Cover
Cover - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Jun. 30, 2022 | |
Document Information [Line Items] | ||
Document Type | 10-K | |
Document Annual Report | true | |
Document Period End Date | Dec. 31, 2022 | |
Current Fiscal Year End Date | --12-31 | |
Document Transition Report | false | |
Entity File Number | 1-16305 | |
Entity Registrant Name | PUGET ENERGY INC /WA | |
Entity Incorporation, State or Country Code | WA | |
Entity Address, Address Line One | 355 110th Ave NE | |
Entity Address, City or Town | Bellevue | |
Entity Address, State or Province | WA | |
Entity Address, Postal Zip Code | 98004 | |
City Area Code | (425) | |
Local Phone Number | 454-6363 | |
Entity Tax Identification Number | 91-1969407 | |
Entity Well-known Seasoned Issuer | No | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Filer Category | Non-accelerated Filer | |
Entity Small Business | false | |
Entity Emerging Growth Company | false | |
ICFR Auditor Attestation Flag | true | |
Entity Shell Company | false | |
Entity Central Index Key | 0001085392 | |
Entity Public Float | $ 0 | |
Entity Common Stock, Shares Outstanding | 200 | |
Document Fiscal Year Focus | 2022 | |
Document Fiscal Period Focus | FY | |
Amendment Flag | false | |
Subsidiaries [Member] | ||
Document Information [Line Items] | ||
Document Type | 10-K | |
Document Annual Report | true | |
Document Period End Date | Dec. 31, 2022 | |
Current Fiscal Year End Date | --12-31 | |
Document Transition Report | false | |
Entity File Number | 1-4393 | |
Entity Registrant Name | PUGET SOUND ENERGY, INC. | |
Entity Incorporation, State or Country Code | WA | |
Entity Address, Address Line One | 355 110th Ave NE | |
Entity Address, City or Town | Bellevue | |
Entity Address, State or Province | WA | |
Entity Address, Postal Zip Code | 98004 | |
City Area Code | (425) | |
Local Phone Number | 454-6363 | |
Entity Tax Identification Number | 91-0374630 | |
Entity Well-known Seasoned Issuer | No | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Filer Category | Non-accelerated Filer | |
Entity Small Business | false | |
Entity Emerging Growth Company | false | |
ICFR Auditor Attestation Flag | true | |
Entity Shell Company | false | |
Entity Central Index Key | 0000081100 | |
Entity Public Float | $ 0 | |
Entity Common Stock, Shares Outstanding | 85,903,791 | |
Document Fiscal Year Focus | 2022 | |
Document Fiscal Period Focus | FY | |
Amendment Flag | false |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2022 | |
Auditor [Line Items] | |
Auditor Location | Portland, Oregon |
Auditor Name | PricewaterhouseCoopers LLP |
Auditor Firm ID | 238 |
Subsidiaries [Member] | |
Auditor [Line Items] | |
Auditor Location | Portland, Oregon |
Auditor Name | PricewaterhouseCoopers LLP |
Auditor Firm ID | 238 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Electric | $ 2,961,457 | $ 2,671,623 | $ 2,319,416 |
Natural gas | 1,209,636 | 1,067,418 | 980,913 |
Other | 50,069 | 66,620 | 26,121 |
Total operating revenue | 4,221,162 | 3,805,661 | 3,326,450 |
Purchased electricity | 1,038,728 | 784,565 | 593,719 |
Electric generation fuel | 348,159 | 282,254 | 199,107 |
Residential exchange | (77,715) | (82,225) | (80,294) |
Purchased natural gas | 500,849 | 398,553 | 362,872 |
Unrealized (gain) loss on derivative instruments, net | (261,177) | (13,785) | 26,807 |
Utility operations and maintenance | 665,259 | 629,864 | 597,048 |
Non-utility expense and other | 59,804 | 58,281 | 43,425 |
Depreciation and amortization | 663,232 | 704,783 | 647,755 |
Conservation amortization | 116,942 | 103,147 | 99,585 |
Taxes other than income taxes | 389,442 | 362,527 | 328,602 |
Total operating expenses | 3,443,523 | 3,227,964 | 2,818,626 |
Operating income (loss) | 777,639 | 577,697 | 507,824 |
Other income | 45,450 | 57,483 | 58,759 |
Other expense | (19,569) | (14,467) | (23,207) |
AFUDC | 18,444 | 16,743 | 14,827 |
Interest expense | (347,921) | (352,092) | (373,822) |
Income (loss) before income taxes | 474,043 | 285,364 | 184,381 |
Income tax (benefit) expense | 59,698 | 24,515 | 1,664 |
Net income (loss) | 414,345 | 260,849 | 182,717 |
Subsidiaries [Member] | |||
Electric | 2,961,457 | 2,671,623 | 2,319,416 |
Natural gas | 1,209,636 | 1,067,418 | 980,913 |
Other | 45,080 | 66,620 | 26,121 |
Total operating revenue | 4,216,173 | 3,805,661 | 3,326,450 |
Purchased electricity | 1,038,728 | 784,565 | 593,719 |
Electric generation fuel | 348,159 | 282,254 | 199,107 |
Residential exchange | (77,715) | (82,225) | (80,294) |
Purchased natural gas | 500,849 | 398,553 | 362,872 |
Unrealized (gain) loss on derivative instruments, net | (261,177) | (13,785) | 26,807 |
Utility operations and maintenance | 665,259 | 629,864 | 597,048 |
Non-utility expense and other | 47,194 | 56,242 | 42,266 |
Depreciation and amortization | 657,349 | 704,372 | 647,546 |
Conservation amortization | 116,942 | 103,147 | 99,585 |
Taxes other than income taxes | 388,123 | 362,527 | 328,602 |
Total operating expenses | 3,423,711 | 3,225,514 | 2,817,258 |
Operating income (loss) | 792,462 | 580,147 | 509,192 |
Other income | 36,684 | 46,523 | 46,923 |
Other expense | (19,569) | (14,467) | (23,207) |
AFUDC | 18,444 | 16,743 | 14,827 |
Interest expense | (256,774) | (248,624) | (247,213) |
Income (loss) before income taxes | 571,247 | 380,322 | 300,522 |
Income tax (benefit) expense | 80,295 | 44,259 | 26,242 |
Net income (loss) | $ 490,952 | $ 336,063 | $ 274,280 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Net Income (Loss) | $ 414,345 | $ 260,849 | $ 182,717 |
Other comprehensive income (loss): | |||
Net unrealized gain (loss) from pension and postretirement plans, net of tax | 2,658 | 59,005 | (2,288) |
Other comprehensive income (loss) | 2,658 | 59,005 | (2,288) |
Comprehensive income (loss) | 417,003 | 319,854 | 180,429 |
Subsidiaries [Member] | |||
Net Income (Loss) | 490,952 | 336,063 | 274,280 |
Other comprehensive income (loss): | |||
Net unrealized gain (loss) from pension and postretirement plans, net of tax | 9,711 | 67,431 | 7,136 |
Amortization of treasury interest rate swaps to earnings, net of tax | 386 | 384 | 385 |
Other comprehensive income (loss) | 10,097 | 67,815 | 7,521 |
Comprehensive income (loss) | $ 501,049 | $ 403,878 | $ 281,801 |
CONSOLIDATED STATEMENTS OF CO_2
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Net unrealized gain (loss) from pension and postretirement plans, tax | $ 708 | $ 15,686 | $ (609) |
Subsidiaries [Member] | |||
Net unrealized gain (loss) from pension and postretirement plans, tax | 2,580 | 17,925 | 1,897 |
Amortization of Financing Cash Flow Hedge Contracts to Earnings Tax | $ 102 | $ 103 | $ 102 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Utility Plant [Abstract] | ||
Electric plant | $ 10,300,895 | $ 9,729,643 |
Natural gas plant | 4,721,982 | 4,498,198 |
Common plant | 1,103,783 | 1,155,567 |
Less: Accumulated depreciation and amortization | (4,341,789) | (4,031,458) |
Net utility plant | 11,784,871 | 11,351,950 |
Other property and investments: | ||
Goodwill | 1,656,513 | 1,656,513 |
Other property and investments | 328,535 | 324,897 |
Total other property and investments | 1,985,048 | 1,981,410 |
Current assets: | ||
Cash and cash equivalents | 105,740 | 56,946 |
Restricted cash | 63,045 | 46,204 |
Accounts receivable, net of allowance for doubtful accounts of $41,962 and $34,958, respectively | 673,236 | 398,895 |
Unbilled revenue | 284,022 | 271,606 |
Materials and supplies, at average cost | 132,172 | 113,287 |
Fuel and natural gas inventory, at average cost | 94,075 | 59,393 |
Unrealized gain on derivative instruments | 587,029 | 128,210 |
Prepaid expenses and other | 41,940 | 46,293 |
Power contract acquisition adjustment gain | 16,736 | 17,274 |
Total current assets | 1,997,995 | 1,138,108 |
Other long-term and regulatory assets: | ||
Power cost adjustment mechanism | 112,207 | 79,546 |
Purchased gas adjustment receivable | 0 | 57,935 |
Regulatory assets related to power contracts | 7,904 | 9,689 |
Other regulatory assets | 784,231 | 815,058 |
Unrealized gain on derivative instruments | 94,621 | 26,197 |
Power contract acquisition adjustment gain | 46,924 | 63,660 |
Operating lease right-of-use asset | 193,509 | 184,957 |
Other | 180,204 | 163,374 |
Total other long-term and regulatory assets | 1,419,600 | 1,400,416 |
Total assets | 17,187,514 | 15,871,884 |
Common shareholder’s equity: | ||
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding | 0 | 0 |
Additional paid-in capital | 3,523,532 | 3,523,532 |
Retained earnings | 1,465,331 | 1,067,216 |
Accumulated other comprehensive income (loss), net of tax | (24,774) | (27,432) |
Total common shareholder’s equity | 4,964,089 | 4,563,316 |
Long-term debt: | ||
First mortgage bonds and senior notes | 4,662,000 | 4,662,000 |
Pollution control bonds | 161,860 | 161,860 |
Long-term debt | 2,034,300 | 1,583,300 |
Debt discount, issuance costs and other | 194,787 | 203,394 |
Total long-term debt | 6,663,373 | 6,203,766 |
Total capitalization | 11,627,462 | 10,767,082 |
Current liabilities: | ||
Accounts payable | 665,750 | 444,384 |
Short-term debt | 441,300 | 140,000 |
Current maturities of long-term debt | 0 | 450,000 |
Accrued expenses: | ||
Taxes | 116,098 | 127,398 |
Salaries and wages | 60,537 | 47,936 |
Interest | 62,148 | 67,807 |
Unrealized loss on derivative instruments | 124,976 | 63,309 |
Power contract acquisition adjustment loss | 1,638 | 1,785 |
Operating lease liabilities | 20,342 | 20,398 |
Other | 70,685 | 62,406 |
Total current liabilities | 1,563,474 | 1,425,423 |
Other Long-term and regulatory liabilities: | ||
Deferred income taxes | 985,947 | 912,484 |
Unrealized loss on derivative instruments | 18,366 | 40,965 |
Purchased gas adjustment liability | 3,536 | 0 |
Regulatory liabilities | 1,147,143 | 844,184 |
Regulatory liability for deferred income taxes | 811,161 | 865,976 |
Regulatory liabilities related to power contracts | 63,660 | 80,934 |
Power contract acquisition adjustment loss | 6,266 | 7,904 |
Operating lease liabilities | 181,265 | 172,510 |
Finance lease liabilities | 102,518 | 105,303 |
Other deferred credits | 676,716 | 649,119 |
Total long-term and regulatory liabilities | 3,996,578 | 3,679,379 |
Commitments and contingencies (Note 16) | ||
Total capitalization and liabilities | $ 17,187,514 | $ 15,871,884 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 1,000 | 1,000 |
Common stock, shares outstanding (in shares) | 200 | 200 |
Subsidiaries [Member] | ||
Utility Plant [Abstract] | ||
Electric plant | $ 12,071,531 | $ 11,535,976 |
Natural gas plant | 5,276,156 | 5,054,622 |
Common plant | 1,125,217 | 1,177,598 |
Less: Accumulated depreciation and amortization | (6,688,033) | (6,416,246) |
Net utility plant | 11,784,871 | 11,351,950 |
Other property and investments: | ||
Other property and investments | 80,076 | 74,602 |
Total other property and investments | 80,076 | 74,602 |
Current assets: | ||
Cash and cash equivalents | 102,840 | 50,043 |
Restricted cash | 63,045 | 46,204 |
Accounts receivable, net of allowance for doubtful accounts of $41,962 and $34,958, respectively | 671,071 | 402,602 |
Unbilled revenue | 284,014 | 271,606 |
Materials and supplies, at average cost | 132,172 | 113,287 |
Fuel and natural gas inventory, at average cost | 91,783 | 58,129 |
Unrealized gain on derivative instruments | 587,029 | 128,210 |
Prepaid expenses and other | 41,940 | 46,293 |
Total current assets | 1,973,894 | 1,116,374 |
Other long-term and regulatory assets: | ||
Power cost adjustment mechanism | 112,207 | 79,546 |
Purchased gas adjustment receivable | 0 | 57,935 |
Other regulatory assets | 784,231 | 815,058 |
Unrealized gain on derivative instruments | 94,621 | 26,197 |
Operating lease right-of-use asset | 193,509 | 184,957 |
Other | 176,833 | 162,391 |
Total other long-term and regulatory assets | 1,361,401 | 1,326,084 |
Total assets | 15,200,242 | 13,869,010 |
Common shareholder’s equity: | ||
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding | 859 | 859 |
Additional paid-in capital | 3,535,105 | 3,485,105 |
Retained earnings | 1,438,163 | 982,607 |
Accumulated other comprehensive income (loss), net of tax | (103,044) | (113,141) |
Total common shareholder’s equity | 4,871,083 | 4,355,430 |
Long-term debt: | ||
First mortgage bonds and senior notes | 4,662,000 | 4,662,000 |
Pollution control bonds | 161,860 | 161,860 |
Debt discount, issuance costs and other | 37,095 | 39,141 |
Total long-term debt | 4,786,765 | 4,784,719 |
Total capitalization | 9,657,848 | 9,140,149 |
Current liabilities: | ||
Accounts payable | 664,457 | 451,716 |
Short-term debt | 357,000 | 140,000 |
Accrued expenses: | ||
Taxes | 116,472 | 133,406 |
Salaries and wages | 60,537 | 47,936 |
Interest | 52,170 | 51,832 |
Unrealized loss on derivative instruments | 124,976 | 63,309 |
Operating lease liabilities | 20,342 | 20,398 |
Other | 70,685 | 62,406 |
Total current liabilities | 1,466,639 | 971,003 |
Other Long-term and regulatory liabilities: | ||
Deferred income taxes | 1,139,600 | 1,084,203 |
Unrealized loss on derivative instruments | 18,366 | 40,965 |
Purchased gas adjustment liability | 3,536 | 0 |
Regulatory liabilities | 1,145,879 | 842,920 |
Regulatory liability for deferred income taxes | 811,724 | 866,541 |
Operating lease liabilities | 181,265 | 172,510 |
Finance lease liabilities | 102,518 | 105,303 |
Other deferred credits | 672,867 | 645,416 |
Total long-term and regulatory liabilities | 4,075,755 | 3,757,858 |
Commitments and contingencies (Note 16) | ||
Total capitalization and liabilities | $ 15,200,242 | $ 13,869,010 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 150,000,000 | 150,000,000 |
Common stock, shares outstanding (in shares) | 85,903,791 | 85,903,791 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Assets | ||
Construction work in progress | $ 861,801 | $ 870,204 |
Current assets: | ||
Allowance for doubtful accounts | $ 41,962 | $ 34,958 |
Common shareholder’s equity: | ||
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 1,000 | 1,000 |
Common stock, shares outstanding (in shares) | 200 | 200 |
Subsidiaries [Member] | ||
Assets | ||
Construction work in progress | $ 861,801 | $ 870,204 |
Current assets: | ||
Allowance for doubtful accounts | $ 41,962 | $ (34,958) |
Common shareholder’s equity: | ||
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 150,000,000 | 150,000,000 |
Common stock, shares outstanding (in shares) | 85,903,791 | 85,903,791 |
CONSOLIDATED STATEMENTS OF COMM
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY - USD ($) $ in Thousands | Total | Common Stock | Additional Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Subsidiaries [Member] | Subsidiaries [Member] Common Stock | Subsidiaries [Member] Additional Paid-in Capital | Subsidiaries [Member] Retained Earnings | Subsidiaries [Member] Accumulated Other Comprehensive Income (Loss) |
Balance at Dec. 31, 2019 | $ 4,000,299 | $ 3,308,957 | $ 775,491 | $ (84,149) | $ 4,048,680 | $ 859 | $ 3,485,105 | $ 751,193 | $ (188,477) | |
Balance (in shares) at Dec. 31, 2019 | 200 | 85,903,791 | ||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||
Net income (loss) | 182,717 | 182,717 | 274,280 | 274,280 | ||||||
Dividends, Common Stock | (45,421) | (45,421) | (149,072) | (149,072) | ||||||
Other comprehensive income (loss) | (2,288) | (2,288) | 7,521 | 7,521 | ||||||
Investment from parent | 4,575 | 4,575 | 0 | |||||||
Balance at Dec. 31, 2020 | 4,139,882 | 3,313,532 | 912,787 | (86,437) | 4,181,409 | $ 859 | 3,485,105 | 876,401 | (180,956) | |
Balance (in shares) at Dec. 31, 2020 | 200 | 85,903,791 | ||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||
Net income (loss) | 260,849 | 260,849 | 336,063 | 336,063 | ||||||
Dividends, Common Stock | (106,420) | (106,420) | (229,857) | (229,857) | ||||||
Other comprehensive income (loss) | 59,005 | 59,005 | 67,815 | 67,815 | ||||||
Investment from parent | 210,000 | 210,000 | 0 | |||||||
Balance at Dec. 31, 2021 | $ 4,563,316 | 3,523,532 | 1,067,216 | (27,432) | $ 4,355,430 | $ 859 | 3,485,105 | 982,607 | (113,141) | |
Balance (in shares) at Dec. 31, 2021 | 200 | 200 | 85,903,791 | 85,903,791 | ||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||
Net income (loss) | $ 414,345 | 414,345 | $ 490,952 | 490,952 | ||||||
Dividends, Common Stock | (16,230) | (16,230) | (35,396) | (35,396) | ||||||
Other comprehensive income (loss) | 2,658 | 2,658 | 10,097 | 10,097 | ||||||
Investment from parent | 0 | 50,000 | 50,000 | |||||||
Balance at Dec. 31, 2022 | $ 4,964,089 | $ 3,523,532 | $ 1,465,331 | $ (24,774) | $ 4,871,083 | $ 859 | $ 3,535,105 | $ 1,438,163 | $ (103,044) | |
Balance (in shares) at Dec. 31, 2022 | 200 | 200 | 85,903,791 | 85,903,791 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Net Cash Provided by (Used in) Operating Activities [Abstract] | |||
Net Income (Loss) | $ 414,345 | $ 260,849 | $ 182,717 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation and amortization | 663,232 | 704,783 | 647,755 |
Conservation amortization | 116,942 | 103,147 | 99,585 |
Deferred income taxes and tax credits, net | 17,941 | (1,228) | (6,287) |
Net unrealized (gain) loss on derivative instruments | (261,177) | (13,785) | 26,807 |
(Gain) or loss on extinguishment of debt | 0 | 0 | 13,546 |
AFUDC - equity | (28,310) | (27,806) | (23,223) |
Production tax credit | 0 | (45,562) | (39,761) |
Other non-cash | (9,284) | ||
Other non-cash | 4,757 | 9,069 | |
Funding of pension liability | 18,000 | 18,000 | 18,000 |
Regulatory assets and liabilities | 90,335 | 126,625 | 152,417 |
Purchased gas adjustment | (37,256) | (29,720) | (45,111) |
Other long term assets and liabilities | 23,639 | 24,761 | 3,171 |
Change in certain current assets and liabilities: | |||
Accounts receivable and unbilled revenue | 258,188 | 96,498 | 32,994 |
Materials and supplies | 18,885 | (5,046) | 2,649 |
Fuel and natural gas inventory | 34,682 | 10,598 | (3,287) |
Prepayments and other | (4,186) | 997 | 18,242 |
Accounts payable | 237,260 | 84,775 | 16,516 |
Taxes payable | (11,300) | 16,646 | 10,773 |
Other | 18,215 | (3,224) | (30,854) |
Net cash provided by (used in) operating activities | 769,618 | 826,598 | 727,568 |
Net Cash Provided by (Used in) Investing Activities | |||
Construction expenditures - excluding equity AFUDC | 1,004,713 | 922,144 | 908,136 |
Other | 567 | (1,367) | (5,340) |
Net cash provided by (used in) investing activities | (1,005,280) | (920,777) | (902,796) |
Net Cash Provided by (Used in) Financing Activities | |||
Change in short-term debt, net | 301,300 | (233,800) | 197,800 |
Dividends paid | 16,230 | 106,420 | 45,421 |
Investment from parent | 0 | 210,000 | 4,575 |
Proceeds from long-term debt and bonds issued | 448,075 | 961,538 | 644,690 |
Redemption of bonds and notes | 450,000 | 502,410 | 450,000 |
Repayment of term loan and revolving credit | 0 | (234,000) | (159,400) |
Other | 18,152 | 20,570 | (1,311) |
Net cash provided by (used in) financing activities | 301,297 | 115,478 | 190,933 |
Net increase (decrease) in cash, cash equivalents, and restricted cash | 65,635 | 21,299 | 15,705 |
Cash, cash equivalents, and restricted cash at beginning of period | 103,150 | 81,851 | 66,146 |
Cash, cash equivalents, and restricted cash at end of period | 168,785 | 103,150 | 81,851 |
Supplemental cash flow information: | |||
Cash payments for interest (net of capitalized interest) | 320,656 | 329,894 | 336,441 |
Cash payments (refunds) for income taxes | 46,785 | 22,647 | 4,974 |
Non-cash financing and investing activities: | |||
Accounts payable for capital expenditures eliminated from cash flow | 68,357 | 89,958 | 58,304 |
Recognition of finance lease eliminated from cash flows | 454 | 105,176 | 0 |
Subsidiaries [Member] | |||
Net Cash Provided by (Used in) Operating Activities [Abstract] | |||
Net Income (Loss) | 490,952 | 336,063 | 274,280 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation and amortization | 657,349 | 704,372 | 647,546 |
Conservation amortization | 116,942 | 103,147 | 99,585 |
Deferred income taxes and tax credits, net | (2,103) | (8,652) | 15,271 |
Net unrealized (gain) loss on derivative instruments | (261,177) | (13,785) | 26,807 |
AFUDC - equity | (28,310) | (27,806) | (23,223) |
Production tax credit | 0 | (45,562) | (39,761) |
Other non-cash | (6,005) | (19,761) | (1,575) |
Funding of pension liability | 18,000 | 18,000 | 18,000 |
Regulatory assets and liabilities | 90,335 | 126,625 | 152,417 |
Purchased gas adjustment | (37,256) | (29,720) | (45,111) |
Other long term assets and liabilities | 14,359 | 14,097 | (8,764) |
Change in certain current assets and liabilities: | |||
Accounts receivable and unbilled revenue | 252,308 | 96,487 | 33,835 |
Materials and supplies | 18,885 | (5,046) | 2,649 |
Fuel and natural gas inventory | 33,654 | 10,598 | (3,287) |
