit facility | 128 | 128 | $ 128 | ||||||||||||||||||||
Loan balance | 315 | 315 | 315 | 345 | |||||||||||||||||||
Letters of credit outstanding | $ 116 | $ 116 | $ 116 | 111 | |||||||||||||||||||
Notes | $ 613 | ||||||||||||||||||||||
Total net capacity (in megawatts) | MW | 667 | ||||||||||||||||||||||
Rates | 6% | 6% | 6% | ||||||||||||||||||||
Revolver facility | $ 4 | $ 4 | $ 4 | ||||||||||||||||||||
Renewable Power Generation | Nonrecourse | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Loan balance | 70 | 70 | 70 | 80 | |||||||||||||||||||
Notes | $ 150 | ||||||||||||||||||||||
Rates | 4.11% | ||||||||||||||||||||||
Renewables 2017 | Nonrecourse | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Loan balance | $ 850 | 709 | 709 | 709 | |||||||||||||||||||
Notational amount, debt | $ 636 | ||||||||||||||||||||||
Interest rate, debt hedge | 2.32% | ||||||||||||||||||||||
Total long-term debt | $ 850 | 850 | 850 | ||||||||||||||||||||
Renewables 2020 | Nonrecourse | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Loan balance | $ 750 | ||||||||||||||||||||||
Notational amount, debt | 516 | ||||||||||||||||||||||
Interest rate, debt hedge | 0.8295% | 1.05% | |||||||||||||||||||||
Total long-term debt | $ 650 | $ 650 | $ 650 | 690 | |||||||||||||||||||
Renewables 2020 | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Nonrecourse | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Basis spread | 2.76% | ||||||||||||||||||||||
Floor rate | 1% | 1% | 1% | ||||||||||||||||||||
Renewables 2020 | LIBOR | Nonrecourse | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Basis spread | 2.50% | ||||||||||||||||||||||
West Medway II, LLC | Nonrecourse | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Credit facility | $ 150 | ||||||||||||||||||||||
Rates | 2.875% | ||||||||||||||||||||||
Notational amount, debt | $ 113 | ||||||||||||||||||||||
Interest rate, debt hedge | 0.61% | 0.5365% | |||||||||||||||||||||
Total long-term debt | $ 85 | $ 85 | $ 85 | 115 | |||||||||||||||||||
West Medway II, LLC | Nonrecourse | Maximum | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Rates | 3.225% | 3.225% | |||||||||||||||||||||
West Medway II, LLC | Nonrecourse | Minimum | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Rates | 2.975% | 2.975% | |||||||||||||||||||||
Antelope Valley Solar Ranch One | Nonrecourse | |||||||||||||||||||||||
Schedule of line of credit, short term, and long term debt [Line Items] | |||||||||||||||||||||||
Basis spread | 0.375% | ||||||||||||||||||||||
Loan | $ 646 | ||||||||||||||||||||||
Average blended interest rate | 2.82% | ||||||||||||||||||||||
Loan balance | 390 | 390 | $ 390 | 415 | |||||||||||||||||||
Letters of credit outstanding | $ 36 | $ 36 | $ 36 | $ 37 |
Debt and Credit Agreements - Su
Debt and Credit Agreements - Summary of Bank Commitments, Credit Facility Borrowings and Available Capacity (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Feb. 09, 2022 | Feb. 01, 2022 | Jan. 31, 2022 |
Short-term Debt [Line Items] | |||||
Aggregate Bank Commitment | $ 6,108 | $ 5,802 | $ 4,500 | ||
Facility Draws | 0 | 0 | |||
Outstanding Letters of Credit | 1,775 | 2,475 | |||
Outstanidng Commercial Paper | 1,107 | 959 | |||
Available Capacity | 3,166 | 2,268 | |||
Commercial Paper | |||||
Short-term Debt [Line Items] | |||||
Aggregate Bank Commitment | $ 3,500 | $ 3,500 | |||
Weighted Average Interest Rate on Commercial Paper Borrowings | 5.66% | 4.90% | |||
Syndicated Revolver | |||||
Short-term Debt [Line Items] | |||||
Aggregate Bank Commitment | $ 3,500 | $ 3,500 | $ 3,500 | ||
Facility Draws | 0 | 0 | |||
Outstanding Letters of Credit | 60 | 765 | |||
Outstanidng Commercial Paper | 1,107 | 959 | |||
Available Capacity | 2,333 | 1,776 | |||
Bilaterals | |||||
Short-term Debt [Line Items] | |||||
Aggregate Bank Commitment | 1,500 | 1,200 | |||
Facility Draws | 0 | 0 | |||
Outstanding Letters of Credit | 878 | 867 | |||
Outstanidng Commercial Paper | 0 | 0 | |||
Available Capacity | 622 | 333 | |||
Liquidity Facility | |||||
Short-term Debt [Line Items] | |||||
Aggregate Bank Commitment | 971 | 971 | $ 1,000 | ||
Facility Draws | 0 | 0 | |||
Outstanding Letters of Credit | 720 | 732 | |||
Outstanidng Commercial Paper | 0 | 0 | |||
Available Capacity | 191 | 139 | |||
Liquidity Facility | No Additional Collateral Posted | |||||
Short-term Debt [Line Items] | |||||
Outstanidng Commercial Paper | 911 | 871 | |||
Project Finance | |||||
Short-term Debt [Line Items] | |||||
Aggregate Bank Commitment | 137 | 131 | |||
Facility Draws | 0 | 0 | |||
Outstanding Letters of Credit | 117 | 111 | |||
Outstanidng Commercial Paper | 0 | 0 | |||
Available Capacity | $ 20 | $ 20 |
Debt and Credit Agreements - _2
Debt and Credit Agreements - Summary of Credit Facility Thresholds (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Jan. 31, 2022 |
Line of Credit Facility [Line Items] | |||
Credit facility | $ 6,108 | $ 5,802 | $ 4,500 |
Bilaterals | |||
Line of Credit Facility [Line Items] | |||
Credit facility | 1,500 | $ 1,200 | |
Bilaterals | January 5, 2016 | |||
Line of Credit Facility [Line Items] | |||
Credit facility | 150 | ||
Bilaterals | October 25, 2019 | |||
Line of Credit Facility [Line Items] | |||
Credit facility | 200 | ||
Bilaterals | November 20, 2019 | |||
Line of Credit Facility [Line Items] | |||
Credit facility | 300 | ||
Bilaterals | November 21, 2019 | |||
Line of Credit Facility [Line Items] | |||
Credit facility | 100 | ||
Bilaterals | November 21, 2019(November 21, 2022) | |||
Line of Credit Facility [Line Items] | |||
Credit facility | 100 | ||
Bilaterals | May 15, 2020 | |||
Line of Credit Facility [Line Items] | |||
Credit facility | 300 | ||
Bilaterals | August 12, 2022 | |||
Line of Credit Facility [Line Items] | |||
Credit facility | 50 | ||
Bilaterals | March 29, 2023 | |||
Line of Credit Facility [Line Items] | |||
Credit facility | 100 | ||
Bilaterals | December 8, 2023 | |||
Line of Credit Facility [Line Items] | |||
Credit facility | $ 200 |
Debt and Credit Agreements - _3
Debt and Credit Agreements - Summary of Outstanding Long-term Debt (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Debt Instrument [Line Items] | ||
Total long-term debt | $ 7,677 | $ 4,650 |
Unamortized debt discount and premium, net | (4) | (5) |
Unamortized debt issuance costs | (56) | (36) |
Long-term debt due within one year | (121) | (143) |
Long-term debt | 7,496 | 4,466 |