Prepayments and other | (4,186) | 997 | 18,242 |
Accounts payable | 228,635 | 92,007 | 16,549 |
Taxes payable | (16,934) | 26,152 | 7,277 |
Other | 24,211 | 6,256 | (29,965) |
Net cash provided by (used in) operating activities | 817,461 | 920,393 | 824,810 |
Net Cash Provided by (Used in) Investing Activities | |||
Construction expenditures - excluding equity AFUDC | 1,000,810 | 908,273 | 876,437 |
Other | 567 | (1,367) | (5,340) |
Net cash provided by (used in) investing activities | (1,001,377) | (906,906) | (871,097) |
Net Cash Provided by (Used in) Financing Activities | |||
Change in short-term debt, net | 217,000 | (233,800) | 197,800 |
Dividends paid | 35,396 | 229,857 | 149,072 |
Investment from parent | 50,000 | 0 | 0 |
Proceeds from long-term debt and bonds issued | 0 | 446,063 | 0 |
Redemption of bonds and notes | 0 | 2,410 | 0 |
Other | 21,950 | 22,043 | 13,389 |
Net cash provided by (used in) financing activities | 253,554 | 2,039 | 62,117 |
Net increase (decrease) in cash, cash equivalents, and restricted cash | 69,638 | 15,526 | 15,830 |
Cash, cash equivalents, and restricted cash at beginning of period | 96,247 | 80,721 | 64,891 |
Cash, cash equivalents, and restricted cash at end of period | 165,885 | 96,247 | 80,721 |
Supplemental cash flow information: | |||
Cash payments for interest (net of capitalized interest) | 233,746 | 223,484 | 228,420 |
Cash payments (refunds) for income taxes | 93,058 | 38,442 | 11,521 |
Non-cash financing and investing activities: | |||
Accounts payable for capital expenditures eliminated from cash flow | 68,357 | 89,958 | 58,304 |
Recognition of finance lease eliminated from cash flows | $ 454 | $ 105,176 | $ 0 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies | Summary of Significant Accounting Policies Basis of Presentation Puget Energy is an energy services holding company that owns Puget Sound Energy (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma liquefied natural gas (LNG) facility. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that are incurred by PSE and allocated to Puget LNG are related party transactions by nature. In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any ASC 805, “Business Combinations” (ASC 805) purchase accounting adjustments. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. Utility Plant Puget Energy and PSE capitalize, at original cost, additions to utility plant, including renewals and betterments. Costs include indirect costs such as engineering, supervision, certain taxes, pension and other employee benefits and an allowance for funds used during construction (AFUDC). Replacements of minor items of property are included in maintenance expense. When the utility plant is retired and removed from service, the original cost of the property is charged to accumulated depreciation and costs associated with removal of the property, less salvage, are charged to the cost of removal regulatory liability. Planned Major Maintenance Planned major maintenance is an activity that typically occurs when PSE overhauls or substantially upgrades various systems and equipment on a scheduled basis. Costs related to planned major maintenance are deferred and amortized to the next scheduled major maintenance. This accounting method also follows the Washington Utilities and Transportation Commission (Washington Commission) regulatory treatment related to these generating facilities. Other Property and Investments For PSE, the costs of other property and investments (i.e., non-utility) are stated at historical cost. Expenditures for refurbishment and improvements that significantly add to productive capacity or extend useful life of an asset are capitalized. Replacements of minor items are expensed on a current basis. Gains and losses on assets sold or retired, which were previously recorded in utility plant, are apportioned between regulatory assets/liabilities and earnings. However, gains and losses on assets sold or retired, not previously recorded in utility plant, are reflected in earnings. Depreciation and Amortization The Company provides for depreciation and amortization on a straight-line basis. Amortization is recorded for intangibles such as regulatory assets and liabilities, computer software and franchises. The annual depreciation provision stated as a percent of a depreciable electric utility plant was 3.4%, 3.4%, and 3.5% in 2022, 2021, and 2020, respectively; depreciable natural gas utility plant was 2.9%, 2.8%, and 2.9% in 2022, 2021, and 2020, respectively; and depreciable common utility plant was 7.1%, 6.8% and 7.3% in 2022, 2021, and 2020, respectively. The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability. Tacoma LNG Facility In February 2022, the Tacoma LNG facility at the Port of Tacoma completed commissioning and commenced commercial operations. In December 2019, the Puget Sound Clean Air Agency (PSCAA) issued the air quality permit for the facility, and the Pollution Hearings Control Board of Washington State upheld the approval following extended litigation. The Tacoma LNG facility provides peak-shaving services to PSE’s natural gas customers, and provides LNG as fuel to transportation customers, particularly in the marine market at a lower cost due to the facility's scale. Pursuant to an order by the Washington Commission, PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility. The remaining 57.0% of common capital and operating costs of the Tacoma LNG facility will be allocated to Puget LNG. Per this allocation of costs, $249.1 million of non-utility plant and $244.7 million of construction work in progress related to Puget LNG's portion of the Tacoma LNG facility is reported in the Puget Energy "Other property and investments" financial statement line item as of December 31, 2022, and December 31, 2021, respectively. Additionally, $11.6 million, $1.3 million, and $0.6 million of operating costs are reported in the Puget Energy "Non-utility expense and other" financial statement line item in 2022, 2021, and 2020, respectively. Additionally, $245.7 million and $239.6 million of plant in service and construction work in progress related to PSE’s portion of the Tacoma LNG facility is reported in the PSE “Utility plant - Natural gas plant” financial statement line item as of December 31, 2022, and December 31, 2021, respectively, as PSE is a regulated entity. Cash and Cash Equivalents Cash and cash equivalents consist of demand bank deposits and short-term highly liquid investments with original maturities of three months or less at the time of purchase. The carrying amounts of cash and cash equivalents are reported at cost and approximate fair value, due to the short-term maturity. Restricted Cash Restricted cash amounts primarily represent cash posted as collateral for derivative contracts as well as funds required to be set aside for contractual obligations related to transmission and generation facilities. Materials and Supplies Materials and supplies are used primarily in the operation and maintenance of electric and natural gas distribution and transmission systems as well as spare parts for combustion turbines used for the generation of electricity. The Company records these items at weighted-average cost. Fuel and Natural Gas Inventory Fuel and natural gas inventory is used in the generation of electricity and for future sales to the Company’s natural gas customers. Fuel inventory consists of coal, diesel and natural gas used for generation. Natural gas inventory consists of natural gas and LNG held in storage for future sales. The Company records fuel inventory and natural gas inventory for unregulated operations at the lower of cost or net realizable value and natural gas inventory for regulated operations at average cost. Regulatory Assets and Liabilities PSE accounts for its regulated operations in accordance with ASC 980, “Regulated Operations” (ASC 980). ASC 980 requires PSE to defer certain costs or losses that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. It similarly requires deferral of revenues or gains that are expected to be returned to customers in the future. Accounting under ASC 980 is appropriate as long as rates are established by or subject to approval by independent third-party regulators; rates are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that rates set at levels that will recover costs can be charged to and collected from customers. In most cases, PSE classifies regulatory assets and liabilities as long-term when amortization periods extend longer than one year. For further details regarding regulatory assets and liabilities, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report. Puget Energy recorded regulatory assets and liabilities at the time of the merger related to power purchase contracts. Allowance for Funds Used During Construction AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. The amount of AFUDC recorded in each accounting period varies depending primarily upon the level of construction work in progress and the AFUDC rate used. AFUDC is capitalized as a part of the cost of utility plant; the AFUDC debt portion is credited to interest expense, while the AFUDC equity portion is credited to other income. Cash inflow related to AFUDC does not occur until these charges are reflected in rates. The AFUDC rate authorized by the Washington Commission for natural gas and electric utility plant additions effective December 19, 2017, was 7.60%. Effective October 1, 2020 for natural gas and October 15, 2020 for electric the authorized AFUDC rate is 7.39%. The Washington Commission authorized the Company to calculate AFUDC using its allowed rate of return. To the extent amounts calculated using this rate exceed the AFUDC calculated rate using the Federal Energy Regulatory Commission (FERC) formula, PSE capitalizes the excess as a deferred asset, crediting other income. The deferred asset is being amortized over the average useful life of PSE’s non-project electric utility plant which is approximately 30 years. Revenue Recognition Operating utility revenue is recognized when the basis of services is rendered, which includes estimated unbilled revenue. Revenue from retail sales is billed based on tariff rates approved by the Washington Commission. PSE's estimate of unbilled revenue is based on a calculation using meter readings from its automated meter reading system. The estimate calculates unbilled usage at the end of each month as the difference between the customer meter readings on the last day of the month and the last customer meter readings billed. The unbilled usage is then priced at published rates for each tariff rate schedule to estimate the unbilled revenues by customer. PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $292.8 million, $268.5 million and $240.8 million for 2022, 2021, and 2020, respectively. The Company reports the collection of such taxes on a gross basis in operation revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income. PSE's electric and natural gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, natural gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. The mechanism mitigates volatility in revenue and gross margin erosion due to weather and energy efficiency. Any differences in revenue are deferred to a regulatory asset for under recovery or regulatory liability for over recovery under alternative revenue recognition standard. Revenue is recognized under this program when deemed collectible within 24 months based on alternative revenue recognition guidance. Decoupled rate increases are effective May 1 of each year subject to a soft rate cap of total revenue for decoupled rate schedules, where rate cap is applied to under-collected revenue and any over-collected revenues are passed back to customers at 100%. Any excess under-recovered revenue above the rate cap will be included in the following year's decoupled rate and the Company will only be able to recognize revenue below the rate cap of total revenue for decoupled rate schedules. For revenue deferrals exceeding the annual rate cap of total revenue for decoupled rate schedules, the Company will assess the excess amount to determine its ability to be collected within 24 months per GAAP rules. The soft rate cap test, which limits the amount of revenues PSE can collect in its annual filings, is 5.0% for natural gas customers and 3.0% for electric customers. The Company will not record any decoupling revenue that is expected to take longer than 24 months to collect following the end of the annual period in which the revenues would have otherwise been recognized. Once determined to be collectible within 24 months, any previously non-recognized amounts will be recognized. Revenues associated with energy costs under the power cost adjustment (PCA) mechanism and purchased gas adjustment (PGA) mechanism are excluded from the decoupling mechanism. Allowance for Credit Losses The Company measures expected credit losses on trade receivables on a collective basis by receivable type, which include electric retail receivables, gas retail receivables, and electric wholesale receivables. The estimate of expected credit losses considers historical credit loss information that is adjusted for current conditions and reasonable and supportable forecasts. The following table presents the activity in the allowance for credit losses for accounts receivable at December 31, 2022, and 2021: Puget Energy and (Dollars in Thousands) Year Ended December 31, Allowance for credit losses: 2022 2021 Beginning balance $ 34,958 20,080 Provision for credit loss expense 1 28,316 27,204 Receivables charged-off (21,312) (12,326) Total ending allowance balance $ 41,962 $ 34,958 1 $7.1 million and $2.8 million of provision were deferred as cost specific to COVID-19 in 2022 and 2021, respectively. Self-Insurance PSE is self-insured for storm damage and certain environmental contamination associated with current operations occurring on PSE-owned property. In addition, PSE is required to meet a deductible for a portion of the risk associated with comprehensive liability, workers’ compensation claims and catastrophic property losses other than those which are storm related. The cumulative annual cost threshold for deferral of storms under the mechanism is $10.0 million. Additionally, costs may only be deferred if the outage meets the Institute of Electrical and Electronics Engineers outage criteria for system average interruption duration index and qualifying costs exceed $0.5 million per qualified storm. Federal Income Taxes For presentation in Puget Energy's and PSE’s separate financial statements, income taxes are allocated to the subsidiaries on the basis of separate company computations of tax, modified by allocating certain consolidated group limitations which are attributed to the separate company. Taxes payable or receivable are settled with Puget Holdings, which is the ultimate taxpayer. Natural Gas Off-System Sales and Capacity Release PSE contracts for firm natural gas supplies and holds firm transportation and storage capacity sufficient to meet the expected peak winter demand for natural gas by its firm customers. Due to the variability in weather, winter peaking consumption of natural gas by most of its customers and other factors, PSE holds contractual rights to natural gas supplies and transportation and storage capacity in excess of its average annual requirements to serve firm customers on its distribution system. For much of the year, there is excess capacity available for third-party natural gas sales, exchanges and capacity releases. PSE sells excess natural gas supplies, enters into natural gas supply exchanges with third parties outside of its distribution area and releases to third parties excess interstate natural gas pipeline capacity and natural gas storage rights on a short-term basis to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. The proceeds from such activities, net of transactional costs, are accounted for as reductions in the cost of purchased natural gas and passed on to customers through the PGA mechanism, with no direct impact on net income. As a result, PSE nets the sales revenue and associated cost of sales for these transactions in purchased natural gas. As part of the Company’s electric operations, PSE purchases natural gas for its gas-fired generation facilities. The projected volume of natural gas for power is relative to the price of natural gas. Based on the market prices for natural gas, PSE may use the natural gas it has already purchased to generate power or PSE may sell the already purchased natural gas. The net proceeds from selling natural gas, previously purchased for power generation, are accounted for in electric operating revenue and are included in the PCA mechanism. Production Tax Credit Production Tax Credits (PTCs) represent federal income tax incentives available to taxpayers that generate energy from qualifying renewable sources during the first ten years of operation. Before the 2017 GRC, the tax savings from these credits were intended to be refunded by PSE to its customers when monetized, used on the income tax return, through its revenue requirement as initially approved by the Washington Commission. As the Company had not generated taxable income with which to monetize the credits, they had not been refunded to customers. Amounts to be refunded have been recorded as a regulatory liability with an offsetting reduction to revenue as it was intended to be refunded through the revenue requirement. A deferred tax asset and reduction to deferred tax expense were also recorded for the regulatory liability. These entries resulted in no net income impact. In connection with the GRC settlement in 2017, the Washington Commission authorized the Company to utilize the tax savings associated with the monetization of the PTCs to fund the following: (i) Colstrip Community Transition Fund, (ii) unrecovered Colstrip plant and (iii) incurred decommissioning and remediation costs for Colstrip. As PTCs will no longer be refunded to customers through the revenue requirement, a non-cash increase to revenue and deferred tax expense will be recorded as the PTCs are monetized. These entries will result in no net income impact. For the tax year ending December 31, 2022, there was no PTC monetized as there were no PTC carryforwards from 2021. For the tax years ending December 31, 2021 and 2020, $45.6 million and $39.8 million of PTCs were monetized through tax filings. Accounting for Derivatives ASC 815, "Derivatives and Hedging" (ASC 815) requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value unless the contracts qualify for an exception. PSE enters into derivative contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts and swaps. Some of PSE’s physical electric supply contracts qualify for the normal purchase normal sale (NPNS) exception to derivative accounting rules. PSE may enter into financial fixed price contracts to economically hedge the variability of certain index-based contracts. Those contracts that do not meet the NPNS exception are marked-to-market to current earnings in the statements of income, subject to deferral under ASC 980, for natural gas related derivatives due to the PGA mechanism. For additional information, see Note 10, "Accounting for Derivative Instruments and Hedging Activities" to the consolidated financial statements included in Item 8 of this report. Fair Value Measurements of Derivatives ASC 820, “Fair Value Measurements and Disclosures” (ASC 820), defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). As permitted under ASC 820, the Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements as it believes that the approach is used by market participants for these types of assets and liabilities. Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company values derivative instruments based on daily quoted prices from an independent external pricing service. When external quoted market prices are not available for derivative contracts, the Company uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves. All derivative instruments are sensitive to market price fluctuations that can occur on a daily basis. For additional information, see Note 11, "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report. Debt-Related Costs Debt premiums, discounts, expenses and amounts received or incurred to settle hedges are amortized over the life of the related debt for the Company. The premiums and costs associated with reacquired debt are deferred and amortized over the life of the related new issuance, in accordance with ratemaking treatment for PSE and presented net of long-term liabilities on the balance sheet. Leases PSE determines if an arrangement is, or contains, a lease at inception of the contract. If the arrangement is, or contains a lease, PSE assesses whether the lease is operating or financing for income statement and balance sheet classification. Operating leases are included in operating lease right-of-use (ROU) assets, operating lease current liabilities, and operating lease liabilities in our consolidated balance sheets. Finance leases are included in utility plant, other current liabilities, and finance lease liabilities in our consolidated balance sheets. ROU assets represent the right to use an underlying asset for the lease term, and consist of the amount of the initial measurement of the lease liability, any lease payments made to the lessor at or before the commencement date, minus any lease incentives received, and any initial direct costs incurred by the lessee. Lease liabilities represent our obligation to make lease payments arising from the lease and are measured at present value of the lease payments not yet paid, discounted using the discount rate for the lease, determined based on PSE's incremental borrowing rate, at commencement. As most of PSE's leases do not provide an implicit interest rate, PSE uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. For fleet, IT and wind farm leases, this rate is applied using a portfolio approach. The lease terms may include options to extend or terminate the lease when it is reasonably certain that PSE will exercise that option. On the statement of income, operating leases are generally accounted for under a straight-line expense model, while finance leases, which were previously referred to as capital leases, are generally accounted for under a financing model. Consistent with the previous lease guidance, however, the standard allows rate-regulated utilities to recognize expense consistent with the timing of recovery in rates. PSE has lease agreements with lease and non-lease components. Non-lease components comprise common area maintenance and utilities, and are accounted for separately from lease components. Variable Interest Entities On April 12, 2017, PSE entered into a Power Purchase Agreement (PPA) with Skookumchuck Wind Energy Project, LLC (Skookumchuck) in which Skookumchuck would develop a wind generation facility and, once completed, sell bundled energy and associated attributes, namely renewable energy credits to PSE over a term of 20 years. Skookumchuck commenced commercial operation in November 2020. PSE has no equity investment in Skookumchuck but is Skookumchuck’s only customer. Based on the terms of the contract, PSE will receive all of the output of the facility, subject to curtailment rights. PSE has concluded that it is not the primary beneficiary of this VIE since it does not control the commercial and operating activities of the facility. Additionally, PSE does not have the obligation to absorb losses or receive benefits. Therefore, PSE will not consolidate the VIE. Purchased energy of $14.6 million was recognized in purchased electricity on the Company's consolidated statements of income for the year ended December 31, 2022 and $1.4 million is included in accounts payable on the Company's consolidated balance sheet for the year ended December 31, 2022. Purchased energy of $19.0 million was recognized in purchased electricity on the Company's consolidated statements of income and $2.7 million included in accounts payable on the Company's consolidated balance sheet for the year ended December 31, 2021. On May 28, 2020, PSE entered into a PPA with Golden Hills Wind Farm, LLC (Golden Hills) pursuant to which Golden Hills would develop a wind generation facility and, once completed, sell bundled energy and associated attributes, namely RECs to PSE over a term of 20 years. On April 29, 2022, Golden Hills commenced commercial operations. PSE has no equity investment in Golden Hills but is Golden Hills’s only customer. Based on the terms of the contract, PSE will receive all of the output of the facility, subject to curtailment rights. PSE has concluded that Golden Hills is a VIE and that PSE is not the primary beneficiary of this VIE since it does not control the commercial and operating activities of the facility. Additionally, PSE does not have the obligation to absorb losses or receive benefits. Therefore, PSE will not consolidate the VIE. Purchased energy of $18.3 million was recognized in purchased electricity on the Company's consolidated statements of income for the year ended December 31, 2022. There was no balance in accounts payable on the Company's balance sheet as of December 31, 2022. On February 3, 2021, PSE entered into a PPA with Clearwater Wind Project, LLC (Clearwater) in which Clearwater will develop a wind generation facility on a site located in Rosebud, Custer and Garfield counties, Montana; and, once completed, sell energy and associated attributes to PSE over a term of 25 years. On November 8th, 2022, Clearwater commenced commercial operations. PSE has no equity investment in Clearwater but is Clearwater’s only customer. Based on the terms of the contract, PSE will receive all of the output of the facility, subject to curtailment rights. PSE has concluded that Clearwater is a VIE and that PSE is not the primary beneficiary of this VIE since it does not control the commercial and operating activities of the facility. Additionally, PSE does not have the obligation to absorb losses or receive benefits. Therefore, PSE will not consolidate the VIE. Purchased energy of $5.7 million was recognized in purchased electricity on the Company's consolidated statements of income for the year ended December 31, 2022. Additionally, $2.5 million was included in accounts payable on the Company's balance sheet as of December 31, 2022. |
New Accounting Pronouncements
New Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Standards Update and Change in Accounting Principle [Abstract] | |
New Accounting Pronouncements | New Accounting Pronouncements Recently Adopted Accounting Guidance Reference Rate Reform In March 2020, the FASB issued ASU 2020-04, "Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting ”. ASU 2020-04 provides temporary optional expedients and exceptions to the current guidance on contract modifications to ease the financial reporting burdens related to the expected market transition from London Interbank Offered Rate (LIBOR) and other interbank offered rates to alternative reference rates. In December 2022, the FASB issued ASU 2022-06, "Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848" . ASU 2022-06 postpones the sunset date of Topic 848 from December 31, 2022 to December 31, 2024. The Company has promissory notes that reference LIBOR. As of December 31, 2022, the Company has not utilized any of the expedients discussed within this ASU; however, it continues to assess other agreements to determine if LIBOR is included and if the expedients would be utilized through the allowed period of December 2024. Retirement Benefits In 2018, the FASB issued ASU 2018-14, " Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans" . This update modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans through added, removed and clarified requirements of relevant disclosures. The amendments in this update are effective for fiscal years ending after December 15, 2020, for public business entities and for fiscal years ending after December 15, 2021, for all other entities. Early adoption is permitted for all entities. The Company adopted this standard for the year ended December 31, 2020. Refer to Note 13, "Retirement Benefits" to the consolidated financial statements. Fair Value Measurement In 2018, the FASB issued ASU 2018-13, "Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement" . The amendments in this update modify the disclosure requirements on fair value measurements in Topic 820, Fair Value Measurement, based on the concepts in the Concepts Statement, including the consideration of costs and benefits. The amendments are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The Company adopted this update as of January 1, 2020, and it impacted Note 11, "Fair Value Measurements". As the amendment contemplates changes in disclosures only, it did not have a material impact on the Company's results of operations, cash flows, or consolidated balance sheets. |
Revenue (Notes)
Revenue (Notes) | 12 Months Ended |
Dec. 31, 2022 | |
Revenue from Contract with Customer [Abstract] | |
Revenue from Contract with Customer | Revenue The following tables present disaggregated revenue from contracts with customers, and other revenue by major source for the years ended December 31, 2022, December 31, 2021, and December 31, 2020: Puget Energy and (Dollars in Thousands) Year Ended December 31, 2022 Revenue from contracts with customers: Electric Natural Gas Other 1 Total Retail Residential $ 1,381,858 $ 808,376 $ — $ 2,190,234 Commercial 981,170 352,243 — 1,333,413 Industrial 116,712 25,096 — 141,808 Other 18,759 — — 18,759 Wholesale 319,380 — — 319,380 Transmission and transportation 47,027 20,332 — 67,359 Miscellaneous 13,065 718 50,069 63,852 Total revenue from contracts with customers $ 2,877,971 $ 1,206,765 $ 50,069 $ 4,134,805 Total other revenue 2 83,486 2,871 — 86,357 Total operating revenue $ 2,961,457 $ 1,209,636 $ 50,069 $ 4,221,162 _____________ 1 Other includes $5.0 million of Puget LNG revenues recorded at Puget Energy. 2 Total other revenue includes revenues from derivatives and alternative revenue programs that are not considered revenues from contracts with customers. Puget Energy and (Dollars in Thousands) Year Ended December 31, 2021 Revenue from contracts with customers: Electric Natural Gas Other Total Retail Residential $ 1,318,326 $ 722,003 $ — $ 2,040,329 Commercial 902,928 292,275 — 1,195,203 Industrial 108,267 21,741 — 130,008 Other 18,834 392 — 19,226 Wholesale 161,152 — — 161,152 Transmission and transportation 43,753 20,030 — 63,783 Miscellaneous 47,948 9,863 66,620 124,431 Total revenue from contracts with customers $ 2,601,208 $ 1,066,304 $ 66,620 $ 3,734,132 Total other revenue 1 70,415 1,114 — 71,529 Total operating revenue $ 2,671,623 $ 1,067,418 $ 66,620 $ 3,805,661 _____________ 1 Total other revenue includes revenues from derivatives, PTC deferral revenue and alternative revenue programs that are not considered revenues from contracts with customers. Puget Energy and (Dollars in Thousands) Year Ended December 31, 2020 Revenue from contracts with customers: Electric Natural Gas Other Total Retail Residential $ 1,186,012 $ 662,503 $ — $ 1,848,515 Commercial 791,898 251,740 — 1,043,638 Industrial 101,567 18,592 — 120,159 Other 26,644 5,227 — 31,871 Wholesale 66,345 — — 66,345 Transmission and transportation 38,073 19,555 — 57,628 Miscellaneous 25,007 3,107 26,121 54,235 Total revenue from contracts with customers $ 2,235,546 $ 960,724 $ 26,121 $ 3,222,391 Total other revenue 1 83,870 20,189 — 104,059 Total operating revenue $ 2,319,416 $ 980,913 $ 26,121 $ 3,326,450 _____________ 1 Total other revenue includes revenues from derivatives, PTC deferral revenue and alternative revenue programs that are not considered revenues from contracts with customers. Revenue at PSE is recognized when performance obligations under the terms of a contract or tariff with our customers are satisfied. Performance obligations are satisfied generally through performance of PSE's obligation over time or with transfer of control of electric power, natural gas, and other revenue from contracts with customers. Revenue is measured as the amount of consideration expected to be received in exchange for transferring goods and services. Electric and Natural Gas Retail Revenue Electric and natural gas retail revenue consists of tariff-based sales of electricity and natural gas to PSE's customers. For tariff contracts, PSE has elected the portfolio approach practical expedient model to apply the revenue from contracts with customers to groups of contracts. The Company determined that the portfolio approach will not differ from considering each contract or performance obligation separately. Electric and natural gas tariff contracts include the performance obligation of standing ready to perform electric and natural gas services. The electricity and natural gas the customer chooses to consume is considered an option and is recognized over time using the output method when the customer simultaneously consumes the electricity or natural gas. PSE has elected the right to invoice practical expedient for unbilled retail revenue. The obligation of standing ready to perform electric service and the consumption of electricity and natural gas at market value implies a right to consideration for performance completed to date. The Company believes that tariff prices approved by the Washington Commission represent stand-alone selling prices for the performance obligations under ASC 606. PSE collects Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes and presents the taxes on a gross basis, as PSE is the taxpayer for those excise and municipal taxes. Other Revenue from Contracts with Customers Other revenue from contracts with customers is primarily comprised of electric transmission, natural gas transportation, biogas, and wholesale revenue sold on an intra-month basis. Electric Transmission and Natural Gas Transportation Transmission and transportation tariff contracts include the performance obligation to transmit and transport electricity or natural gas. Transfer of control and recognition of revenue occurs over time as the customer simultaneously receives the transmission and transportation services. Measurement of satisfaction of this performance obligation is determined using the output method. Similar to retail revenue, the Company utilizes the right to invoice practical expedient as PSE’s right to consideration is tied directly to the value of power and natural gas transmitted and transported each month. The price is based on the tariff rates that were approved by the Washington Commission or the FERC and, therefore, corresponds directly to the value to the customer for performance completed to date. Biogas Biogas is a renewable natural gas fuel that PSE purchases and sells along with the renewable green attributes derived from the renewable natural gas. Biogas contracts include the performance obligations of biogas and renewable credit delivery upon PSE receiving produced biogas from its supplier. Transfer of control and recognition of revenue occurs at a point in time as biogas is considered a storable commodity and may not be consumed as it is delivered. Wholesale Wholesale revenue at PSE includes sales of electric power and non-core natural gas to other utilities or marketers. Wholesale revenue contracts include the performance obligation of physical electric power or natural gas. There are typically no added fixed or variable amounts on top of the established rate for power or natural gas and contracts always have a stated, fixed quantity of power or natural gas delivered. Transfer of control and recognition of revenue occurs at a point in time when the customer takes physical possession of electric power or natural gas. Non-core gas consists of natural gas supply in excess of natural gas used for generation, sold to third parties to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. PSE reports non-core gas sold net of costs as PSE does not take control of the natural gas but is merely an agent within the market that connects a seller to a purchaser. PWI Land Sale On August 13, 2021, Puget Western, Inc. (PWI) a wholly-owned subsidiary of PSE sold a parcel of land that resulted in $23.2 million of other revenue from contracts with customers. PWI purchases, develops, and sells land holdings throughout PSE’s service territory; thus, the sale was reported as non-utility revenue of $23.2 million and non-utility expense of $12.9 million. Other Revenue In accordance with ASC 606, PSE separately presents revenue not collected from contracts with customers that falls under other accounting guidance. Transaction Price Allocated to Remaining Performance Obligations In December 2020, PLNG entered into a contract with one customer where PLNG is selling LNG over a 10-year delivery period beginning no later than 2024. The contract requires the customer to purchase a minimum annual quantity even if the customer does not take delivery. The price of the LNG includes a fixed charge, a fuel charge that includes both a market index and fixed margin component and other variable consideration. The fixed transaction price is allocated to the remaining performance obligations which is determined by the fixed charge components multiplied by the outstanding minimum annual quantity. Based on management’s best estimate of commencement, the Company expects to recognize this revenue over the following time periods: Puget Energy (Dollars in Thousands) 2024 2025 2026 2027 2028 Thereafter Total Remaining Performance Obligations $ 15,359 19,710 19,454 19,454 19,454 102,135 $ 195,566 |
Regulation and Rates
Regulation and Rates | 12 Months Ended |
Dec. 31, 2022 | |
Regulated Operations [Abstract] | |
Regulation and Rates | Regulation and Rates Regulatory Assets and Liabilities Regulatory accounting allows PSE to defer certain costs that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. It similarly requires deferral of revenues or gains that are expected to be returned to customers in the future. The net regulatory assets and liabilities at December 31, 2022, and 2021, are included the following tables: Puget Sound Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2022 2021 Environmental remediation (a) $ 141,893 $ 127,977 Storm damage costs electric 3 to 5 years 127,524 127,789 PCA mechanism N/A 112,207 79,546 Chelan PUD contract initiation 8.8 years 62,611 69,699 Deferred Washington Commission AFUDC 30 years 61,463 62,244 Baker Dam licensing operating and maintenance costs (b) 55,049 54,525 Get to zero depreciation expense deferral (c) 1 to 4 years 49,605 50,220 Lower Snake River 14.4 years 48,536 53,757 Decoupling deferrals and interest (d) Less than 2 years 36,773 79,125 Unamortized loss on reacquired debt 1 to 45 years 33,732 35,805 Advanced metering infrastructure 3 years 30,431 23,037 Washington Commission LNG N/A 25,188 1,764 PGA receivable 2 years — 57,935 Generation plant major maintenance, excluding Colstrip 3 to 7 years 20,374 12,094 Low Income Program Costs N/A 17,370 21,755 Property tax tracker Less than 2 years 12,398 25,896 Energy conservation costs (a) 10,296 3,573 Washington Commission electric vehicle (c) 4 years 7,796 6,109 Regulatory filing fee deferral N/A 7,559 — Snoqualmie licensing operating and maintenance costs (b) 7,445 7,446 Washington Commission COVID-19 N/A 7,051 3,657 Water heater rental property loss N/A 5,725 5,725 Mint Farm ownership and operating costs 2.3 years 4,317 6,318 Colstrip major maintenance (c) 3 years 4,035 4,035 Various other regulatory assets (a) 7,060 32,508 Total PSE regulatory assets $ 896,438 $ 952,539 Deferred income taxes (e) N/A (811,724) (866,541) Cost of removal (f) (639,320) (563,129) PGA unrealized gain N/A (287,725) (60,728) Repurposed production tax credits N/A (133,855) (134,270) Decoupling liability Less than 2 years (63,206) (36,506) Green direct N/A (11,837) (13,194) Refund on counterparty settlement 1 year (4,353) — PGA liability 2 years (3,536) — Various other regulatory liabilities (a) (5,583) (35,093) Total PSE regulatory liabilities (1,961,139) (1,709,461) PSE net regulatory assets (liabilities) $ (1,064,701) $ (756,922) __________________ (a) Amortization periods vary depending on timing of underlying transactions. (b) The FERC license requires PSE to incur various O&M expenses over the life of the 40 year and 50 year license for Snoqualmie and Baker, respectively. The regulatory asset represents the net present value of future expenditures and will be offset by actual costs incurred. (c) Amortization period approved in 2022 GRC, beginning January 2023. (d) Decoupling deferrals and interest includes a 24 month GAAP reserve of zero and $3.0 million for December 31, 2022 and 2021, respectively. (e) For additional information, see Note 14,"Income Taxes" to the consolidated financial statements included in Item 8 of this report. (f) The balance is dependent upon the cost of removal of underlying assets and the life of utility plant. . Puget Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2022 2021 Total PSE regulatory assets (a) $ 896,438 $ 952,539 Puget Energy acquisition adjustments: Regulatory assets related to power contracts 3 to 30 years 7,904 9,689 Total Puget Energy regulatory assets 904,342 962,228 Total PSE regulatory liabilities (a) (1,961,139) (1,709,461) Puget Energy acquisition adjustments: Deferred income