Senior unsecured notes | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 5,688 | 2,938 |
Senior unsecured notes | Minimum | ||
Debt Instrument [Line Items] | ||
Rates | 3.25% | |
Senior unsecured notes | Maximum | ||
Debt Instrument [Line Items] | ||
Rates | 6.50% | |
Tax-exempt notes | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 435 | |
Tax-exempt notes | Minimum | ||
Debt Instrument [Line Items] | ||
Rates | 4.10% | |
Tax-exempt notes | Maximum | ||
Debt Instrument [Line Items] | ||
Rates | 4.45% | |
Notes payable and other | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 34 | 68 |
Notes payable and other | Minimum | ||
Debt Instrument [Line Items] | ||
Rates | 2.10% | |
Notes payable and other | Maximum | ||
Debt Instrument [Line Items] | ||
Rates | 5.85% | |
Fixed rates | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 780 | 839 |
Fixed rates | Minimum | ||
Debt Instrument [Line Items] | ||
Rates | 2.29% | |
Fixed rates | Maximum | ||
Debt Instrument [Line Items] | ||
Rates | 6% | |
Variable rates | ||
Debt Instrument [Line Items] | ||
Total long-term debt | $ 740 | $ 805 |
Variable rates | Minimum | ||
Debt Instrument [Line Items] | ||
Rates | 7.24% | |
Variable rates | Maximum | ||
Debt Instrument [Line Items] | ||
Rates | 8.57% |
Debt and Credit Agreements - Sc
Debt and Credit Agreements - Schedule of Long-term Debt Maturities (Details) $ in Millions | Dec. 31, 2023 USD ($) |
Debt Disclosure [Abstract] | |
2024 | $ 121 |
2025 | 1,010 |
2026 | 121 |
2027 | 705 |
2028 | 1,160 |
Thereafter | 4,560 |
Total | $ 7,677 |
Fair Value of Financial Asset_3
Fair Value of Financial Assets and Liabilities - Fair Value of Financial Liabilities Recorded at Amortized Cost (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
SNF Obligation | $ 1,296 | $ 1,230 |
Carrying Amount | ||
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-Term Debt, including amounts due within one year | 7,617 | 4,609 |
SNF Obligation | 1,296 | 1,230 |
Fair Value | ||
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-Term Debt, including amounts due within one year | 7,914 | 4,547 |
SNF Obligation | 1,222 | 1,021 |
Fair Value | Level 2 | ||
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-Term Debt, including amounts due within one year | 7,140 | 3,688 |
SNF Obligation | 1,222 | 1,021 |
Fair Value | Level 3 | ||
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-Term Debt, including amounts due within one year | 774 | 859 |
SNF Obligation | $ 0 | $ 0 |
Fair Value of Financial Asset_4
Fair Value of Financial Assets and Liabilities - Fair Value Measurement of Assets and Liabilities, Recurring (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Notational amount | $ 15 | $ 41 |
Asset, notational amount | 884 | 494 |
Liability, notational amount | 884 | 494 |
Variation margin | 1,712 | 836 |
Cash and Cash Equivalents | Constellation Energy Generation, LLC | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Cash equivalents | 349 | 390 |
Restricted cash | Constellation Energy Generation, LLC | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Cash equivalents | 49 | 70 |
Exelon Corporate | Cash and Cash Equivalents | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Cash equivalents | 54 | |
Exelon Corporate | Cash | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Cash equivalents | 2 | 19 |
Nuclear Decommissioning Trust Fund Investments | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Net liabilities | 115 | 168 |
Notational amount | 64 | 59 |
Fair Value, Recurring | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Cash equivalents | 42 | 41 |
DPP consideration | 1,216 | 515 |
Total assets | 20,284 | 18,386 |
Deferred compensation obligation | (69) | (57) |
Total liabilities | (1,120) | (2,598) |
Total net assets | 19,164 | 15,788 |
Fair Value, Recurring | Commodity derivative liabilities subtotal | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative liabilities | (1,051) | (2,541) |
Fair Value, Recurring | Economic hedges | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative liabilities | (12,571) | (20,257) |
Fair Value, Recurring | Proprietary trading | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative liabilities | (2) | (6) |
Fair Value, Recurring | Effect of netting and allocation of collateral | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative liabilities | 11,522 | 17,722 |
Fair Value, Recurring | Nuclear Decommissioning Trust Fund Investments | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 16,398 | 14,127 |
Fair Value, Recurring | Cash equivalents | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 443 | 269 |
Fair Value, Recurring | Equities | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 6,565 | 4,960 |
Fair Value, Recurring | Fixed income | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 3,843 | 3,325 |
Fair Value, Recurring | Private credit | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 151 | 159 |
Fair Value, Recurring | Rabbi trust investments subtotal | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 82 | 68 |
Fair Value, Recurring | Investments in equities | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 372 | 6 |
Unrealized gain | 313 | |
Fair Value, Recurring | Commodity derivative assets subtotal | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative assets | 2,174 | 3,629 |
Fair Value, Recurring | Economic hedges | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative assets | 11,294 | 20,443 |
Fair Value, Recurring | Proprietary trading | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative assets | 2 | 10 |
Fair Value, Recurring | Effect of netting and allocation of collateral | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative assets | (9,122) | (16,824) |
Total assets measured at fair value | Fair Value, Recurring | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Total assets | 20,284 | 18,386 |
Level 1 | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Collateral posted (received) from counterparties | 591 | 328 |
Level 1 | Fair Value, Recurring | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Cash equivalents | 42 | 41 |
DPP consideration | 0 | 0 |
Total assets | 7,769 | 6,301 |
Deferred compensation obligation | 0 | 0 |
Total liabilities | (94) | 108 |
Total net assets | 7,675 | 6,409 |
Level 1 | Fair Value, Recurring | Commodity derivative liabilities subtotal | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative liabilities | (94) | 108 |