taxes 563 565 Regulatory liabilities related to power contracts 3 to 30 years (63,660) (80,934) Various other regulatory liabilities Varies (1,264) (1,264) Total Puget Energy regulatory liabilities (2,025,500) (1,791,094) Puget Energy net regulatory asset (liabilities) $ (1,121,158) $ (828,866) ____________________ (a) Puget Energy’s regulatory assets and liabilities include purchase accounting adjustments under ASC 805. If the Company determines that it no longer meets the criteria for continued application of ASC 980, the Company would be required to write-off its regulatory assets and liabilities related to those operations not meeting ASC 980 requirements. Discontinuation of ASC 980 could have a material impact on the Company's financial statements. In accordance with guidance provided by ASC 410, “Asset Retirement and Environmental Obligations (ARO),” PSE reclassified from accumulated depreciation to a regulatory liability $639.3 million and $563.1 million in 2022 and 2021, respectively, for the cost of removal of utility plant. These amounts are collected from PSE’s customers through depreciation rates. General Rate Case Filing PSE filed a general rate case (GRC) which includes a three-year multiyear rate plan with the Washington Commission on January 31, 2022, requesting an overall increase in electric and natural gas rates of 13.6% and 13.0% respectively in 2023; 2.5% and 2.3%, respectively in 2024; and 1.2% and 1.8%, respectively, in 2025. PSE requested a return on equity of 9.9% in all three rate years. PSE requested an overall rate of return of 7.39% in 2023; 7.44% in 2024; and 7.49% in 2025. The filing requests recovery of forecasted plant additions through 2022 as required by Revised Code of Washington (RCW) 80.28.425 as well as forecasted plant additions through 2025, the final year of the multiyear rate plan. On January 6, 2023, the Washington Commission approved PSE’s natural gas rates in its compliance filing with an overall increase of $70.8 million or 6.4% in 2023 and $19.5 million or 1.65% in 2024, with an effective date of January 7, 2023. On January 10, 2023, the Washington Commission approved PSE’s electric rates in its compliance filing with an overall increase of $247.0 million or 10.75% in 2023 and $33.1 million or 1.33% in 2024 with an effective date of January 11, 2023. PSE filed a GRC with the Washington Commission on June 20, 2019, requesting an overall increase in electric and natural gas rates of 6.9% and 7.9% respectively. On July 8, 2020, the Washington Commission issued its order on PSE’s 2019 GRC. The ruling provided for a weighted cost of capital of 7.39% or 6.8% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.4%. The order also resulted in a combined net increase to electric of $29.5 million, or 1.6%, and to natural gas of $36.5 million, or 4.0%. However, the Washington Commission extended the amortization of certain regulatory assets, PSE’s electric decoupling deferral, and PSE’s PGA deferral to mitigate the impact of the rate increase in response to the economic uncertainty created by the COVID-19 pandemic. This reduced the electric revenue increase to approximately $0.9 million, or 0.1% and the natural gas increase to $1.3 million, or 0.2% and became effective October 15, 2020 and October 1, 2020, respectively. In July 2021, PSE received a Private Letter Ruling (PLR) from the IRS which concluded that in the 2019 GRC the Washington Commission’s methodology for reversing plant-related excess deferred income taxes was an impermissible methodology under the IRS normalization and consistency rules. The PLR required adjustments to PSE's rates to bring PSE back into compliance with IRS rules. In September 2021, the Washington Commission amended its order in accordance with the PLR. The annualized overall rate impact was an increase of $15.8 million, or 0.7%, for electric and $3.1 million, or 0.3%, for natural gas for a total of $18.9 million with rates effective October 1, 2021. This led to a combined annualized net increase to electric rates of $77.1 million, or 3.7%, an increase of $17.5 million above the $59.6 million granted in the revised final order. The order also led to a combined annualized net increase to natural gas rates of $45.3 million, or 5.9%, an increase of $2.4 million above the $42.9 million granted in the revised final order. The Washington Commission maintained adjustments that mitigated the impacts of the rate increases in response to the economic instability created by the COVID-19 pandemic, which reduced the electric revenue increase to approximately $48.3 million, or 2.3%, and the natural gas increase to $4.9 million, or 0.6%. Power Cost Only Rate Case On December 9, 2020, PSE filed its 2020 power cost only rate case (PCORC). The filing proposed an increase of $78.5 million (or an average of approximately 3.7%) in the Company's overall power supply costs with an anticipated effective date in June 2021. On February 2, 2021, PSE supplemented the PCORC to update its power costs, leading to a requested increase from $78.5 million to $88.0 million (or an average of approximately 4.1%). On March 2, 2021, several of the parties to the PCORC reached a multiparty settlement in principle, which was unopposed. The settlement resulted in an estimated revenue increase of $65.3 million or 3.1%. On June 1, 2021, the Washington Commission issued its Final Order approving and adopting the settlement and authorizing and requiring a power cost update through a compliance filing. On June 17, 2021, PSE filed a compliance filing with the Washington Commission with a revenue increase of $70.9 million or 3.3% due to the update on power costs with rates effective July 1, 2021. Per the 2022 GRC Final Order in Docket No. UE-220066, PCORC rates were set to zero as of January 11, 2023 and PSE agreed not to file a PCORC during 2023 and 2024, the two-year rate plan agreed to in the GRC settlement. Revenue Decoupling Adjustment Mechanism On July 8, 2020, the Washington Commission issued the final order in Dockets No. UE-190529 and UG-190530, which instructed PSE to extend the collection of amortization balances for electric decoupling delivery and fixed power cost sections originally filed through the annual May 2020 decoupling filing. The extension requires PSE to move amortization balances for electric decoupling as of August 31, 2020 to be collected from customers for a two-year period, instead of the originally approved one-year period. Additionally, through approving the electric cost of service, the final order approved the re-allocation of decoupling balances from Schedule 40 to the remaining electric decoupling groups. On December 23, 2020, the Washington Commission approved PSE’s filing to update Schedule 142 decoupling amortization rates, with an effective date of January 1, 2021, by zeroing out rates still effective past October 15, 2020 on tariff sheet Schedule 142-H, which was replaced by rates on tariff sheet Schedule 142-I effective October 15, 2020. PSE included a true up of the over-collection amounts for the period of October 15, 2020 through December 31, 2020 in PSE’s annual May 2021 decoupling filing. On June 1, 2021, the Washington Commission approved the multi-party settlement agreement which was filed within PSE’s PCORC filing. As part of this settlement agreement, the electric annual fixed power cost allowed revenue was updated to reflect changes in the approved revenue requirement. The changes took effect on July 1, 2021. On September 28, 2021, the Washington Commission approved 2019 GRC filing updated to PLR changes. As part of this filing, the annual electric and gas delivery cost allowed revenue was updated to reflect changes in the approved revenue requirement. The changes took effect on October 1, 2021. On January 6, 2023, the Washington Commission approved the natural gas 2022 GRC filing. As part of this filing the annual gas delivery allowed revenue was updated to reflect changes in the approved revenue requirement. Additionally, the Commission approved the removal of the earnings test from the decoupling mechanism in accordance with RCW 80.28.425(6). The changes took effect on January 7, 2023. On January 10, 2023, the Washington Commission approved the electric 2022 GRC filing. As part of this filing the annual electric delivery and fixed power cost allowed revenue was updated to reflect changes in the approved revenue requirement. Additionally, the Commission approved the removal of the earnings test from the decoupling mechanism in accordance with RCW 80.28.425(6). The changes took effect on January 11, 2023. On December 31, 2022, PSE performed an analysis to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980. If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and regulatory asset balance. Once the reserve is probable of collection within 24 months from the end of the annual period, the reserve can be recognized as decoupling revenue. The analysis indicated that electric and natural gas deferred revenue will be collected within 24 months of the annual period; therefore no reserve adjustment was booked to 2022 electric and natural gas decoupling revenue. This compares to $3.0 million of electric deferred revenue not being collected within 24 months of the annual period in 2021; therefore, a reserve adjustment was booked to 2021 electric decoupling revenue. Natural gas deferred revenue would be collected within 24 months of the annual period; therefore no reserve adjustment was booked to 2021 natural gas decoupling revenue. Power Cost Adjustment Mechanism PSE currently has a PCA mechanism that provides for the deferral of power costs that vary from the “power cost baseline” level of power costs. The “power cost baseline” levels are set, in part, based on normalized assumptions about weather and hydroelectric conditions. Excess power costs or savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism and will trigger a surcharge or refund when the cumulative deferral trigger is reached. Effective January 1, 2017, the following graduated scale is used in the PCA mechanism: Company’s Share Customers' Share Annual Power Cost Variability Over Under Over Under Over or Under Collected by up to $17 million 100 % 100 % — % — % Over or Under Collected by between $17 million - $40 million 35 50 65 50 Over or Under Collected beyond $40 + million 10 10 90 90 For the year ended December 31, 2022, in its PCA mechanism, PSE under recovered its allowable costs by $110.1 million of which $74.6 million was apportioned to customers and $1.5 million of interest was accrued on the deferred customer balance. This compares to an under recovery of allowable costs of $68.0 million, for the year ended December 31, 2021, of which $36.7 million was apportioned to customers and accrued $1.7 million of interest on the total deferred customer balance. Power Cost Adjustment Clause On July 8, 2020, the Washington Commission issued the final order in Dockets No. UE-190529 and UG-190530, which instructed PSE to remove Schedule 95 collection on decoupling allowed rates for Special Contracts, which are included in allowed rates under the Decoupling Schedule 142 effective October 15, 2020. PSE exceeded the $20.0 million cumulative deferral balance in its PCA mechanism in 2020. The surcharging of deferrals can be triggered by the Company when the balance in the deferral account is a credit of $20.0 million or more. During 2020, actual power costs were higher than baseline power costs; thereby, creating an under-recovery of $76.1 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $32.1 million of the under-recovered amount, and customers were responsible for the remaining $44.0 million, or $46.0 million including interest. PSE filed to recover the deferred balance in Docket No. UE-210300, and the Washington Commission allowed the recovery effective December 1, 2021. Additionally, PSE exceeded the $20.0 million cumulative deferral balance in its PCA mechanism in 2021. During 2021, actual power costs were higher than baseline power costs, thereby creating an under-recovery of $68.0 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $31.3 million of the under-recovered amount, and customers were responsible for the remaining $36.7 million, or $38.4 million including interest. On October 27, 2022, the Washington Commission approved PSE's 2021 PCA report that proposes to recover the deferred balance for 2021 PCA period by keeping the current rates and allowing recovery from January 1, 2023 through November 30, 2023. Purchased Gas Adjustment Mechanism On October 28, 2021, the Washington Commission approved PSE's request for PGA rates in Docket No. UG-210721, effective November 1, 2021. As part of that filing, PSE requested an annual revenue increase of $59.1 million; where PGA rates, under Schedule 101, increase annual revenue by $80.6 million, and the tracker rates under Schedule 106, decrease annual revenue by $21.5 million. Those annual 2021 PGA rate increases were set in addition to continuing the collection on the remaining balance of $69.4 million under Supplemental Schedule 106B, which were set, in effect, through September 30, 2023 per the 2019 GRC. On October 27, 2022, the Washington Commission approved PSE's request for PGA rates in Docket No. UG-220715, effective November 1, 2022. As part of that filing, PSE requested an annual revenue increase of $155.3 million; where PGA rates, under Schedule 101, increase annual revenue by $142.1 million, and the tracker rates under Schedule 106, increase annual revenue by $13.2 million. On November 15, 2022, the FERC approved a settlement of a counterparty, FERC Docket No. RP17-346. Under the terms, PSE was allocated $24.2 million related to PSE natural gas services which was recorded on December 31, 2022 and included below. The 2022 GRC order requires PSE to amortize the refund in 2023 as a credit against natural gas costs and therefore pass back the refund to customers through the PGA mechanism. The following table presents the PGA mechanism balances and activity at December 31, 2022 and December 31, 2021: Puget Energy and (Dollars in Thousands) At December 31, At December 31, PGA receivable balance and activity 2022 2021 PGA receivable beginning balance $ 57,935 $ 87,655 Actual natural gas costs 457,950 364,775 Allowed PGA recovery (496,879) (396,236) Interest 1,674 1,741 Refund from counterparty settlement (24,216) — PGA (liability)/receivable ending balance $ (3,536) $ 57,935 Get to Zero Depreciation Deferral On April 10, 2019, PSE filed an accounting petition with the Washington Commission, requesting authorization to defer depreciation expense associated with Get To Zero (GTZ) projects that were placed in service after June 30, 2018. The GTZ project consists of a number of short-lived technology upgrades. The depreciation expense associated with the GTZ projects with lives of 10 years or less that were placed in service after June 30, 2018, were deferred beginning May 1 per the petition request. For the year ended December 31, 2022 and December 31, 2021, PSE deferred $11.8 million and $6.6 million of depreciation expense for GTZ, respectively. In addition to the deferral of depreciation expense, PSE had also requested to defer carrying charges on the GTZ deferral, to be calculated utilizing the FERC quarterly rate of return. The 2022 GRC final order authorized recovery of all remaining GTZ depreciation and carrying charge balances as of December 2022. Finally, all GTZ deferrals ended as of December 2022. Crisis Affected Customer Assistance Program On April 6, 2020, PSE filed with the Washington Commission revisions to its currently effective electric and natural gas service tariffs. The purpose of this filing was to incorporate into PSE’s low-income tariff a new temporary bill assistance program, Crisis Affected Customer Assistance Program (CACAP-1) (Dockets No. UE-200331 and UG-200332), to mitigate the economic impact of the COVID-19 pandemic on PSE’s customers. CACAP-1 allowed PSE customers facing financial hardship due to COVID-19 to receive up to $1,000 in bill assistance. The program made available $11.0 million in unspent low income funds from prior years, therefore resulting in no rate impact, and supplemented other forms of financial assistance. CACAP-1 ran from April 13, 2020, to September 30, 2020. On March 28, 2021, the Washington Commission approved PSE’s CACAP-2 (Dockets No. UE-210137 and UG-210138). With a program budget of $20.0 million for electric customers and $7.7 million for natural gas customers, CACAP-2, which ran from April 12, 2021, to March 29, 2022, provided up to $2,500 per year in bill assistance for arrearages for each qualifying low-income household. On October 15, 2021, PSE submitted for the Washington Commission’s review and approval a Supplemental CACAP (Dockets No UE-210792 and UG-210793) filing to continue assistance for PSE customers facing financial hardship due to COVID-19. The Washington Commission approved the Supplemental CACAP program to be effective on November 15, 2021. The Supplemental CACAP utilized carry-over funds not expended in any prior years under PSE’s Schedule 129 Home Energy Lifeline Program (HELP), with a combined total budget of $34.5 million for both electric and natural gas residential customers (capped at $23.7 million and $10.8 million, respectively). Supplemental CACAP benefits offered to cover a qualifying residential customer’s past due balance, up to $2,500. PSE applied the Supplemental CACAP benefits automatically, with an opt-out option, in December 2021. Storm Loss Deferral Mechanism The Washington Commission has defined deferrable weather-related events and provided that costs in excess of the annual cost threshold may be deferred for qualifying damage costs that meet the modified Institute of Electrical and Electronics Engineers outage criteria for system average interruption duration index. For the year ended December 31, 2022, PSE incurred $32.2 million in weather-related electric transmission and distribution system restoration costs, of which the Company deferred $21.4 million and $0.2 million as regulatory assets related to storms that occurred in 2022 and 2021, respectively. This compares to $51.4 million incurred in weather-related electric transmission and distribution system restoration costs for the year ended December 31, 2021, of which the Company deferred $40.9 million and $0.2 million as regulatory assets related to storms that occurred in 2021 and 2020, respectively. Under the 2017 GRC Order, the storm loss deferral mechanism approved the following: (i) the cumulative annual cost threshold for deferral of storms under the mechanism at $10.0 million; and (ii) qualifying events where the total qualifying cost is less than $0.5 million will not qualify for deferral and these costs will also not count toward the $10.0 million annual cost threshold. Environmental Remediation The Company is subject to environmental laws and regulations by the federal, state and local authorities and is required to undertake certain environmental investigative and remedial efforts as a result of these laws and regulations. The Company has been named by the Environmental Protection Agency (EPA), the Washington State Department of Ecology and/or other third parties as potentially responsible at several contaminated sites and former manufactured gas plant sites. In accordance with the guidance of ASC 450, “Contingencies,” the Company reviews its estimated future obligations and will record adjustments, if any, on a quarterly basis. Management believes it is probable and reasonably estimable that the impact of the potential outcomes of disputes with certain property owners and other potentially responsible parties will result in environmental remediation costs of $84.4 million for natural gas and $48.3 million for electric. The Company believes a significant portion of its past and future environmental remediation costs are recoverable from insurance companies, from third parties or from customers under a Washington Commission order. The Company is also subject to cost-sharing agreements with third parties regarding environmental remediation projects in Seattle, Tacoma, Everett, and Bellingham, Washington. |
Utility Plant | Utility Plant The following table presents electric, natural gas and common utility plant classified by account: Puget Energy Puget Sound Energy Utility Plant Estimated Useful Life 1 December 31, December 31, (Dollars in Thousands) (Years) 2022 2021 2022 2021 Distribution plant 7-65 $ 7,886,665 $ 7,488,629 $ 9,406,017 $ 9,026,042 Production plant 3-90 3,131,578 3,147,987 3,780,910 3,815,599 Transmission plant 44-75 1,576,916 1,556,666 1,683,737 1,663,559 General plant 5-75 735,298 746,758 760,094 773,662 Intangible plant (including capitalized software) 2 3-50 755,430 797,691 745,973 788,240 Plant acquisition adjustment N/A 242,826 242,826 282,792 282,792 Underground storage 25-60 45,305 43,391 58,716 56,820 Liquefied natural gas storage 25-50 12,628 12,628 14,498 14,498 Plant held for future use N/A 46,079 46,020 46,232 46,172 Recoverable Cushion Gas N/A 8,784 8,655 8,784 8,655 Plant not classified N/A 723,383 316,933 723,383 316,933 Finance leases, net of accumulated amortization 3 N/A 99,967 105,020 99,967 105,020 Less: accumulated provision for depreciation (4,341,789) (4,031,458) (6,688,033) (6,416,246) Subtotal $ 10,923,070 $ 10,481,746 $ 10,923,070 $ 10,481,746 Construction work in progress 861,801 870,204 861,801 870,204 Net utility plant $ 11,784,871 $ 11,351,950 $ 11,784,871 $ 11,351,950 _______________________ 1. Estimated Useful Life years have been approved in the 2022 GRC. 2. Intangible assets include capitalized software and franchise agreements with useful lives ranging between 3-10 years and 10-50 years, respectively. 3. At December 31, 2022, and 2021, accumulated amortization of finance leases at Puget Energy and PSE was $7.3 million and $2.6 million, respectively. Jointly owned generating plant service costs are included in utility plant service cost at the Company's ownership share. The Company provides financing for its ownership interest in the jointly owned utility plants. The following tables indicate the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2022. These amounts are also included in the Utility Plant table above, with the exception of Puget Energy's portion of the Tacoma LNG facility, which is reported in the Puget Energy "Other property and investments" financial statement line item. The Company's share of fuel costs and operating expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income. Puget Energy Jointly Owned Generating Plants Energy Source (Fuel) Company’s Ownership Share Plant in Service at Cost Construction Work in Progress Accumulated Depreciation Colstrip Units 3 & 4 Coal 25.00% $ 321,767 $ — $ (176,847) Frederickson 1 Natural Gas 49.85 63,348 — (21,894) Jackson Prairie Natural Gas 33.34 44,708 837 (12,178) Tacoma LNG Natural Gas various 494,795 2,936 (10,922) Puget Sound Energy Jointly Owned Generating Plants Energy Source (Fuel) Company’s Ownership Share Plant in Service at Cost Construction Work in Progress Accumulated Depreciation Colstrip Units 3 & 4 Coal 25.00 % $ 579,019 $ — $ (434,099) Frederickson 1 Natural Gas 49.85 69,415 — (27,962) Jackson Prairie Natural Gas 33.34 58,716 837 (26,186) Tacoma LNG Natural Gas various 245,690 503 (5,052) In June 2019, Talen, the plant operator of Colstrip Units 1 and 2, announced a plan to shut down as of December 31, 2019. The Company retired Colstrip 1&2 from Utility Plant and transferred the unrecovered plant amount of $126.5 million to regulatory assets, offset by depreciation as included in base rates until the 2019 GRC became effective in October 2020. Consistent with the GRC settlement in 2017, monetization of the PTCs will fund the following: (i) Colstrip Community Transition Fund, (ii) unrecovered Colstrip plant and (iii) incurred decommissioning and remediation costs for Colstrip. At December 31, 2022, and December 31, 2021, the unrecovered plant for Colstrip 1&2 was fully offset with PTCs. On September 2, 2022, PSE and Talen Energy reached an agreement to transfer PSE's ownership interest in Colstrip Units 3 and 4 to Talen Energy on December 31, 2025. Management evaluated Colstrip Units 3 and 4 and determined that the applicable held for sale accounting criteria were not met as of December 31, 2022. As such, Colstrip Units 3 and 4 are classified as Electric Utility Plant on the Company's balance sheet as of December 31, 2022. Asset Retirement Obligation The Company has recorded liabilities for steam generation sites, combustion turbine generation sites, wind generation sites, distribution and transmission poles, natural gas mains, liquefied natural gas storage sites, and leased facilities where disposal is governed by ASC 410-20 “Asset Retirement and Environmental Obligations" (ARO). The Company records its ARO liabilities for its electric transmission and distribution poles as well as gas distribution mains aligned with its underlying asset data with future estimates of retirements. For the twelve months ended December 31, 2022, the Company reviewed the estimated remediation costs at Colstrip and determined no change was warranted for the Colstrip ARO liability for Colstrip Units 1 and 2 and Colstrip Units 3 and 4. For the twelve months ended December 31, 2021, the Company reviewed the estimated remediation costs at Colstrip and decreased the Colstrip ARO liability by $1.5 million for Colstrip Units 1 and 2, and $3.1 million for Colstrip Units 3 and 4. The 2021 decrease to Colstrip 1 and 2 is primarily due to remediation plans approved by the Montana Department of Environmental Quality under a 2012 settlement between the plant operator and the state for the remaining sites at Colstrip. The plant operator previously contested the approved plan for Colstrip Units 1 and 2 under the defined process in the settlement with the state and reached a settlement agreement regarding the ability to still present another option under the settlement terms and conditions. The Company had previously recorded these incremental costs in 2020 for remediation work on the older ponds under ASC 410-20 “Asset Retirement and Environmental Obligations" and ASC 410-30 “Environmental Remediation". For the twelve months ended December 31, 2022 and 2021, the Company also recorded relief of ARO and environmental remediation liability of $6.9 million and $13.1 million, respectively. In addition, the Company recorded Tacoma LNG facility ARO liability of $3.9 million and $3.8 million for PSE and $3.8 million and $3.7 million for Puget LNG as of December 31, 2022 and December 31, 2021, respectively. The 2022 and 2021 increases to the Tacoma LNG facility ARO liabilities are primarily due to continued construction of the plant. In 2022, the ARO liability associated with the Tacoma LNG facility was fully recorded as construction was essentially complete and commissioning activities are on-going. Puget Energy and Puget Sound Energy December 31, (Dollars in Thousands) 2022 2021 Asset retirement obligation at beginning of the period $ 209,041 $ 216,163 Relief of liability (6,867) (13,146) Revisions in estimated cash flows 1,519 (46) Accretion expense 5,713 6,070 Asset retirement obligation at end of period 1 $ 209,406 $ 209,041 ___________________ 1. Asset retirement obligations include $3.8 million and $3.7 million for Puget LNG held only at Puget Energy as of December 31, 2022, and 2021, respectively. The Company has identified the following obligations, as defined by ASC 410, “ARO,” which were not recognized because the liability for these assets cannot be reasonably estimated at December 31, 2022: • A legal obligation under Federal Dangerous Waste Regulations to dispose of asbestos-containing material in facilities that are not scheduled for remodeling, demolition or sales. The disposal cost related to these facilities could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated; • An obligation under Washington state law to decommission the wells at the Jackson Prairie natural gas storage facility upon termination of the project. Since the project is expected to continue as long as the Northwest pipeline continues to operate, the liability cannot be reasonably estimated; • An obligation to pay its share of decommissioning costs at the end of the functional life of the major transmission lines. The major transmission lines are expected to be used indefinitely; therefore, the liability cannot be reasonably estimated; • A legal obligation under Washington state environmental laws to remove and properly dispose of certain under and above ground fuel storage tanks. The disposal costs related to under and above ground storage tanks could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated; • An obligation to pay decommissioning costs at the end of utility service franchise agreements to restore the surface of the franchise area. The decommissioning costs related to facilities at the franchise area could not be measured since the decommissioning date is indeterminable; therefore, the liability cannot be reasonably estimated; and • A potential legal obligation may arise upon the expiration of an existing FERC hydropower license if the FERC orders the project to be decommissioned, although PSE contends that the FERC does not have such authority. Given the value of ongoing generation, flood control and other benefits provided by these projects, PSE believes that the potential for decommissioning is remote and cannot be reasonably estimated. |
Dividend Payment Restrictions
Dividend Payment Restrictions | 12 Months Ended |
Dec. 31, 2022 | |
Dividend Payment Restrictions [Abstract] | |
Dividend Payment Restrictions | Dividend Payment Restrictions The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s electric and natural gas mortgage indentures. At December 31, 2022, approximately $1.4 billion of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant. Pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciation and amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3.0 to 1.0. The common equity ratio, calculated on a regulatory basis, was 48.1% at December 31, 2022, and the EBITDA to interest expense was 5.0 to 1.0 for the twelve months ended December 31, 2022. PSE’s ability to pay dividends is also limited by the terms of its credit facilities, pursuant to which PSE is not permitted to pay dividends during any Event of Default (as defined in the facilities), or if the payment of dividends would result in an Event of Default, such as failure to comply with certain financial covenants. Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission. Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than 2.0 to 1.0. Puget Energy's EBITDA to interest expense was 3.7 to 1.0 for the twelve months ended December 31, 2022. At December 31, 2022, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends. |
Utility Plant
Utility Plant | 12 Months Ended |
Dec. 31, 2022 | |
Utility Plant [Abstract] | |
Utility Plant | Utility Plant The following table presents electric, natural gas and common utility plant classified by account: Puget Energy Puget Sound Energy Utility Plant Estimated Useful Life 1 December 31, December 31, (Dollars in Thousands) (Years) 2022 2021 2022 2021 Distribution plant 7-65 $ 7,886,665 $ 7,488,629 $ 9,406,017 $ 9,026,042 Production plant 3-90 3,131,578 3,147,987 3,780,910 3,815,599 Transmission plant 44-75 1,576,916 1,556,666 1,683,737 1,663,559 General plant 5-75 735,298 746,758 760,094 773,662 Intangible plant (including capitalized software) 2 3-50 755,430 797,691 745,973 788,240 Plant acquisition adjustment N/A 242,826 242,826 282,792 282,792 Underground storage 25-60 45,305 43,391 58,716 56,820 Liquefied natural gas storage 25-50 12,628 12,628 14,498 14,498 Plant held for future use N/A 46,079 46,020 46,232 46,172 Recoverable Cushion Gas N/A 8,784 8,655 8,784 8,655 Plant not classified N/A 723,383 316,933 723,383 316,933 Finance leases, net of accumulated amortization 3 N/A 99,967 105,020 99,967 105,020 Less: accumulated provision for depreciation (4,341,789) (4,031,458) (6,688,033) (6,416,246) Subtotal $ 10,923,070 $ 10,481,746 $ 10,923,070 $ 10,481,746 Construction work in progress 861,801 870,204 861,801 870,204 Net utility plant $ 11,784,871 $ 11,351,950 $ 11,784,871 $ 11,351,950 _______________________ 1. Estimated Useful Life years have been approved in the 2022 GRC. 2. Intangible assets include capitalized software and franchise agreements with useful lives ranging between 3-10 years and 10-50 years, respectively. 3. At December 31, 2022, and 2021, accumulated amortization of finance leases at Puget Energy and PSE was $7.3 million and $2.6 million, respectively. Jointly owned generating plant service costs are included in utility plant service cost at the Company's ownership share. The Company provides financing for its ownership interest in the jointly owned utility plants. The following tables indicate the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2022. These amounts are also included in the Utility Plant table above, with the exception of Puget Energy's portion of the Tacoma LNG facility, which is reported in the Puget Energy "Other property and investments" financial statement line item. The Company's share of fuel costs and operating expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income. Puget Energy Jointly Owned Generating Plants Energy Source (Fuel) Company’s Ownership Share Plant in Service at Cost Construction Work in Progress Accumulated Depreciation Colstrip Units 3 & 4 Coal 25.00% $ 321,767 $ — $ (176,847) Frederickson 1 Natural Gas 49.85 63,348 — (21,894) Jackson Prairie Natural Gas 33.34 44,708 837 (12,178) Tacoma LNG Natural Gas various 494,795 2,936 (10,922) Puget Sound Energy Jointly Owned Generating Plants Energy Source (Fuel) Company’s Ownership Share Plant in Service at Cost Construction Work in Progress Accumulated Depreciation Colstrip Units 3 & 4 Coal 25.00 % $ 579,019 $ — $ (434,099) Frederickson 1 Natural Gas 49.85 69,415 — (27,962) Jackson Prairie Natural Gas 33.34 58,716 837 (26,186) Tacoma LNG Natural Gas various 245,690 503 (5,052) In June 2019, Talen, the plant operator of Colstrip Units 1 and 2, announced a plan to shut down as of December 31, 2019. The Company retired Colstrip 1&2 from Utility Plant and transferred the unrecovered plant amount of $126.5 million to regulatory assets, offset by depreciation as included in base rates until the 2019 GRC became effective in October 2020. Consistent with the GRC settlement in 2017, monetization of the PTCs will fund the following: (i) Colstrip Community Transition Fund, (ii) unrecovered Colstrip plant and (iii) incurred decommissioning and remediation costs for Colstrip. At December 31, 2022, and December 31, 2021, the unrecovered plant for Colstrip 1&2 was fully offset with PTCs. On September 2, 2022, PSE and Talen Energy reached an agreement to transfer PSE's ownership interest in Colstrip Units 3 and 4 to Talen Energy on December 31, 2025. Management evaluated Colstrip Units 3 and 4 and determined that the applicable held for sale accounting criteria were not met as of December 31, 2022. As such, Colstrip Units 3 and 4 are classified as Electric Utility Plant on the Company's balance sheet as of December 31, 2022. Asset Retirement Obligation The Company has recorded liabilities for steam generation sites, combustion turbine generation sites, wind generation sites, distribution and transmission poles, natural gas mains, liquefied natural gas storage sites, and leased facilities where disposal is governed by ASC 410-20 “Asset Retirement and Environmental Obligations" (ARO). The Company records its ARO liabilities for its electric transmission and distribution poles as well as gas distribution mains aligned with its underlying asset data with future estimates of retirements. For the twelve months ended December 31, 2022, the Company reviewed the estimated remediation costs at Colstrip and determined no change was warranted for the Colstrip ARO liability for Colstrip Units 1 and 2 and Colstrip Units 3 and 4. For the twelve months ended December 31, 2021, the Company reviewed the estimated remediation costs at Colstrip and decreased the Colstrip ARO liability by $1.5 million for Colstrip Units 1 and 2, and $3.1 million for Colstrip Units 3 and 4. The 2021 decrease to Colstrip 1 and 2 is primarily due to remediation plans approved by the Montana Department of Environmental Quality under a 2012 settlement between the plant operator and the state for the remaining sites at Colstrip. The plant operator previously contested the approved plan for Colstrip Units 1 and 2 under the defined process in the settlement with the state and reached a settlement agreement regarding the ability to still present another option under the settlement terms and conditions. The Company had previously recorded these incremental costs in 2020 for remediation work on the older ponds under ASC 410-20 “Asset Retirement and Environmental Obligations" and ASC 410-30 “Environmental Remediation". For the twelve months ended December 31, 2022 and 2021, the Company also recorded relief of ARO and environmental remediation liability of $6.9 million and $13.1 million, respectively. In addition, the Company recorded Tacoma LNG facility ARO liability of $3.9 million and $3.8 million for PSE and $3.8 million and $3.7 million for Puget LNG as of December 31, 2022 and December 31, 2021, respectively. The 2022 and 2021 increases to the Tacoma LNG facility ARO liabilities are primarily due to continued construction of the plant. In 2022, the ARO liability associated with the Tacoma LNG facility was fully recorded as construction was essentially complete and commissioning activities are on-going. Puget Energy and Puget Sound Energy December 31, (Dollars in Thousands) 2022 2021 Asset retirement obligation at beginning of the period $ 209,041 $ 216,163 Relief of liability (6,867) (13,146) Revisions in estimated cash flows 1,519 (46) Accretion expense 5,713 6,070 Asset retirement obligation at end of period 1 $ 209,406 $ 209,041 ___________________ 1. Asset retirement obligations include $3.8 million and $3.7 million for Puget LNG held only at Puget Energy as of December 31, 2022, and 2021, respectively. The Company has identified the following obligations, as defined by ASC 410, “ARO,” which were not recognized because the liability for these assets cannot be reasonably estimated at December 31, 2022: • A legal obligation under Federal Dangerous Waste Regulations to dispose of asbestos-containing material in facilities that are not scheduled for remodeling, demolition or sales. The disposal cost related to these facilities could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated; • An obligation under Washington state law to decommission the wells at the Jackson Prairie natural gas storage facility upon termination of the project. Since the project is expected to continue as long as the Northwest pipeline continues to operate, the liability cannot be reasonably estimated; • An obligation to pay its share of decommissioning costs at the end of the functional life of the major transmission lines. The major transmission lines are expected to be used indefinitely; therefore, the liability cannot be reasonably estimated; • A legal obligation under Washington state environmental laws to remove and properly dispose of certain under and above ground fuel storage tanks. The disposal costs related to under and above ground storage tanks could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated; • An obligation to pay decommissioning costs at the end of utility service franchise agreements to restore the surface of the franchise area. The decommissioning costs related to facilities at the franchise area could not be measured since the decommissioning date is indeterminable; therefore, the liability cannot be reasonably estimated; and • A potential legal obligation may arise upon the expiration of an existing FERC hydropower license if the FERC orders the project to be decommissioned, although PSE contends that the FERC does not have such authority. Given the value of ongoing generation, flood control and other benefits provided by these projects, PSE believes that the potential for decommissioning is remote and cannot be reasonably estimated. |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2022 | |
Long-Term Debt, Unclassified [Abstract] | |