Level 1 | Fair Value, Recurring | Economic hedges | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative liabilities | (2,681) | (3,171) |
Level 1 | Fair Value, Recurring | Proprietary trading | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative liabilities | 0 | 0 |
Level 1 | Fair Value, Recurring | Effect of netting and allocation of collateral | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative liabilities | 2,587 | 3,279 |
Level 1 | Fair Value, Recurring | Nuclear Decommissioning Trust Fund Investments | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 6,973 | 5,660 |
Level 1 | Fair Value, Recurring | Cash equivalents | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 356 | 181 |
Level 1 | Fair Value, Recurring | Equities | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 4,574 | 3,462 |
Level 1 | Fair Value, Recurring | Fixed income | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 2,043 | 2,017 |
Level 1 | Fair Value, Recurring | Private credit | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 0 | 0 |
Level 1 | Fair Value, Recurring | Rabbi trust investments subtotal | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 48 | 40 |
Level 1 | Fair Value, Recurring | Investments in equities | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 372 | 6 |
Level 1 | Fair Value, Recurring | Commodity derivative assets subtotal | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative assets | 334 | 554 |
Level 1 | Fair Value, Recurring | Economic hedges | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative assets | 2,330 | 3,505 |
Level 1 | Fair Value, Recurring | Proprietary trading | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative assets | 0 | 0 |
Level 1 | Fair Value, Recurring | Effect of netting and allocation of collateral | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative assets | (1,996) | (2,951) |
Level 2 | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Collateral posted (received) from counterparties | 1,347 | 352 |
Level 2 | Fair Value, Recurring | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Cash equivalents | 0 | 0 |
DPP consideration | 1,216 | 515 |
Total assets | 5,475 | 4,181 |
Deferred compensation obligation | (69) | (57) |
Total liabilities | (681) | (859) |
Total net assets | 4,794 | 3,322 |
Level 2 | Fair Value, Recurring | Commodity derivative liabilities subtotal | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative liabilities | (612) | (802) |
Level 2 | Fair Value, Recurring | Economic hedges | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative liabilities | (7,154) | (11,498) |
Level 2 | Fair Value, Recurring | Proprietary trading | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative liabilities | 0 | (4) |
Level 2 | Fair Value, Recurring | Effect of netting and allocation of collateral | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative liabilities | 6,542 | 10,700 |
Level 2 | Fair Value, Recurring | Nuclear Decommissioning Trust Fund Investments | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 3,600 | 2,630 |
Level 2 | Fair Value, Recurring | Cash equivalents | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 87 | 88 |
Level 2 | Fair Value, Recurring | Equities | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 1,990 | 1,498 |
Level 2 | Fair Value, Recurring | Fixed income | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 1,523 | 1,044 |
Level 2 | Fair Value, Recurring | Private credit | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 0 | 0 |
Level 2 | Fair Value, Recurring | Rabbi trust investments subtotal | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 33 | 27 |
Level 2 | Fair Value, Recurring | Investments in equities | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 0 | 0 |
Level 2 | Fair Value, Recurring | Commodity derivative assets subtotal | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative assets | 626 | 1,009 |
Level 2 | Fair Value, Recurring | Economic hedges | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative assets | 5,821 | 11,353 |
Level 2 | Fair Value, Recurring | Proprietary trading | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative assets | 0 | 4 |
Level 2 | Fair Value, Recurring | Effect of netting and allocation of collateral | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative assets | (5,195) | (10,348) |
Level 3 | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Collateral posted (received) from counterparties | 462 | 218 |
Level 3 | Fair Value, Recurring | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Cash equivalents | 0 | 0 |
DPP consideration | 0 | 0 |
Total assets | 1,644 | 2,490 |
Deferred compensation obligation | 0 | 0 |
Total liabilities | (345) | (1,847) |
Total net assets | 1,299 | 643 |
Level 3 | Fair Value, Recurring | Commodity derivative liabilities subtotal | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative liabilities | (345) | (1,847) |
Level 3 | Fair Value, Recurring | Economic hedges | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative liabilities | (2,736) | (5,588) |
Level 3 | Fair Value, Recurring | Proprietary trading | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative liabilities | (2) | (2) |
Level 3 | Fair Value, Recurring | Effect of netting and allocation of collateral | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative liabilities | 2,393 | 3,743 |
Level 3 | Fair Value, Recurring | Nuclear Decommissioning Trust Fund Investments | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 429 | 423 |
Level 3 | Fair Value, Recurring | Cash equivalents | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 0 | 0 |
Level 3 | Fair Value, Recurring | Equities | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 1 | 0 |
Level 3 | Fair Value, Recurring | Fixed income | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 277 | 264 |
Level 3 | Fair Value, Recurring | Private credit | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 151 | 159 |
Level 3 | Fair Value, Recurring | Rabbi trust investments subtotal | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 1 | 1 |
Level 3 | Fair Value, Recurring | Investments in equities | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
NDT fund investments | 0 | 0 |
Level 3 | Fair Value, Recurring | Commodity derivative assets subtotal | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative assets | 1,214 | 2,066 |