Long-term Debt | Long-Term Debt The following table presents outstanding long-term debt due dates and principal amounts, net of debt discount, issuance and other costs and fair value adjustments as of 2022 and 2021: (Dollars in Thousands) December 31, Series Type Due 2022 2021 Puget Sound Energy: 7.150% First Mortgage Bond 2025 $ 15,000 $ 15,000 7.200% First Mortgage Bond 2025 2,000 2,000 7.020% Senior Secured Note 2027 300,000 300,000 7.000% Senior Secured Note 2029 100,000 100,000 3.900% Pollution Control Bond 2031 138,460 138,460 4.000% Pollution Control Bond 2031 23,400 23,400 5.483% Senior Secured Note 2035 250,000 250,000 6.724% Senior Secured Note 2036 250,000 250,000 6.274% Senior Secured Note 2037 300,000 300,000 5.757% Senior Secured Note 2039 350,000 350,000 5.795% Senior Secured Note 2040 325,000 325,000 5.764% Senior Secured Note 2040 250,000 250,000 4.434% Senior Secured Note 2041 250,000 250,000 5.638% Senior Secured Note 2041 300,000 300,000 4.300% Senior Secured Note 2045 425,000 425,000 4.223% Senior Secured Note 2048 600,000 600,000 3.250% Senior Secured Note 2049 450,000 450,000 2.893% Senior Secured Note 2051 450,000 450,000 4.700% Senior Secured Note 2051 45,000 45,000 * Debt discount, issuance cost and other * (37,095) (39,141) Total PSE long-term debt $ 4,786,765 $ 4,784,719 Puget Energy: * Fair value adjustment of PSE long-term debt * $ (148,341) $ (156,849) * Revolving Credit Agreement 2027 34,300 33,300 3.650% Senior Secured Note 2025 400,000 400,000 2.379% Senior Secured Note 2028 500,000 500,000 4.100% Senior Secured Note 2030 650,000 650,000 4.224% Senior Secured Note 2032 450,000 — * Debt discount, issuance cost and other * (9,351) (7,404) Total Puget Energy long-term debt $ 6,663,373 $ 6,203,766 ___________________ * Not Applicable. PSE's senior secured notes will cease to be secured by the pledged first mortgage bonds on the date (the "Substitution Date") that all of the first mortgage bonds issued and outstanding under the electric or natural gas utility mortgage indenture have been retired. As of December 31, 2022, the latest maturity date of the first mortgage bonds, other than pledged first mortgage bonds, is December 22, 2025. On the Substitution Date, PSE will deliver to the trustee for PSE's senior secured notes substitute pledged first mortgage bonds to be issued under a new mortgage indenture. As a result, as of the Substitution Date PSE's outstanding senior secured notes and any future series of PSE's senior secured notes will be secured by substitute pledged first mortgage bonds. Puget Energy Long-Term Debt On June 14, 2021, Puget Energy issued $500.0 million of senior secured notes at an interest rate of 2.379%. The notes were issued for a period of 7 years, mature on June 15, 2028, and pay interest semi-annually on June 15 and December 15. Proceeds from the issuance of the notes were invested in short-term money market funds, then used to repay the Company’s $500.0 million 6.0% notes that matured on September 1, 2021. On June 23, 2021, Puget Energy received an equity contribution from Puget Equico LLC, Puget Energy’s parent company. The proceeds from the equity contribution were used to pay off Puget Energy’s $210.0 million term loan on June 23, 2021. On March 10, 2022, Puget Energy filed an S-3 Registration statement under which it may issue up to $1.0 billion aggregate principal amount of senior notes secured by Puget Energy's assets. As of the date of this report, $550.0 million was available to be issued. The shelf registration will expire in March 2025. On March 17, 2022, Puget Energy issued $450.0 million of senior secured notes at an interest rate of 4.224%. The notes mature on March 15, 2032, and pay interest semi-annually on March 15 and September 15 of each year. Proceeds from the issuance of the notes were invested in short-term money market funds, and then used to repay Puget Energy's $450.0 million 5.625% notes that were originally scheduled to mature July 2022. On April 28, 2022, Puget Energy redeemed the $450.0 million 5.625% senior secured notes due July 2022 and paid related expenses for a total redemption price of $457.2 million, which includes repayment of the $450.0 million principal amount and $7.2 million of accrued interest expense. At December 31, 2022, Puget Energy maintained an $800.0 million credit facility. As of December 31, 2022, $118.6 million was drawn and outstanding under the facility, of which $34.3 million was classified as long-term debt and $84.3 million was classified as short-term debt. Puget Sound Energy Long-Term Debt On September 15, 2021, PSE issued $450.0 million of senior secured notes at an interest rate of 2.893%. The notes were issued for a period of 30 years, mature on September 15, 2051, and pay interest semi-annually on March 15 and September 15 of each year. The proceeds from the issuance will be used for repayment of commercial paper as well as general corporate purposes. In August 2022, PSE filed an S-3 shelf registration statement under which it may issue up to $1.4 billion aggregate principal amount of senior notes secured by first mortgage bonds. As of the date of this report, $1.4 billion was available to be issued. The shelf registration will expire in August 2025. Long-Term Debt Maturities The principal amounts of long-term debt maturities for the next five years and thereafter are as follows: (Dollars in Thousands) 2023 2024 2025 2026 2027 Thereafter Total Maturities of: PSE $ — $ — $ 17,000 $ — $ 300,000 $ 4,506,860 $ 4,823,860 Puget Energy — — 400,000 — $ 34,300 1,600,000 2,034,300 Total long-term debt $ — $ — $ 417,000 $ — $ 334,300 $ 6,106,860 $ 6,858,160 |
Liquidity Facilities and Other
Liquidity Facilities and Other Financing Arrangements | 12 Months Ended |
Dec. 31, 2022 | |
Liquidity Facilities and Other Financing Arrangements [Abstract] | |
Liquidity Facilities and Other Financing Arrangements | Liquidity Facilities and Other Financing ArrangementsAs of December 31, 2022, and 2021, PSE had $357.0 million and $140.0 million in short-term debt outstanding, respectively. Outside of the consolidation of PSE’s short-term debt, Puget Energy had $118.6 million drawn and outstanding under its credit facility, of which $34.3 million was classified as long-term debt and $84.3 million was classified as short-term debt. PSE’s weighted-average interest rate on short-term debt, including borrowing rate, commitment fees and the amortization of debt issuance costs, during 2022 and 2021 was 6.1% and 1.6%, respectively. As of December 31, 2022, PSE and Puget Energy had several committed credit facilities that are described below. Puget Sound Energy Credit Facility On May 16, 2022, PSE entered into a new $800.0 million credit facility to replace the existing facility. The terms and conditions, including fees, financial covenant, expansion feature and credit spreads remain substantially the same. The base interest rate on loans has changed to the Secured Overnight Financing Rate (SOFR), as the London Interbank Offer Rate (LIBOR) is being discontinued in 2023. The proceeds of the PSE credit facility are to be used for general corporate purposes. The maturity date of the credit facility is May 14, 2027. The credit facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million and has an expansion feature which, upon receipt of commitments from one or more lenders, could increase the total size of the facility up to $1.4 billion. The credit agreement is syndicated among numerous lenders and contains usual and customary affirmative and negative covenants that, among other things, place limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreement also contains a leverage ratio that requires the ratio of (a) total funded indebtedness to (b) total capitalization to be 65% or less at all times. PSE certifies its compliance with such covenants to participating banks each quarter. As of December 31, 2022, PSE was in compliance with all applicable covenant ratios. The credit agreement allows PSE to borrow at a prime based rate or to make floating rate advances at the SOFR, in either case, plus a spread that is based upon PSE's credit rating. PSE must pay a commitment fee on the unused portion of the credit facility. The spreads and the commitment fee depend on PSE's credit ratings. As of the date of this report, interest was calculated as SOFR plus 0.10% SOFR adjustment plus 1.25% spread over the adjusted SOFR rate and the commitment fee was 0.175%. As of December 31, 2022, no amount was drawn under PSE's credit facility and $357.0 million was outstanding under the commercial paper program. Outside of the credit agreement, PSE had a $2.3 million letter of credit in support of a long-term transmission contract and had $28.0 million issued under a standby letter of credit in support of natural gas purchases. Demand Promissory Note In 2006, PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a demand promissory note pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy. Under the terms of the promissory note, PSE pays interest on the outstanding borrowings based on the lower of the weighted-average interest rates of PSE’s outstanding commercial paper or PSE’s senior unsecured revolving credit facility. Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. As of December 31, 2022, there was no outstanding balance under the promissory note. Puget Energy Credit Facility On May 16, 2022, Puget Energy entered into a new $800.0 million credit facility to replace the existing facility. The terms and conditions, including fees, financial covenant, expansion feature and credit spreads remain substantially the same. The base interest rate on loans has changed to the SOFR, as the LIBOR is being discontinued in 2023. The proceeds of the PE credit facility are to be used for general corporate purposes. The maturity date of the credit facility is May 14, 2027. The Puget Energy revolving senior secured credit facility also has an accordion feature, upon receipt of commitments from one or more lenders, could increase the size of the facility up to $1.3 billion. The revolving senior secured credit facility allows Puget Energy to borrow based on a prime based rate or SOFR, in either case, plus a spread based on Puget Energy's credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of December 31, 2022, there was $118.6 million drawn and outstanding under the facility, of which $34.3 million was classified as long-term debt and $84.3 million was classified as short-term debt. As of the date of this report, interest was calculated as SOFR plus 0.10% SOFR adjustment plus 1.75% spread over the adjusted SOFR rate and the commitment fee was 0.275%. The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The credit agreement also contains a leverage ratio that requires the ratio of (a) total funded indebtedness to (b) total capitalization to be 65% or less at all times. As of December 31, 2022, Puget Energy was in compliance with all applicable covenants. On September 26, 2022, PE borrowed $50.0 million on the credit facility and contributed the proceeds to PSE as an equity contribution. The equity proceeds were used for general corporate purposes. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2022 | |
Leases [Abstract] | |
Lessee, Operating and Finance Leases | Leases PSE has operating leases for buildings for corporate offices and operations, real estate for operating facilities and the PSE and PLNG LNG facility, land for our wind farms, and vehicles for PSE’s fleet. Finance leases represent office printers and office buildings. The leases have remaining lease terms of less than a year to 47 years. PSE's right-of-use (ROU) assets and lease liabilities include options to extend leases when it is reasonably certain that PSE will exercise that option. During 2021, mechanical completion was achieved for the Puget LNG facility which triggered an increase in the lease payments for the Port of Tacoma lease. This remeasurement resulted in an increase of the operating lease ROU asset and operating lease liabilities of $26.3 million, of which $0.4 million was recorded in current operating lease liabilities and $25.9 million was recorded in operating lease liabilities. Additionally, two finance leases commenced for service center facilities in Kent and Puyallup, Washington. The Kent lease has a term of 20 years and resulted in an increase of electric utility plant and finance lease liabilities of $45.1 million, of which $1.0 million was recorded in other current liabilities and $44.1 million was recorded in finance lease liabilities, respectively. The Puyallup lease has a term of 20 years and resulted in an increase in common utility plant and finance lease liabilities of $61.3 million, of which $0.4 million was recorded in other current liabilities and $59.9 million was recorded in finance lease liabilities. During 2022, there were no material changes regarding the Company's leases. The components of lease cost were as follows: Puget Energy and Year Ended December 31, Year Ended December 31, (Dollars in Thousands) 2022 2021 Finance lease cost: Amortization of right-of-use asset $ 2,465 $ 1,291 Interest on lease liabilities 2,482 358 Total finance lease cost $ 4,947 $ 1,649 Operating lease cost 1 $ 23,984 $ 23,983 _______________ 1. Includes $1.5 million and $1.4 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease or both of the years ended December 31, 2022 and December 31, 2021, respectively. Supplemental cash flow information related to leases was as follows: Puget Energy and Year Ended December 31, Year Ended December 31, (Dollars in Thousands) 2022 2021 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flow for operating leases $ 16,574 $ 16,440 Investing cash flow for operating leases 1 7,410 7,543 Operating cash flow for finance leases 2,482 358 Financing cash flow for finance leases 2,465 1,291 Non-cash disclosure upon commencement of new lease Right-of-use assets obtained in exchange for new operating lease liabilities $ 5,338 $ 4,820 Right-of-use assets obtained in exchange for new finance lease liabilities — 105,176 Non-cash disclosure upon modification of existing lease Modification of operating lease right-of-use assets $ 21,068 $ 26,287 _______________ 1 Includes $1.5 million and $1.4 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for both of the years ended December 31, 2022 and December 31, 2021, respectively. Supplemental balance sheet information related to leases was as follows: Puget Energy and (Dollars in Thousands) At December 31, At December 31, Operating Leases 2022 2021 Operating lease right-of-use asset $ 193,509 $ 184,957 Operating leases liabilities current $ 20,342 $ 20,398 Operating lease liabilities long-term 181,265 172,510 Total operating lease liabilities: $ 201,607 $ 192,908 Finance Leases Common plant $ 58,391 $ 61,227 Electric plant 41,576 43,793 Total finance lease assets $ 99,967 $ 105,020 Other current liabilities $ 3,167 $ 1,742 Finance lease liabilities 102,518 105,303 Total finance lease liabilities $ 105,685 $ 107,045 Weighted Average Remaining Lease Term Operating leases 22.00 Years 22.80 Years Finance leases 19.10 Years 20.15 Years Weighted Average Discount Rate Operating leases 3.62 % 3.27 % Finance leases 3.07 % 3.07 % The following table summarizes the Company’s estimated future minimum lease payments as of December 31, 2022: Puget Energy and Future Minimum Lease Payments (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2023 $ 23,676 $ 6,383 2024 23,232 6,408 2025 21,887 6,534 2026 21,472 6,591 2027 21,047 6,670 Thereafter 172,969 109,882 Total lease payments $ 284,283 $ 142,468 Less imputed interest (82,676) (36,783) Total net present value $ 201,607 $ 105,685 |
Accounting for Derivative Instr
Accounting for Derivative Instruments and Hedging Activities | 12 Months Ended |
Dec. 31, 2022 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Accounting for Derivative Instruments and Hedging Activities | Accounting for Derivative Instruments and Hedging Activities PSE employs various energy portfolio optimization strategies, but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the Power Cost Adjustment. Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility in costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. PSE's hedging strategy includes a risk-responsive component for the core natural gas portfolio, which utilizes quantitative risk-based measures with defined objectives to balance both portfolio risk and hedge costs. PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. Currently, the Company does not apply cash flow hedge accounting, and therefore records all mark-to-market gains or losses through earnings. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program, and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. The following table presents the volumes, fair values and classification of the Company's derivative instruments recorded on the balance sheets: Puget Energy and Year Ended December 31, (Dollars in Thousands) Volumes (millions) Assets 1 Liabilities² 2022 2021 2022 2021 2022 2021 Electric portfolio derivatives * * $ 337,703 $ 74,829 $ 87,120 $ 85,424 Natural gas derivatives (MMBtus) 3 322 347 343,947 79,578 56,222 18,850 Total derivative contracts $ 681,650 $ 154,407 $ 143,342 $ 104,274 Current 587,029 128,210 124,976 63,309 Long-term 94,621 26,197 18,366 40,965 Total derivative contracts $ 681,650 $ 154,407 $ 143,342 $ 104,274 __________ 1. Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments. 2. Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments. 3. All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 234.9 million One Million British Thermal Units (MMBtus) and purchased electricity of 5.3 million megawatt hours (MWhs) at December 31, 2022, and 238.0 million MMBtus and 8.1 million MWhs at December 31, 2021. It is the Company's policy to record all derivative transactions on a gross basis at the contract level without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements, which standardize physical power contracts; International Swaps and Derivatives Association (ISDA) agreements, which standardize financial natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical natural gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as the right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount. For further details regarding the fair value of derivative instruments, see Note 11, "Fair Value Measurements", to the consolidated financial statements included in Item 8 of this report. The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities: Puget Energy and December 31, 2022 (Dollars in Thousands) Gross Amount Recognized in the Consolidated Balance Sheet 1 Gross Amounts Offset in the Consolidated Balance Sheet Net of Amounts Presented in the Consolidated Balance Sheet Gross Amounts Not Offset in the Consolidated Balance Sheet Commodity Contracts 2 Cash Collateral Received/Pledged Net Amount Assets: Energy derivative contracts $ 681,650 $ — $ 681,650 $ (125,334) $ — $ 556,316 Liabilities: Energy derivative contracts 143,342 — 143,342 (125,334) (5,661) 12,347 Puget Energy and December 31, 2021 (Dollars in Thousands) Gross Amount Recognized 1 Gross Amounts Offset in the Consolidated Balance Sheet Net of Amounts Presented in the Consolidated Balance Sheet Gross Amounts Not Offset in the Consolidated Balance Sheet Commodity Contracts 2 Cash Collateral Received/Pledged Net Amount Assets Energy Derivative Contracts $ 154,407 $ — $ 154,407 $ (40,833) $ — $ 113,574 Liabilities Energy Derivative Contracts 104,274 — 104,274 (40,833) (1,743) 61,698 __________ 1. All derivative contract deals are executed under ISDA, NAESB, and WSPP master agreements with right of set-off. 2. Amounts reflect netting by Counterparty and right of set-off. The following tables present the effect and locations of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income: Puget Energy and Year Ended December 31, (Dollars in Thousands) Location 2022 2021 2020 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net $ 61,761 $ 26,686 $ 5,534 Realized Electric generation fuel 158,550 76,504 5,246 Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 199,416 (12,901) (32,341) Realized Purchased electricity 20,917 (3,044) (14,958) Total gain (loss) recognized in income on derivatives $ 440,644 $ 87,245 $ (36,519) The Company is exposed to credit risk primarily through buying and selling electricity and natural gas to serve its customers. Credit risk is the potential loss resulting from a counterparty's non-performance under an agreement. The Company manages credit risk with policies and procedures for, among other things, counterparty credit analysis, exposure measurement, and exposure monitoring and mitigation. The Company monitors counterparties for significant swings in credit default swap rates, credit rating changes by external rating agencies, ownership changes or financial distress. Where deemed appropriate, the Company may request collateral or other security from its counterparties to mitigate potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of December 31, 2022, approximately 99.4% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, is with counterparties that are rated investment grade by rating agencies and 0.6% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies. The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors in the determination of reserves, such as credit default swaps and bond spreads. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels. The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against unrealized gain (loss) positions. As of December 31, 2022, the Company was in a net liability position with the majority of counterparties, so the default factors of counterparties did not have a significant impact on reserves for the period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. PSE also transacts power futures contracts on the Intercontinental Exchange (ICE), and natural gas contracts on the ICE NGX exchange platform. Execution of contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of December 31, 2022, PSE had cash posted as collateral of $23.2 million related to contracts executed on the ICE platform. In August 2022, PSE entered into a standby letter of credit agreement with TD Bank allowing standby letter of credit postings of up to $50.0 million as a condition of transacting on the ICE NGX platform. As of December 31, 2022, PSE had $33.0 million in cash posted with ICE NGX and $28.0 million issued under the standby letter of credit agreement. PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades during the twelve months ended December 31, 2022. The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post: Puget Energy and December 31, (Dollars in Thousands) 2022 2021 Contingent Feature Fair Value 1 Liability Posted Contingent Fair Value 1 Liability Posted Contingent Credit rating 2 $ 3,157 $ — $ 3,157 $ 52,537 $ — $ 52,537 Requested credit for adequate assurance 4,157 — — 9,380 — — Forward value of contract 3 5,661 56,200 N/A 1,743 12,782 N/A Total $ 12,975 $ 56,200 $ 3,157 $ 63,660 $ 12,782 $ 52,537 _______________ 1. Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable. 2. Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral. 3. Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2020 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements ASC 820 established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy categorizes the inputs into three levels with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority given to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows: Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Equity securities that are also classified as cash equivalents are considered Level 1 if there are unadjusted quoted prices in active markets for identical assets or liabilities. Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options. Level 3 - Pricing inputs include significant inputs that have little or no observability as of the reporting date. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves, contract terms and prices, credit-risk adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs as substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service. The Company considers its electric and natural gas contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes or that are transacted at illiquid delivery locations are classified as Level 3 in the fair value hierarchy. Management's assessment is based on the trading activity in real-time and forward electric and natural gas markets. Each quarter, the Company confirms the validity of pricing-service quoted prices used to value Level 2 commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter. Assets and Liabilities with Estimated Fair Value The carrying values of cash and cash equivalents, restricted cash, and short-term debt as reported on the balance sheet are reasonable estimates of their fair value due to the short-term nature of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of other investments of $55.0 million and $53.2 million at December 31, 2022, and 2021, respectively, are included in "Other property and investments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions. The fair value of long-term notes were estimated using the discounted cash flow method with U.S. Treasury yields and Company's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows: Puget Energy December 31, 2022 December 31, 2021 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Financial liabilities: Long-term debt (fixed-rate), net of discount 1 2 $ 6,629,073 $ 6,149,797 $ 6,170,466 $ 7,769,896 Long-term debt (variable-rate), net of discount 2 34,300 34,300 33,300 33,300 Total $ 6,663,373 $ 6,184,097 $ 6,203,766 $ 7,803,196 Puget Sound Energy December 31, 2022 December 31, 2021 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Financial liabilities: Long-term debt (fixed-rate), net of discount 2 2 $ 4,786,765 $ 4,379,010 $ 4,784,719 $ 6,145,639 Total $ 4,786,765 $ 4,379,010 $ 4,784,719 $ 6,145,639 _______________ 1. The carrying value includes debt issuances costs of $21.5 million and $22.7 million for December 31, 2022, and 2021, respectively, which are not included in fair value. 2. The carrying value includes debt issuances costs of $21.4 million and $22.8 million for December 31, 2022, and 2021, respectively, which are not included in fair value. Assets and Liabilities Measured at Fair Value on a Recurring Basis The following tables present the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis and the reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy and Fair Value Fair Value December 31, 2022 December 31, 2021 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric Derivative Instruments $ 218,610 $ 119,093 $ 337,703 $ 68,011 $ 6,818 $ 74,829 Gas Derivative Instruments 342,988 959 343,947 79,526 52 79,578 Total derivative assets $ 561,598 $ 120,052 $ 681,650 $ 147,537 $ 6,870 $ 154,407 Liabilities: Electric Derivative Instruments $ 84,105 $ 3,015 $ 87,120 $ 35,854 $ 49,570 $ 85,424 Gas Derivative Instruments 55,136 1,086 56,222 16,678 2,172 18,850 Total derivative liabilities $ 139,241 $ 4,101 $ 143,342 $ 52,532 $ 51,742 $ 104,274 Puget Energy and Year Ended December 31, Level 3 Roll-Forward Net Asset (Liability) 2022 2021 2020 (Dollars in Thousands) Electric Natural Gas Total Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ (42,752) $ (2,120) $ (44,872) $ (23,718) $ (1,135) $ (24,853) $ (3,379) $ 1,282 $ (2,097) Changes during period: Realized and unrealized energy derivatives Included in earnings 1 180,533 — 180,533 (15,839) — (15,839) (23,559) — (23,559) Included in regulatory assets / liabilities — 301 301 — (1,749) (1,749) — (1,049) (1,049) Settlements 2 (21,972) 1,369 (20,603) (3,195) 764 (2,431) 3,220 (1,368) 1,852 Transferred into Level 3 — — — — — — — — — Transferred out Level 3 269 323 592 — — $ — — — $ — Balance at end of period $ 116,078 $ (127) $ 115,951 $ (42,752) $ (2,120) $ (44,872) $ (23,718) $ (1,135) $ (24,853) __________________ 1. Income Statement classification: Unrealized gain (loss) on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $147.1 million, $(21.6) million and $(21.3) million for the years ended December 31, 2022, 2021, and 2020, respectively. 2. The Company had no purchases or sales of options during the reported periods. Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company's consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company's consolidated statements of income. In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company's commodity contracts extend beyond what is considered observable as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next, and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month and reported in the Level 3 Roll-forward table above. The Company did not have any transfers between Level 2 and Level 1 during the years ended December 31, 2022, 2021, and 2020. The Company does transact at locations, or market price points, that are illiquid or for which no prices are available from the independent pricing service. In such circumstances the Company uses a more liquid price point and adjusts the price for transportation costs to the illiquid locations to serve as a proxy for market prices. Such transactions are classified as Level 3. The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs. The only significant unobservable input into the fair value measurement of the Company's Level 3 assets and liabilities is the forward price for electric and natural gas contracts. Below are the forward price ranges for the Company's commodity contracts, as of December 31, 2022: Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Electricity $ 119,093 $ 3,015 Discounted cash flow Power Prices (per MWh) $ 55.79 $ 291.03 $ 131.51 Natural Gas $ 959 $ 1,086 Discounted cash flow Natural Gas Prices (per MMBtu) $ 3.84 $ 7.00 $ 4.87 _______________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently, significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. At December 31, 2022, a hypothetical 10% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $37.6 million. Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis Puget Energy records the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle. ASC 360 requires long-lived assets to be tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. One such triggering event is a significant decrease in the forward market prices of power. Puget Energy evaluated the triggering event criteria in ASC 360 during 2022 and 2021 and determined there was no indication of impairment of its power purchase contracts. |
Employee Investment Plans
Employee Investment Plans | 12 Months Ended |
Dec. 31, 2022 | |
Employee Investment Plans [Abstract] | |
Employee Investment Plans | Employee Investment PlansThe Company's Investment Plan is a qualified employee 401(k) plan, under which employee salary deferrals and after-tax contributions are used to purchase several different investment fund options. PSE’s contributions to the employee Investment Plan were $25.2 million, $23.6 million and $22.1 million for the years 2022, 2021, and 2020, respectively. The employee Investment Plan eligibility requirements are set forth in the plan documents. Non-represented employees and United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry (UA) represented employees hired before January 1, 2014, and International Brotherhood of Electrical Workers Local Union 77 (IBEW) represented employees hired before December 12, 2014, have the following company contributions: 1. For employees under the Cash Balance retirement plan formula, PSE will match 100% of an employee's contribution up to 6.0% of plan compensation each paycheck, and will make an additional year-end contribution equal to 1.0% of base pay. 2. For employees grandfathered under the Final Average Earning retirement plan formula, PSE will match 55.0% of an employee’s contribution up to 6.0% of plan compensation each paycheck. Non-represented and UA-represented employees hired on or after January 1, 2014 along with IBEW-represented employees hired on or after December 12, 2014, will have access to the 401(k) plan. The two contribution sources from PSE are below: 1. 401(k) Company Matching: For non-represented, UA-represented and IBEW-represented employees PSE will match: 100% match on the first 3.0% of pay contributed and 50.0% match on the next 3.0% of pay contributed, such that an employee who contributes 6.0% of pay will receive 4.5% of pay in company match. Company matching will be immediately vested. 2. Company Contribution: For UA-represented employees will receive an annual company contribution of 4.0% of eligible pay placed in the Cash Balance retirement plan. Non-represented and IBEW-represented employees will receive an annual company contribution of 4.0% of eligible pay, placed either in the Investment Plan 401(k) plan or in PSE’s Cash Balance retirement plan. Non-represented and IBEW-represented employees will make a one-time election within 30 days of hire and direct that PSE put the 4.0% contribution either into the 401(k) plan or into an account in the Cash Balance retirement plan. The Company's 4.0% contribution will vest after three years of service. |
Retirement Benefits
Retirement Benefits | 12 Months Ended |
Dec. 31, 2022 | |
Subsidiaries [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Retirement Benefits | Retirement Benefits PSE has a defined benefit pension plan (Qualified Pension Benefits) covering a substantial majority of PSE employees. For employees hired prior to 2014, pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates. Effective January 1, 2014, all new UA represented employees hired or rehired receive annual pay credits of 4.0% of eligible pay each year in the cash balance formula of the defined pension plan. Effective January 1, 2014 for non-represented employees, and December 12, 2014 for employees represented by the IBEW, newly hired or rehired employees receive annual employer contributions of 4.0% of eligible play each year into the cash balance formula of the defined benefit pension or 401k plan account. PSE also has a non-qualified Supplemental Executive Retirement Plan (SERP) for certain key senior management employees that closed to new participants in 2019. Effective 2019, PSE has an officer restoration benefit for new officers who join PSE or are promoted, such that company contributions under PSE’s applicable tax-qualified plan, which otherwise would have been credited if not for IRS limitations, are credited at 4.0% of earnings to an account with the Deferred Compensation Plan. In addition to providing pension benefits, PSE provides legacy group health care and life insurance benefits (Other Benefits) for certain retired employees. These benefits are provided principally through an insurance company. The insurance premiums, paid primarily by retirees, are based on the benefits provided during the prior year. On June 11, 2019, the Company's Welfare Benefits Committee approved the termination of the Plan effective December 31, 2019, and the creation of a Retiree Health Reimbursement Account (HRA) Plan effective January 1, 2020. Puget Energy's retirement plans were remeasured as a result of the merger in 2009, which represents the difference between Puget Energy and PSE's retirement plans. The components of service cost are included within utility operations and maintenance for PSE and within non-utility expense and other for Puget Energy while all non-service cost components are included in other income. The following tables summarize the Company’s change in benefit obligation, change in plan assets and amounts recognized in the Statements of Financial Position for the years ended December 31, 2022, and 2021: Puget Energy and Qualified SERP Other (Dollars in Thousands) 2022 2021 2022 2021 2022 2021 Change in benefit obligation: Benefit obligation at beginning of period $ 834,960 $ 849,383 $ 43,155 $ 46,742 $ 11,654 $ 12,114 Amendments — — — — 38 205 Service cost 26,351 26,888 557 456 217 155 Interest cost 24,263 22,381 1,253 1,183 311 302 Actuarial loss (gain) (215,005) (6,826) (5,260) 828 (2,397) (514) Benefits paid (80,226) (55,831) (7,659) (6,054) (808) (803) Medicare part D subsidy received — — — — — 195 Administrative expense (1,065) (1,035) — — — — Benefit obligation at end of period $ 589,278 $ 834,960 $ 32,046 $ 43,155 $ 9,015 $ 11,654 Puget Energy and Qualified SERP Other (Dollars in Thousands) 2022 2021 2022 2021 2022 2021 Change in plan assets: Fair value of plan assets at beginning of period $ 898,550 $ 834,655 $ — $ — $ 6,341 $ 5,918 Actual return on plan assets (176,537) 102,787 — — (550) 1,005 Employer contribution 18,000 18,000 7,659 6,054 207 222 Benefits paid (80,226) (55,831) (7,659) (6,054) (808) (804) Administrative expense (1,254) (1,061) — — — — Fair value of plan assets at end of period $ 658,533 $ 898,550 $ — $ — $ 5,190 $ 6,341 Funded status at end of period $ 69,255 $ 63,590 $ (32,046) $ (43,155) $ (3,825) $ (5,313) Puget Energy and Qualified SERP Other (Dollars in Thousands) 2022 2021 2022 2021 2022 2021 Amounts recognized in Consolidated Balance Sheet consist of: Noncurrent assets $ 69,255 $ 63,590 $ — $ — $ — $ — Current liabilities — — (3,532) (2,822) (252) (280) Noncurrent liabilities — — (28,514) (40,333) (3,573) (5,033) Net assets (liabilities) $ 69,255 $ 63,590 $ (32,046) $ (43,155) $ (3,825) $ (5,313) Puget Energy and Qualified SERP Other (Dollars in Thousands) 2022 2021 2022 2021 2022 2021 Change in plan obligation and plan asset: Projected benefit obligation $ 589,278 $ 834,960 $ 32,046 $ 43,155 $ 9,015 $ 11,654 Accumulated benefit obligation 582,538 823,418 29,763 40,773 8,929 11,549 Fair value of plan assets 658,533 898,550 — — 5,190 6,341 The following tables summarize Puget Energy's and PSE's pension benefit amounts recognized in accumulated other comprehensive income (AOCI) for the years ended December 31, 2022, and 2021: Puget Energy Qualified SERP Other (Dollars in Thousands) 2022 2021 2022 2021 2022 2021 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 31,213 $ 24,859 $ 1,563 $ 9,571 $ (1,964) $ (525) Prior service cost (credit) — — 289 578 259 242 Total $ 31,213 $ 24,859 $ 1,852 $ 10,149 $ (1,705) $ (283) Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2022 2021 2022 2021 2022 2021 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 124,767 $ 127,111 $ 1,864 $ 10,103 $ (2,056) $ (622) Prior service cost (credit) — — 289 578 258 242 Total $ 124,767 $ 127,111 $ 2,153 $ 10,681 $ (1,798) $ (380) The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, 2022, 2021, and 2020. Puget Energy Qualified SERP Other (Dollars in Thousands) 2022 2021 2020 2022 2021 2020 2022 2021 2020 Components of net periodic benefit cost: Service cost $ 26,351 $ 26,888 $ 24,337 $ 557 $ 456 $ 756 $ 217 $ 155 $ 190 Interest cost 24,263 22,381 25,180 1,253 1,183 1,464 311 302 368 Expected return on plan assets (51,014) (48,239) (49,902) — — — (379) (355) (389) Amortization of prior service cost (credit) — (1,904) (1,980) 289 349 349 22 6 — Amortization of net loss (gain) 6,381 11,803 8,160 2,471 2,165 2,122 (29) (39) (82) Net periodic benefit cost $ 5,981 $ 10,929 $ 5,795 $ 4,570 $ 4,153 $ 4,691 $ 142 $ 69 $ 87 Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2022 2021 2020 2022 2021 2020 2022 2021 2020 Components of net periodic benefit cost: Service cost $ 26,351 $ 26,888 $ 24,337 $ 557 $ 456 $ 756 $ 217 $ 155 $ 190 Interest cost 24,263 22,381 25,180 1,253 1,183 1,464 311 302 368 Expected return on plan assets (51,016) (48,242) (49,910) — — — (379) (355) (389) Amortization of prior service cost (credit) — (1,513) (1,573) 289 349 349 22 6 — Amortization of net loss (gain) 15,080 21,862 19,043 2,648 2,344 2,385 (35) (52) (137) Net periodic benefit cost $ 14,678 $ 21,376 $ 17,077 $ 4,747 $ 4,332 $ 4,954 $ 136 $ 56 $ 32 The following tables summarize Puget Energy's and PSE's benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, 2022, and 2021: Puget Energy Qualified SERP Other (Dollars in Thousands) 2022 2021 2022 2021 2022 2021 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 12,735 $ (61,348) $ (5,260) $ 828 $ (1,468) $ (1,164) Amortization of net (loss) gain (6,381) (11,803) (2,471) (2,164) 29 39 Settlements, mergers, sales, and closures — — (277) (830) — — Prior service cost (credit) — — — — 38 205 Amortization of prior service (cost) credit — 1,904 (289) (349) (22) (6) Total change in other comprehensive income for year $ 6,354 $ (71,247) $ (8,297) $ (2,515) $ (1,423) $ (926) Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2022 2021 2022 2021 2022 2021 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 12,736 $ (61,345) $ (5,260) $ 828 $ (1,468) $ (1,164) Amortization of net (loss) gain (15,080) (21,862) (2,648) (2,343) 35 53 Settlements, mergers, sales, and closures — — (331) (886) — — Prior service cost (credit) — — — — 38 205 Amortization of prior service (cost) credit — 1,513 (289) (349) (22) (6) Total change in other comprehensive income for year $ (2,344) $ (81,694) $ (8,528) $ (2,750) $ (1,417) $ (912) The aggregate expected contributions by the Company to fund the qualified pension plan, SERP and the other postretirement plans for the year ending December 31, 2023, are expected to be at least $18.0 million, $3.5 million and $0.3 million, respectively. Assumptions In accounting for pension and other benefit obligations and costs under the plans, the following weighted-average actuarial assumptions were used by the Company: Qualified SERP Other Benefit Obligation Assumptions: 2022 2021 2020 2022 2021 2020 2022 2021 2020 Discount rate 5.60 % 3.00 % 2.70 % 5.60 % 3.00 % 2.70 % 5.60 % 3.00 % 2.70 % Rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Interest crediting rate 4.00 4.00 4.00 N/A N/A N/A N/A N/A N/A Benefit Cost Assumptions: Discount rate 3.00 2.70 3.35 3.00 2.70 3.35 3.00 2.70 3.35 Return on plan assets 6.50 6.50 7.15 — — — 7.00 7.00 7.00 Rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Interest crediting rate 4.00 4.00 4.00 N/A N/A N/A N/A N/A N/A The Company has selected the expected return on plan assets based on a historical analysis of rates of return and the Company’s investment mix, market conditions, inflation and other factors. The expected rate of return is reviewed annually based on these factors. The Company’s accounting policy for calculating the market-related value of assets for the Company’s retirement plan is based on a five-year smoothing of asset gains (losses) measured from the expected return on market-related