Level 3 | Fair Value, Recurring | Economic hedges | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative assets | 3,143 | 5,585 |
Level 3 | Fair Value, Recurring | Proprietary trading | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative assets | 2 | 6 |
Level 3 | Fair Value, Recurring | Effect of netting and allocation of collateral | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Commodity derivative assets | (1,931) | (3,525) |
Assets measured at NAV | Fair Value, Recurring | ||
Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions [Line Items] | ||
Total assets | $ 5,396 | $ 5,414 |
Fair Value of Financial Asset_5
Fair Value of Financial Assets and Liabilities - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Equity investments without readily determinable fair values | $ 103 | $ 46 |
Forward power basis (in dollars per share) | $ 47.76 | |
Forward gas basis (in dollars per share) | $ 3.09 | |
Private credit | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Outstanding commitments | $ 344 | |
Private equity | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Outstanding commitments | 88 | |
Real estate | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Outstanding commitments | $ 373 |
Fair Value of Financial Asset_6
Fair Value of Financial Assets and Liabilities - Fair Value Reconciliation of Level 3 Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract] | ||
Beginning Balance | $ 188 | $ 0 |
Total realized / unrealized gains (losses) | ||
Included in net income (loss) | (12) | 55 |
Purchases, sales, issuances and settlements | ||
Purchases | 8 | 18 |
Settlements | 187 | 4 |
Transfers into Level 3 | 8 | 220 |
Ending Balance | 0 | 188 |
Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract] | ||
Beginning Balance | 643 | 370 |
Total realized / unrealized gains (losses) | ||
Included in net income (loss) | 173 | (757) |
Included in Payables related to Regulatory Agreement Units | 10 | (10) |
Change in collateral | 243 | 253 |
Impacts of separation | 3 | |
Purchases, sales, issuances and settlements | ||
Purchases | 160 | 599 |
Sales | (28) | (50) |
Settlements | 25 | (137) |
Transfers into Level 3 | 46 | 383 |
Transfers out of Level 3 | 27 | (11) |
Ending Balance | 1,299 | 643 |
The amount of total gains (losses) included in income attributed to the change in unrealized losses related to assets and liabilities | 1,196 | (1,269) |
NDT Fund Investments | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract] | ||
Beginning Balance | 423 | 464 |
Total realized / unrealized gains (losses) | ||
Included in net income (loss) | 2 | (2) |
Included in Payables related to Regulatory Agreement Units | 10 | (10) |
Change in collateral | 0 | 0 |
Impacts of separation | 0 | |
Purchases, sales, issuances and settlements | ||
Purchases | 0 | 5 |
Sales | 1 | 0 |
Settlements | (7) | (35) |
Transfers into Level 3 | 0 | 2 |
Transfers out of Level 3 | 0 | (1) |
Ending Balance | 429 | 423 |
The amount of total gains (losses) included in income attributed to the change in unrealized losses related to assets and liabilities | 2 | (2) |
Mark-to-Market Derivatives | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract] | ||
Beginning Balance | 219 | (94) |
Total realized / unrealized gains (losses) | ||
Included in net income (loss) | 171 | (753) |
Included in Payables related to Regulatory Agreement Units | 0 | 0 |
Change in collateral | 243 | 253 |
Impacts of separation | 0 | |
Purchases, sales, issuances and settlements | ||
Purchases | 160 | 594 |
Sales | (29) | (50) |
Settlements | 32 | (102) |
Transfers into Level 3 | 46 | 381 |
Transfers out of Level 3 | 27 | (10) |
Ending Balance | 869 | 219 |
The amount of total gains (losses) included in income attributed to the change in unrealized losses related to assets and liabilities | 1,194 | (1,265) |
Realized gains (losses) | (991) | 410 |
Life Insurance Contracts | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract] | ||
Beginning Balance | 1 | 0 |
Total realized / unrealized gains (losses) | ||
Included in net income (loss) | 0 | (2) |
Included in Payables related to Regulatory Agreement Units | 0 | 0 |
Change in collateral | 0 | 0 |
Impacts of separation | 3 | |
Purchases, sales, issuances and settlements | ||
Purchases | 0 | 0 |
Sales | 0 | 0 |
Settlements | 0 | 0 |
Transfers into Level 3 | 0 | 0 |
Transfers out of Level 3 | 0 | 0 |
Ending Balance | 1 | 1 |
The amount of total gains (losses) included in income attributed to the change in unrealized losses related to assets and liabilities | $ 0 | $ (2) |
Fair Value of Financial Asset_7
Fair Value of Financial Assets and Liabilities - Fair Value Assets and Liabilities Measure on a Recurring Basis Gain Loss Included in Earnings (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Fair Value Assets and Liabilities Measured on a Recurring Basis Gain Loss Included in Earnings [Line Items] | |||
Total gains (losses) included in net income | $ 12 | $ (55) | |
Operating Revenues | |||
Fair Value Assets and Liabilities Measured on a Recurring Basis Gain Loss Included in Earnings [Line Items] | |||
Total gains (losses) included in net income | 706 | (860) | $ (1,343) |
Total unrealized gains (losses) | $ 1,673 | $ (1,330) | $ (1,577) |
Fair Value, Asset, Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Operating revenues | Operating revenues | Operating revenues |
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Operating revenues | Operating revenues | Operating revenues |
Purchased power and fuel | |||
Fair Value Assets and Liabilities Measured on a Recurring Basis Gain Loss Included in Earnings [Line Items] | |||
Total gains (losses) included in net income | $ (503) | $ 5 | $ 531 |
Total unrealized gains (losses) | $ (479) | $ 65 | $ 355 |
Fair Value, Asset, Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Purchased power and fuel | Purchased power and fuel | Purchased power and fuel |
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Purchased power and fuel | Purchased power and fuel | Purchased power and fuel |
Other, net | |||
Fair Value Assets and Liabilities Measured on a Recurring Basis Gain Loss Included in Earnings [Line Items] | |||
Total gains (losses) included in net income | $ 2 | $ (4) | $ 5 |
Total unrealized gains (losses) | $ 2 | $ (2) | $ 5 |
Fair Value, Asset, Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Other, net | Other, net | Other, net |
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Other, net | Other, net | Other, net |
Fair Value of Financial Asset_8
Fair Value of Financial Assets and Liabilities - Fair Value Inputs Assets Quantitative Information (Details) - Level 3 $ in Millions | Dec. 31, 2023 USD ($) | Dec. 31, 2022 USD ($) |
Fair Value Measurement Inputs and Valuation Techniques [Abstract] | ||
Cash collateral posted (received) | $ 462 | $ 218 |
Economic Hedges | ||
Fair Value Measurement Inputs and Valuation Techniques [Abstract] | ||
Mark-to-market derivatives—Economic hedges | $ 407 | $ (3) |
Economic Hedges | Minimum | Discounted Cash Flow | ||
Fair Value Measurement Inputs and Valuation Techniques [Abstract] | ||
Forward power price | 9.64 | 0.63 |
Forward gas price | 1.20 | 1.67 |
Economic Hedges | Minimum | Option Model | ||
Fair Value Measurement Inputs and Valuation Techniques [Abstract] | ||
Volatility percentage | 0.23 | 0.97 |
Economic Hedges | Maximum | Discounted Cash Flow | ||
Fair Value Measurement Inputs and Valuation Techniques [Abstract] | ||
Forward power price | 216 | 283 |
Forward gas price | 14 | 26 |
Economic Hedges | Maximum | Option Model | ||
Fair Value Measurement Inputs and Valuation Techniques [Abstract] | ||
Volatility percentage | 2 | 1.19 |
Economic Hedges | Arithmetic Average | Discounted Cash Flow | ||
Fair Value Measurement Inputs and Valuation Techniques [Abstract] | ||
Forward power price | 48 | 72 |
Forward gas price | 3.09 | 4.57 |
Economic Hedges | Arithmetic Average | Option Model | ||
Fair Value Measurement Inputs and Valuation Techniques [Abstract] | ||
Volatility percentage | 0.87 | 1.11 |
Commitments and Contingencies -
Commitments and Contingencies - Schedule of Commercial Commitments (Details) $ in Millions | Dec. 31, 2023 USD ($) |
Guarantor Obligations [Line Items] | |
Total | $ 2,599 |
2024 | 2,455 |
2025 | 27 |
2026 | 1 |
2027 | 0 |
2028 | 116 |
2029 and beyond | 0 |
Letters of credit | |
Guarantor Obligations [Line Items] | |
Total | 1,775 |
2024 | 1,631 |
2025 | 27 |
2026 | 1 |
2027 | 0 |
2028 | 116 |
2029 and beyond | 0 |
Surety bonds | |
Guarantor Obligations [Line Items] | |
Total | 824 |
2024 | 824 |
2025 | 0 |
2026 | 0 |
2027 | 0 |
2028 | 0 |
2029 and beyond | $ 0 |
Commitments and Contingencies_2
Commitments and Contingencies - Narrative (Details) $ in Millions | 12 Months Ended | |||||||
Dec. 31, 2023 USD ($) counterparty Open_claim | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Apr. 30, 2023 USD ($) | Aug. 03, 2020 USD ($) | Mar. 31, 2019 USD ($) | Sep. 30, 2018 USD ($) | Jan. 01, 2017 USD ($) | |
Commitments and Contingencies [Line Items] | ||||||||
Nuclear financial protection pool value | $ 500 | |||||||
Maximum recovery limit from a nuclear industry mutual insurance company in the event of multiple losses | 15,800 | |||||||
Maximum annual assessment payment mandated by Price-Anderson Act for a nuclear incident | 3,500 | |||||||
Maximum aggregate annual retrospective premium obligation | $ 254 | |||||||
Maximum recovery, aggregate | 3,200 | |||||||
Total cumulative cash reimbursements | 1,855 | |||||||
Net cumulative cash reimbursements | 1,615 | |||||||
Accrued undiscounted amounts, environmental liabilities | 149 | $ 119 | ||||||
Asbestos-related bodily injury claims | $ 131 | 95 | ||||||
Defaulting Market Participant and Settlement of Regulatory Matters | ||||||||
Commitments and Contingencies [Line Items] | ||||||||
Reduction to net income | 50 | $ 800 | ||||||
Former ComEd units | ||||||||
Commitments and Contingencies [Line Items] | ||||||||
Treasury interest rate | 5.488% | |||||||
Fitzpatrick | ||||||||
Commitments and Contingencies [Line Items] | ||||||||
Treasury interest rate | 5.509% | |||||||
West Lake | ||||||||
Commitments and Contingencies [Line Items] | ||||||||
Accrued undiscounted amounts, environmental liabilities | $ 305 | $ 50 | ||||||
Number of potentially responsible parties | counterparty | 3 | |||||||
Environmental loss contingencies | $ 90 | $ 90 | ||||||
Open Claims | ||||||||
Commitments and Contingencies [Line Items] | ||||||||
Asbestos-related bodily injury claims | $ 20 | |||||||
Open claims | Open_claim | 235 | |||||||
Estimated Future Claims | ||||||||
Commitments and Contingencies [Line Items] | ||||||||
Asbestos-related bodily injury claims | $ 111 | |||||||
Nuclear Insurance Premiums | ||||||||
Commitments and Contingencies [Line Items] | ||||||||
Nuclear insurance liability limit per incident | 16,200 | |||||||
Minimum coverage limit | 1,060 | |||||||
Nuclear Insurance Premiums | Maximum | ||||||||
Commitments and Contingencies [Line Items] | ||||||||
Nuclear financial protection pool value | $ 520 | |||||||
Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums | ||||||||
Commitments and Contingencies [Line Items] | ||||||||
Annual distribution, portion | $ 59 | $ 30 | $ 114 |
Commitments and Contingencies_3
Commitments and Contingencies - Settlement Agreements (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Commitments and Contingencies Disclosure [Abstract] | ||
DOE receivable - current | $ 229 | $ 125 |
DOE receivable - noncurrent | 40 | 130 |
Amounts owed to co-owners | $ (23) | $ (12) |
Commitments and Contingencies_4
Commitments and Contingencies - Schedule of Spent Nuclear Fuel Obligation (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Spent Nuclear Fuel Obligation [Line Items] | ||
Spent nuclear fuel obligation | $ 1,296 | $ 1,230 |
Former ComEd units | ||
Spent Nuclear Fuel Obligation [Line Items] | ||
Spent nuclear fuel obligation | 1,158 | 1,100 |
One time fee | 277 | |
Fitzpatrick | ||
Spent Nuclear Fuel Obligation [Line Items] | ||
Spent nuclear fuel obligation | 138 | $ 130 |
One time fee | $ 34 |
Shareholders' Equity - Narrativ
Shareholders' Equity - Narrative (Details) - USD ($) shares in Millions, $ in Millions | 2 Months Ended | 12 Months Ended | ||
Feb. 27, 2024 | Dec. 31, 2023 | Dec. 12, 2023 | Feb. 16, 2023 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Value of stock authorized for repurchase | $ 1,000 | |||
Common stock repurchased (in shares) | 10.6 | |||
Common stock repurchased | $ 1,000 | |||
Value of additional stock authorized for repurchase | $ 1,000 | |||
Remaining repurchase amount | $ 1,000 | |||
Subsequent Event | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Common stock repurchased (in shares) | 1.2 | |||
Common stock repurchased | $ 150 |
Shareholders' Equity - Schedule
Shareholders' Equity - Schedule of Changes in AOCI (Details) - USD ($) $ in Millions | 1 Months Ended | 11 Months Ended | 12 Months Ended | ||
Jan. 31, 2022 | Dec. 31, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||
Beginning Balance | $ 11,614 | $ 0 | $ 11,372 | $ 11,614 | $ 14,676 |
Net current-period OCI | 277 | (431) | 277 | (1) | |
Separation-related adjustments | (197) | ||||
Ending Balance | 0 | 11,372 | 11,286 | 11,372 | 11,614 |
Total | |||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||
Beginning Balance | (31) | (1,760) | (31) | (30) | |
OCI before reclassifications | (453) | 182 | (1) | ||
Net current-period OCI | (431) | (1,729) | (1) | ||
Separation-related adjustments | (2,006) | ||||
Amounts reclassified from AOCI | 22 | 95 | |||
Ending Balance | (1,760) | (2,191) | (1,760) | (31) | |
Losses on Cash Flow Hedges | |||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||
Beginning Balance | (8) | (9) | (8) | (7) | |
OCI before reclassifications | (2) | (1) | (1) | ||
Net current-period OCI | (1) | (1) | (1) | ||
Separation-related adjustments | 0 | ||||
Amounts reclassified from AOCI | 1 | 0 | |||
Ending Balance | (9) | (10) | (9) | (8) | |
Pension and Non-Pension Postretirement Benefit Plan Items | |||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||
Beginning Balance | 0 | (1,725) | 0 | 0 | |
OCI before reclassifications | (453) | 186 | 0 | ||
Net current-period OCI | (432) | (1,725) | 0 | ||
Separation-related adjustments | (2,006) | ||||
Amounts reclassified from AOCI | 21 | 95 | |||
Ending Balance | (1,725) | (2,157) | (1,725) | 0 | |
Foreign Currency Items | |||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||
Beginning Balance | $ (23) | (26) | (23) | (23) | |
OCI before reclassifications | 2 | (3) | 0 | ||
Net current-period OCI | 2 | (3) | 0 | ||
Separation-related adjustments | 0 | ||||
Amounts reclassified from AOCI | 0 | 0 | |||
Ending Balance | $ (26) | $ (24) | $ (26) | $ (23) |
Shareholders' Equity - Income T
Shareholders' Equity - Income Taxes Allocated to Other Comprehensive Income (Loss) Components (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Actuarial loss reclassified to periodic benefit cost | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Pension and non-pension postretirement benefit plans | $ (10) | $ (33) | $ 0 |
Pension and non-pension postretirement benefit plans valuation adjustment | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Pension and non-pension postretirement benefit plans | $ 151 | 619 | $ 0 |
Income tax benefit related to separation adjustment | $ 680 |
Stock-Based Compensation Plan_2
Stock-Based Compensation Plans - Narrative (Details) - shares | 12 Months Ended | |
Dec. 31, 2023 | Feb. 01, 2022 | |
Long Term Incentive Plan | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Shares authorized | 20,000,000 | |
Performance Shares | Long Term Incentive Plan | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Percentage to be settled as common stock | 50% | |
Percentage to be settled as cash | 50% | |
Performance period | 3 years | |
Vesting period | 3 years | |
Restricted Stock Units (RSUs) | Minimum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Requisite service period | 3 years | |
Restricted Stock Units (RSUs) | Maximum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Requisite service period | 5 years |
Stock-Based Compensation Plan_3
Stock-Based Compensation Plans - Schedule of Stock-based Compensation Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Share-Based Payment Arrangement [Abstract] | |||
Total stock-based compensation expense included in operating and maintenance expense | $ 178 | $ 116 | $ 47 |
Income tax benefit | (45) | (29) | (12) |
Total after-tax stock-based compensation expense | $ 133 | $ 87 | $ 35 |
Stock-Based Compensation Plan_4
Stock-Based Compensation Plans - Compensation Costs Tax Benefits (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Tax benefit on stock compensation | $ 45 | $ 29 | $ 12 |
Stock-Based Compensation Plan_5
Stock-Based Compensation Plans - Unit Activity (Details) - $ / shares | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Performance Shares | ||
Shares | ||
Beginning Balance (in shares) | 849,342 | |
Granted (in shares) | 370,874 | |
Change in performance (in shares) | 471,561 | |
Forfeited (in shares) | (20,615) | |
Undistributed vested awards (in shares) | (834,837) | |
Ending Balance (in shares) | 836,325 | 849,342 |
Weighted Average Grant Date Fair Value (per share) | ||
Beginning balance (in dollars per share) | $ 47.40 | |
Granted (in dollars per share) | 83.26 | $ 48.33 |
Change in performance (in dollars per share) | 75.31 | |
Forfeited (in dollars per share) | 57.80 | |
Undistributed vested awards (in dollars per share) | 90.81 | |
Ending balance (in dollars per share) | $ 61.47 | $ 47.40 |
Restricted Stock Units (RSUs) | ||
Shares | ||
Beginning Balance (in shares) | 790,668 | |
Granted (in shares) | 620,002 | |
Vested (in shares) | (295,370) | |
Forfeited (in shares) | (27,922) | |
Undistributed vested awards (in shares) | (222,573) | |
Ending Balance (in shares) | 864,805 | 790,668 |
Weighted Average Grant Date Fair Value (per share) | ||
Beginning balance (in dollars per share) | $ 53.72 | |
Granted (in dollars per share) | 86.10 | $ 54.17 |
Vested (in dollars per share) | 53.46 | |
Forfeited (in dollars per share) | 69.14 | |
Undistributed vested awards (in dollars per share) | 80.52 | |
Ending balance (in dollars per share) | $ 69.42 | $ 53.72 |
Stock-Based Compensation Plan_6
Stock-Based Compensation Plans - Unit Fair Value (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Performance Shares | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Weighted average grant date fair value (in dollars per share) | $ 83.26 | $ 48.33 |
Total fair value of performance shares vested | $ 76 | $ 69 |
Unrecognized compensation costs | $ 39 | $ 28 |
Remaining weighted-average period | 1 year 7 months 6 days | 1 year 8 months 12 days |
Restricted Stock Units (RSUs) | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Weighted average grant date fair value (in dollars per share) | $ 86.10 | $ 54.17 |
Total fair value of performance shares vested | $ 34 | $ 35 |
Unrecognized compensation costs | $ 35 | $ 27 |
Remaining weighted-average period | 1 year 10 months 24 days | 2 years |
Variable Interest Entities - As
Variable Interest Entities - Assets and Liabilities of Consolidated VIEs (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Current assets | ||||
Cash and cash equivalents | $ 368 | $ 422 | $ 504 | |
Restricted cash and cash equivalents | 86 | 106 | $ 72 | |
Accounts receivable | ||||
Customer | 1,934 | 2,585 | ||
Other | 917 | 731 | ||
Inventories, net | ||||
Materials and supplies | 1,216 | 1,076 | ||
Other current assets | 1,655 | 1,026 | ||
Total current assets | 8,299 | 9,360 | ||
Property, plant and equipment, net | 22,116 | 19,822 | ||
Other | 1,910 | 2,059 | ||
Total deferred debits and other assets | 20,343 | 17,727 | ||
Total assets | [1] | 50,758 | 46,909 | |
Current liabilities | ||||
Long-term debt due within one year | 121 | 143 | ||
Accounts payable | 1,302 | 2,828 | ||
Other current liabilities | 338 | 344 | ||
Total current liabilities | 6,319 | 7,839 | ||
Long-term debt | 7,496 | 4,466 | ||
Asset retirement obligations | 14,118 | 12,699 | ||
Other noncurrent liabilities | 1,125 | 1,178 | ||
Total deferred credits and other liabilities | 25,657 | 23,232 | ||
Total liabilities | [1] | 39,472 | 35,537 | |
Recourse | ||||
Current liabilities | ||||
Total liabilities | 1 | |||
Variable Interest Entity, Primary Beneficiary | ||||
Current assets | ||||
Cash and cash equivalents | 48 | 51 | ||
Restricted cash and cash equivalents | 47 | 46 | ||
Accounts receivable | ||||
Customer | 19 | 20 | ||
Other | 10 | 9 | ||
Inventories, net | ||||
Materials and supplies | 14 | 12 | ||
Other current assets | 1,249 | 549 | ||
Total current assets | 1,387 | 687 | ||
Property, plant and equipment, net | 1,979 | 1,965 | ||
Other | 166 | 190 | ||
Total deferred debits and other assets | 2,145 | 2,155 | ||
Total assets | 3,532 | 2,842 | ||
Current liabilities | ||||
Long-term debt due within one year | 63 | 60 | ||
Accounts payable | 11 | 17 | ||
Accrued expenses | 20 | 23 | ||
Other current liabilities | 0 | 2 | ||
Total current liabilities | 94 | 102 | ||
Long-term debt | 704 | 764 | ||
Asset retirement obligations | 190 | 173 | ||
Other noncurrent liabilities | 2 | 3 | ||
Total deferred credits and other liabilities | 896 | 940 | ||
Total liabilities | 990 | 1,042 | ||
Unamortized energy contract assets, current | 22 | 23 | ||
Unamortized energy contract assets, noncurrent | $ 155 | $ 178 | ||
[1] Our consolidated assets include $3,355 million and $2,641 million at December 31, 2023 and 2022, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $990 million and $1,041 million at December 31, 2023 and 2022, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 22–Variable Interest Entities for additional information. |
Variable Interest Entities - Na
Variable Interest Entities - Narrative (Details) | Dec. 31, 2023 | Dec. 31, 2022 |
CRP | ||
Variable Interest Entity [Line Items] | ||
Ownership interest | 51% | 51% |
Antelope Valley | ||
Variable Interest Entity [Line Items] | ||
Ownership interest | 100% | 100% |
NER | ||
Variable Interest Entity [Line Items] | ||
Ownership interest | 100% | 100% |
Distributed Energy Company | ||
Variable Interest Entity [Line Items] | ||
Ownership interest | 90% | 90% |
Constellation Energy Generation, LLC | Solar project entities | ||
Variable Interest Entity [Line Items] | ||
Ownership interest | 100% | |
Constellation Energy Generation, LLC | Wind project entities | ||
Variable Interest Entity [Line Items] | ||
Ownership interest | 100% |
Variable Interest Entities - Su
Variable Interest Entities - Summary of Significant Unconsolidated VIEs (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | |
Variable Interest Entity [Line Items] | |||
Total assets | [1] | $ 50,758 | $ 46,909 |
Total liabilities | [1] | 39,472 | 35,537 |
Variable Interest Entity, Not Primary Beneficiary | |||
Variable Interest Entity [Line Items] | |||
Total assets | 704 | 715 | |
Total liabilities | 77 | 54 | |
Other ownership interests in VIE | 627 | 661 | |
Commercial Agreement VIEs | Variable Interest Entity, Not Primary Beneficiary | |||
Variable Interest Entity [Line Items] | |||
Total assets | 704 | 715 | |
Total liabilities | 77 | 54 | |
Other ownership interests in VIE | 627 | 661 | |
Equity Investment VIEs | Variable Interest Entity, Not Primary Beneficiary | |||
Variable Interest Entity [Line Items] | |||
Total assets | 0 | 0 | |
Total liabilities | 0 | 0 | |
Other ownership interests in VIE | $ 0 | $ 0 | |
[1] Our consolidated assets include $3,355 million and $2,641 million at December 31, 2023 and 2022, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $990 million and $1,041 million at December 31, 2023 and 2022, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 22–Variable Interest Entities for additional information. |
Supplemental Financial Inform_3
Supplemental Financial Information - Summary of Taxes Other Than Income (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Income Statement [Abstract] | |||
Gross receipts | $ 139 | $ 130 | $ 99 |
Property | 253 | 274 | 268 |
Payroll | $ 142 | $ 130 | $ 109 |
Supplemental Financial Inform_4
Supplemental Financial Information - Summary of Other Income (Expense) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Supplemental Financial Information [Abstract] | |||
Net realized income on NDT funds - Regulatory Agreement Units | $ 657 | $ 333 | $ 817 |
Net realized income on NDT funds - Non-Regulatory Agreement Units | 335 | 97 | 449 |
Net unrealized (losses) gains on NDT funds - Regulatory Agreement Units | 397 | (1,354) | 351 |
Net unrealized (losses) gains on NDT funds - Non-Regulatory Agreement Units | 259 | (798) | 209 |
Regulatory offset to NDT fund-related activities | (845) | 820 | (917) |
Total Decommissioning-related activities | 803 | (902) | 909 |
Non-service net periodic benefit credit | 54 | 110 | 0 |
Net unrealized (losses) gains from CTV investments | 307 | (13) | (160) |
Return to provision adjustment | 19 | (49) | 0 |
Other | 85 | 68 | 46 |
Other Nonoperating Income (Expense), Total | $ 1,268 | $ (786) | $ 795 |
Supplemental Financial Inform_5
Supplemental Financial Information - Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Depreciation, amortization and accretion | ||||
Property, plant, and equipment | $ 1,073 | $ 1,065 | $ 2,954 | |
Amortization of intangible assets, net | 58 | 61 | 80 | |
Nuclear fuel | 787 | 758 | 992 | |
ARO accretion | 596 | 543 | 514 | |
Total depreciation, amortization, and accretion | 2,514 | 2,427 | 4,540 | |
Cash paid during the year | ||||
Interest (net of amount capitalized) | 264 | 230 | 275 | |
Income taxes (net of refunds) | 466 | 287 | 426 | |
Other non-cash operating activities | ||||
Pension and non-pension postretirement benefit costs | 47 | 17 | 123 | |
Other decommissioning-related activity | (534) | (263) | (946) | |
Energy-related options | 183 | 293 | 125 | |
Asset Impairment Charges | 71 | 0 | 545 | |
(Gain) loss on sale of assets and businesses | (27) | (1) | (201) | |
Severance costs | 2 | (1) | (73) | |
Long-term incentive plan | 57 | 44 | 0 | |
Amortization of operating ROU asset | 64 | 75 | 119 | |
(Gain) loss on sale of receivables | 75 | 69 | 36 | |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract] | ||||
Cash and cash equivalents | 368 | 422 | 504 | |
Restricted cash and cash equivalents | 86 | 106 | 72 | |
Total cash, restricted cash, and cash equivalents | 454 | 528 | 576 | $ 327 |
Constellation Energy Generation, LLC | ||||
Depreciation, amortization and accretion | ||||
Total depreciation, amortization, and accretion | 2,514 | 2,427 | 4,540 | |
Other non-cash operating activities | ||||
Pension and non-pension postretirement benefit costs | 47 | 17 | 123 | |
Other decommissioning-related activity | (534) | (263) | (946) | |
Energy-related options | 183 | 293 | 125 | |
Asset Impairment Charges | 71 | 0 | 545 | |
(Gain) loss on sale of assets and businesses | (27) | (1) | (201) | |
Severance costs | 2 | (1) | (73) | |
Long-term incentive plan | 0 | 0 | 0 | |
Amortization of operating ROU asset | 64 | 75 | 119 | |
(Gain) loss on sale of receivables | 75 | 69 | 36 | |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract] | ||||
Cash and cash equivalents | 366 | 403 | 504 | |
Restricted cash and cash equivalents | 74 | 98 | 72 | |
Total cash, restricted cash, and cash equivalents | 440 | 501 | 576 | $ 327 |
Amortization of Intangible Assets Included in Depreciation Expense | ||||
Depreciation, amortization and accretion | ||||
Amortization of intangible assets, net | 23 | 26 | 49 | |
Unamortized Energy Contracts | ||||
Depreciation, amortization and accretion | ||||
Amortization of energy contract assets and liabilities | $ 35 | $ 35 | $ 31 |
Supplemental Financial Inform_6
Supplemental Financial Information - Supplemental Balance Sheet Information (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Investments [Abstract] | ||
Equity investments without readily determinable fair values | $ 103 | $ 46 |
Total investments | 563 | 202 |
Accrued Expenses [Abstract] | ||
Accounts payable and accrued expenses | 1,302 | 2,828 |
Compensation-related accruals | 680 | 540 |
Taxes accrued | 399 | 257 |
Equity method investments(a) | ||
Investments [Abstract] | ||
Equity method investments(a) | 7 | 82 |
Employee benefit trusts and investments | ||
Investments [Abstract] | ||
Employee benefit trusts and investments | 82 | 68 |
Other available for sale debt security investments | ||
Investments [Abstract] | ||
Other available for sale debt security investments | 2 | 6 |
Constellation Energy Generation, LLC | ||
Investments [Abstract] | ||
Total investments | 563 | 202 |
Accrued Expenses [Abstract] | ||
Accounts payable and accrued expenses | 1,289 | 2,810 |
Compensation-related accruals | 576 | 502 |
Taxes accrued | 390 | 257 |
Commonwealth Edison Co [Member] | ||
Investments [Abstract] | ||
Equity investments with readily determinable fair values | $ 369 | $ 0 |
Related Party Transactions - Op
Related Party Transactions - Operating Revenues and Purchased Power and Fuel From Affiliates (Details) - Affiliated Entities - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Related Party Transaction [Line Items] | |||
Operating revenues | $ 0 | $ 160 | $ 1,188 |
ComEd | |||
Related Party Transaction [Line Items] | |||
Operating revenues | 58 | 376 | |
PECO | |||
Related Party Transaction [Line Items] | |||
Operating revenues | 33 | 196 | |
Baltimore Gas And Electric Company Affiliate [Member] | |||
Related Party Transaction [Line Items] | |||
Operating revenues | 18 | 236 | |
PHI | |||
Related Party Transaction [Line Items] | |||
Operating revenues | 51 | 366 | |
Potomac Electric Power Co Affiliate [Member] | |||
Related Party Transaction [Line Items] | |||
Operating revenues | 39 | 270 | |
Delmarva Power and Light Co Affiliate [Member] | |||
Related Party Transaction [Line Items] | |||
Operating revenues | 10 | 79 | |
Atlantic City Electric Co Affiliate [Member] | |||
Related Party Transaction [Line Items] | |||
Operating revenues | 2 | 17 | |
Other | |||
Related Party Transaction [Line Items] | |||
Operating revenues | $ 0 | $ 14 |
Related Party Transactions - Na
Related Party Transactions - Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Related Party Transaction [Line Items] | |||
Related Party Costs, Operating and Maintenance | $ 0 | $ 44 | $ 621 |
Exelon Business Services Co Affiliate [Member] | |||
Related Party Transaction [Line Items] | |||
Related Party Costs, Operating and Maintenance | 44 | 588 | |
Related Party Transaction Capitalized Costs Support Services | $ 15 | $ 129 |
Schedule II - Valuation and Q_2
Schedule II - Valuation and Qualifying Accounts Schedule (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Allowance for credit losses | |||
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward] | |||
Balance at Beginning of Period | $ 51 | $ 59 | $ 32 |
Charged to Costs and Expenses | 25 | 10 | 34 |
Charged to Other Accounts | 0 | 0 | 0 |
Deductions | (15) | (18) | (7) |
Balance at End of Period | 61 | 51 | 59 |
Deferred tax valuation allowance | |||
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward] | |||
Balance at Beginning of Period | 11 | 22 | 23 |
Charged to Costs and Expenses | 0 | 0 | 0 |
Charged to Other Accounts | (1) | (11) | (1) |
Deductions | 0 | 0 | 0 |
Balance at End of Period | 10 | 11 | 22 |
Reserve for obsolete materials | |||
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward] | |||
Balance at Beginning of Period | 238 | 250 | 265 |
Charged to Costs and Expenses | 8 | 11 | (6) |
Charged to Other Accounts | 9 | (6) | (2) |
Deductions | (9) | (17) | (7) |
Balance at End of Period | $ 246 | $ 238 | $ 250 |
Uncategorized Items - ceg-20231
Label | Element | Value |
Pension Plan [Member] | ||
Defined Benefit Plan, Benefit Obligation | us-gaap_DefinedBenefitPlanBenefitObligation | $ 9,220,000,000 |
Other Postretirement Benefits Plan [Member] | ||
Defined Benefit Plan, Benefit Obligation | us-gaap_DefinedBenefitPlanBenefitObligation | $ 1,780,000,000 |