assets. This is a calculated value that recognizes changes in fair value in a systematic and rational manner over five years. The same manner of calculating market-related value is used for all classes of assets, and is applied consistently from year to year. Puget Energy’s pension and other postretirement benefits income or costs depend on several factors and assumptions, including plan design, timing and amount of cash contributions to the plan, earnings on plan assets, discount rate, expected long-term rate of return, and mortality trends. Changes in any of these factors or assumptions will affect the amount of income or expense that Puget Energy records in its financial statements in future years and its projected benefit obligation. Puget Energy has selected an expected return on plan assets based on a historical analysis of rates of return and Puget Energy’s investment mix, market conditions, inflation and other factors. As required by merger accounting rules, market-related value was reset to market value effective with the merger. The discount rates were determined by using market interest rate data and the weighted-average discount rate from the FTSE Pension Discount Curve (formerly known as the Citigroup Pension Liability Index Curve). The Company also takes into account in determining the discount rate the expected changes in market interest rates and anticipated changes in the duration of the plan liabilities. The Company's projected benefit obligation for pension plans experienced an actuarial gain of $215.0 million in 2022. This is primarily due to the increase in the discount rate used in measuring the benefit obligation. Plan Benefits The expected total benefits to be paid during the next five years and the aggregate total to be paid for the five years thereafter are as follows: (Dollars in Thousands) 2023 2024 2025 2026 2027 2028-2032 Qualified Pension total benefits $ 46,500 $ 47,800 $ 48,700 $ 49,900 $ 50,700 $ 260,700 SERP Pension total benefits 3,532 1,844 7,634 2,271 10,956 7,479 Other Benefits total 912 890 881 879 854 3,829 Plan Assets Plan contributions and the actuarial present value of accumulated plan benefits are prepared based on certain assumptions pertaining to interest rates, inflation rates and employee demographics, all of which are subject to change. Due to uncertainties inherent in the estimations and assumptions process, changes in these estimates and assumptions in the near term may be material to the financial statements. The Company has a Retirement Plan Committee that establishes investment policies, objectives and strategies designed to balance expected return with a prudent level of risk. All changes to the investment policies are reviewed and approved by the Retirement Plan Committee prior to being implemented. The Retirement Plan Committee invests trust assets with investment managers who have historically achieved above-median long-term investment performance within the risk and asset allocation limits that have been established. Interim evaluations are routinely performed with the assistance of an outside investment consultant. To obtain the desired return needed to fund the pension benefit plans, the Retirement Plan Committee has established investment allocation percentages by asset classes as follows: Allocation Asset Class Minimum Target Maximum Domestic large cap equity 25 % 31 % 40 % Domestic small cap equity — 9 15 Non-U.S. equity 10 25 30 Fixed income 25 35 40 Real estate — — 10 Cash — — 5 Plan Fair Value Measurements ASC 715, “Compensation – Retirement Benefits” (ASC 715) directs companies to provide additional disclosures about plan assets of a defined benefit pension or other postretirement plan. The objectives of the disclosures are to disclose the following: (i) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies; (ii) major categories of plan assets; (iii) inputs and valuation techniques used to measure the fair value of plan assets; (iv) effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period; and (v) significant concentrations of risk within plan assets. ASC 820 allows the reporting entity, as a practical expedient, to measure the fair value of investments that do not have readily determinable fair values on the basis of the net asset value per share of the investment if the net asset value of the investment is calculated in a matter consistent with ASC 946, “Financial Services – Investment Companies”. The standard requires disclosures about the nature and risk of the investments and whether the investments are probable of being sold at amounts different from the net asset value per share. The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, 2022, and 2021: Recurring Fair Value Measures Recurring Fair Value Measures December 31, 2022 December 31, 2021 (Dollars in Thousands) Level 1 Level 2 Other Total Level 1 Level 2 Other Total Assets: Common Stock: Domestic $ 175,969 $ 298 $ — $ 176,267 $ 249,021 $ 99 $ — $ 249,120 Foreign 17,767 — — 17,767 25,963 — — 25,963 Government Securities 61,693 8,828 — 70,521 65,266 2,470 — 67,736 Corporate Securities: Domestic — 16,005 — 16,005 — 12,820 — 12,820 Foreign — 6,525 — 6,525 — 5,239 — 5,239 Cash and cash equivalents 4,678 (632) — 4,046 3,638 (540) — 3,098 Investments measured at NAV: Collective Investment Funds — — 262,910 262,910 — — 359,861 359,861 Partnership — — 86,827 86,827 — — 115,570 115,570 Mutual Funds — — 46,005 46,005 — — 80,724 80,724 Other — — 846 846 — — 1,434 1,434 Net (payable) receivable — — (29,186) (29,186) — — (23,015) (23,015) Total assets $ 260,107 $ 31,024 $ 367,402 $ 658,533 $ 343,888 $ 20,088 $ 534,574 $ 898,550 The following table sets forth by level, within the fair value hierarchy, the Other Benefits plan assets which consist of insurance benefits for retired employees, at fair value: Recurring Fair Value Measures Recurring Fair Value Measures December 31, 2022 December 31, 2021 (Dollars in Thousands) Level 1 Level 2 Other Total Level 1 Level 2 Other Total Assets: Money Markets $ — $ — $ — $ — $ 4 $ — $ — $ 4 Mutual fund — 5,190 — 5,190 — 6,337 — 6,337 Net (payable) receivable — — — — — — — — Total assets $ — $ 5,190 $ — $ 5,190 $ 4 $ 6,337 $ — $ 6,341 The following discussion provides information regarding the methods used in valuation of the various asset class investments held for the pension and other postretirement benefit plans. • Mutual funds classified as Level 1 securities have pricing inputs that are based on unadjusted prices in an active market. Principal markets for equity prices include published exchanges such as NASDAQ and New York Stock Exchange (NYSE). Mutual fund assets not included in the fair value hierarchy are privately held funds. These funds are not actively traded and utilize net asset value (NAV) as a practical expedient to measure fair value. • Common stock investments are traded in active markets on national and international securities exchanges and are valued at closing prices on the last business day of each period presented. They are classified as Level 1 securities. • Corporate and some government debt securities are valued using pricing models maximizing the use of observable inputs for similar securities. This includes basing value on yields currently available on comparable securities of issuers with similar credit ratings. Some government debt securities have quoted prices such as certain treasury securities and are classified as Level 1 securities. • Cash and cash equivalents comprise mostly of money market funds and foreign currency held. Money market funds are classified as Level 1 instruments as pricing inputs are based on unadjusted prices in an active market while foreign currency held is classified as a Level 2 investment based on inputs that are indirectly observable. • Investments in collective trust funds and partnerships are stated at the NAV as determined by the issuer of fund and are based on the fair value of the underlying investments held by the fund less its liabilities. The NAV is used as a practical expedient to estimate fair value. These funds are primarily invested in a blend of corporate and government debt securities as well as international equities. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2022 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | (14) Income Taxes The details of income tax (benefit) expense are as follows: Puget Energy Year Ended December 31, (Dollars in Thousands) 2022 2021 2020 Charged to operating expenses: Current: Federal $ 41,198 $ 25,395 $ 7,962 State 628 721 7 Deferred: Federal 17,866 (1,759) (6,414) State 6 158 109 Total income tax expense $ 59,698 $ 24,515 $ 1,664 Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2022 2021 2020 Charged to operating expenses: Current: Federal $ 81,597 $ 52,616 $ 10,607 State 869 670 383 Deferred: Federal (2,171) (9,027) 15,252 State — — — Total income tax expense $ 80,295 $ 44,259 $ 26,242 The following reconciliation compares pre-tax book income at the federal statutory rate of 21.0% to the actual income tax expense in the Statements of Income: Puget Energy Year Ended December 31, (Dollars in Thousands) 2022 2021 2020 Income taxes at the statutory rate $ 99,549 $ 59,927 $ 38,720 Increase (decrease): Utility plant differences 1 $ (23,028) $ (22,325) $ (22,991) AFUDC, net (3,567) 1,509 (6,095) Executive compensation 1,821 1,386 2,440 Treasury grant amortization (5,717) (5,424) (8,935) Excess deferred tax amortization (13,722) (13,392) (3,038) Other–net 4,362 2,834 1,563 Total income tax expense $ 59,698 $ 24,515 $ 1,664 Effective tax rate 12.6 % 8.6 % 0.9 % Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2022 2021 2020 Income taxes at the statutory rate $ 119,962 $ 79,868 $ 63,110 Increase (decrease): Utility plant differences 1 $ (23,028) $ (22,325) $ (22,991) AFUDC, net (3,567) 1,509 (6,095) Executive compensation 1,821 1,386 2,440 Treasury grant amortization (5,717) (5,424) (8,935) Excess deferred tax amortization (13,722) (13,392) (3,038) Other–net 4,546 2,637 1,751 Total income tax expense $ 80,295 $ 44,259 $ 26,242 Effective tax rate 14.1 % 11.6 % 8.7 % _______________ 1. Utility plant differences include the reversal of excess deferred taxes using the average rate assumption method in the amount of $27.2 million and $27.6 million in 2022 and 2021, respectively. The Company’s net deferred tax liability at December 31, 2022, and 2021, is composed of amounts related to the following types of temporary differences: Puget Energy At December 31, (Dollars in Thousands) 2022 2021 Utility plant and equipment $ 1,853,450 $ 1,892,692 Unrealized gain on derivative instruments 158,175 50,971 Other deferred tax liabilities 365,035 313,270 Subtotal deferred tax liabilities 2,376,660 2,256,933 Net operating loss carryforward (234,825) (254,007) Net regulatory liability for income taxes (811,161) (865,976) Other deferred tax assets (299,597) (184,023) Unrealized loss on derivative instruments (45,130) (40,443) Subtotal deferred tax assets (1,390,713) (1,344,449) Total net deferred tax liabilities $ 985,947 $ 912,484 Puget Sound Energy At December 31, (Dollars in Thousands) 2022 2021 Utility plant and equipment $ 1,852,644 $ 1,892,674 Unrealized gain on derivative instruments 143,147 31,940 Other deferred tax liabilities 279,612 225,753 Subtotal deferred tax liabilities 2,275,403 2,150,367 Net regulatory liability for income taxes (811,724) (866,541) Other deferred tax assets (293,977) (178,211) Unrealized loss on derivative instruments (30,102) (21,412) Subtotal deferred tax assets (1,135,803) (1,066,164) Total net deferred tax liabilities $ 1,139,600 $ 1,084,203 The Company calculates its deferred tax assets and liabilities under ASC 740, “Income Taxes” (ASC 740). ASC 740 requires recording deferred tax balances, at the currently enacted tax rate, on assets and liabilities that are reported differently for income tax purposes than for financial reporting purposes. The utilization of deferred tax assets requires sufficient taxable income in future years. ASC 740 requires a valuation allowance on deferred tax assets when it is more likely than not that the deferred tax assets will not be realized. PSE fully utilized its PTC balance in 2021 and had no carryforwards at the end of 2021. Puget Energy’s net operating loss carryforwards expire from 2029 through 2037. Net operating losses generated in 2018 and thereafter have no expiration date. No valuation allowance has been provided for net operating loss carryforwards. Unrecognized Tax Benefits The Company accounts for uncertain tax positions under ASC 740, which clarifies the accounting for uncertainty in income taxes recognized in the financial statements. ASC 740 requires the use of a two-step approach for recognizing and measuring tax positions taken or expected to be taken in a tax return. First, a tax position should only be recognized when it is more likely than not, based on technical merits, that the position will be sustained upon challenge by the taxing authorities and taken by management to the court of last resort. Second, a tax position that meets the recognition threshold should be measured at the largest amount that has a greater than 50.0% likelihood of being sustained. As of December 31, 2022, and 2021, the Company had no material unrecognized tax benefits. As a result, no interest or penalties were accrued for unrecognized tax benefits during the year. The Company has open tax years from 2019 through 2022. The Company classifies interest as interest expense and penalties as other expense in the financial statements. |
Litigation
Litigation | 12 Months Ended |
Dec. 31, 2022 | |
Jointly Owned Utility Plant Interests | |
Litigation | Litigation From time to time, the Company is involved in litigation or legislative rulemaking proceedings relating to its operations in the normal course of business. The following is a description of pending proceedings that are material to PSE’s operations: Colstrip PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in each of Colstrip Units 3 and 4, which are coal-fired generating units located in Colstrip, Montana. PSE has accelerated the depreciation of Colstrip Units 3 and 4 to December 31, 2025 as part of the 2019 GRC. The 2017 GRC repurposed PTCs and hydro-related treasury grants to recover unrecovered plant costs and to fund and recover decommissioning and remediation costs for Colstrip Units 1 through 4. On September 2, 2022, PSE and Talen Energy reached an agreement to transfer PSE's ownership interest in Colstrip Units 3 and 4 to Talen Energy on December 31, 2025. Management evaluated Colstrip Units 3 and 4 and determined that the applicable held for sale accounting criteria were not met as of December 31, 2022. As such, Colstrip Units 3 and 4 are classified as Electric Utility Plant on the Company's balance sheet as of December 31, 2022. Consistent with a June 2019 announcement, Talen permanently shut down Units 1 and 2 at the end of 2019 due to operational losses associated with the Units. Colstrip Units 1 and 2 were retired effective December 31, 2019. The Washington Clean Energy Transformation Act requires the Washington Commission to provide recovery of the investment, decommissioning, and remediation costs associated with the facilities that are not recovered through the repurposed PTCs and hydro-related treasury grants. The full scope of decommissioning activities and costs may vary from the estimates that are available at this time. On May 19, 2021, PSE along with the Colstrip owners, Avista Corporation, PacifiCorp and Portland General Electric Company filed a lawsuit against the Montana Attorney General challenging the constitutionality of Montana Senate Bill 266. On October 13, 2021, the United States District Court for the District of Montana issued a preliminary injunction finding it likely that Senate Bill 266 unconstitutionally violates the Commerce Clause and Contract Clause of the United States Constitution. Since then, a motion for summary judgment was filed requesting a permanent injunction against enforcement of Senate Bill 266. On September 29, 2022, the magistrate judge in the District Court proceeding issued a recommendation to the presiding U.S. District Court Judge that a permanent injunction against enforcement of Senate Bill 266 be granted. On October 18, 2022, the U.S. District Court Judge accepted in full the magistrate judge recommendation for a permanent injunction against enforcement of Senate Bill 266. Puget LNG |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2020 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and ContingenciesFor the year ended December 31, 2022, approximately 16.4% of the Company’s energy output was obtained at an average cost of approximately $0.034 per Kilowatt Hour (kWh) through long-term contracts with three of the Washington Public Utility Districts (PUDs) that own hydroelectric projects on the Columbia River. The purchase of power from the Columbia River projects is on a pro rata share basis under which the Company pays a proportionate share of the annual debt service, operating and maintenance costs and other expenses associated with each project, in proportion to the contractual share of power that PSE obtains from that project. In these instances, PSE’s payments are not contingent upon the projects being operable; therefore, PSE is required to make the payments even if power is not delivered. These projects are financed substantially through debt service payments and their annual costs should not vary significantly over the term of the contracts unless additional financing is required to meet the costs of major maintenance, repairs or replacements, or license requirements. The Company’s share of the costs and the output of the projects is subject to reduction due to various withdrawal rights of the PUDs and others over the contract lives. The Company's expenses under these PUD contracts were as follows for the years ended December 31: (Dollars in Thousands) 2022 2021 2020 PUD contract costs $ 149,575 $ 117,812 $ 116,874 As of December 31, 2022, the Company purchased portions of the power output of the PUDs' projects as set forth in the following table: Company's Share of (Dollars in Thousands) Contract 2023 Percent of Output 2023 Megawatt Capacity Estimated 2023 Total Costs 2023 Debt Service Costs Interest included in 2023 Debt Service Costs Debt Outstanding Chelan County PUD 1 : Rock Island Project 2031 30.0 % 187 $ 47,892 $ 12,072 $ 5,132 $ 93,493 Rocky Reach Project 2031 30.0 390 54,022 5,039 1,907 33,757 Douglas County PUD 2 : Wells Project 2028 32.8 276 45,489 — — — Grant County PUD 3 : Priest Rapids Development 2052 4.8 45 28,243 747 376 9,768 Wanapum Development 2052 4.8 58 28,243 747 376 9,768 Total 956 $ 203,889 $ 18,605 $ 7,791 $ 146,786 _______________ 1. In March 2021, PSE entered into a new PPA with Chelan County PUD for additional Rocky Reach and Rock Island output. The contract began on January 1, 2022, and continues through December 31, 2026. This agreement increases PSE’s share of output by 5% for each project, which equates to an additional capacity of 31MW for Rock Island and 65MW for Rocky Reach. 2. In March 2021, PSE entered into a new agreement with Douglas County PUD for the extension of the Wells Project Output that began on October 1, 2021, and continues through September 30, 2024. This agreement increases PSE's share of output by 5.5% for the Wells Project, which equates to an additional capacity of 46MW. 3. In November 2022, PSE elected to take its portion of the Priest Rapid Meaningful Priority and was granted 4.13% share of the 2023 Priest Rapids Project output. This one-year contract begins on January 1, 2023, and continues through December 31, 2023. This agreement increases PSE's share of output by 4.13%, which equates to an additional capacity of 39MW for Priest Rapids Development and 51 MW for Wanapum Development. The following table summarizes the Company’s estimated payment obligations for power purchases from the Columbia River projects, electric portfolio contracts and electric wholesale market transactions. These contracts have varying terms and may include escalation and termination provisions. (Dollars in Thousands) 2023 2024 2025 2026 2027 Thereafter Total Columbia River projects $ 191,618 $ 145,078 $ 140,887 $ 138,482 $ 123,152 $ 394,875 $ 1,134,092 Electric portfolio contracts 380,559 385,807 345,257 142,273 133,903 1,776,703 3,164,502 Electric wholesale market transactions 414,278 148,628 11,616 11,616 — — 586,138 Total $ 986,455 $ 679,513 $ 497,760 $ 292,371 $ 257,055 $ 2,171,578 $ 4,884,732 Total purchased power contracts provided the Company with approximately 15.3 million, 13.1 million and 13.2 million MWhs of firm energy at a cost of approximately $892.7 million, $631.4 million and $491.7 million for the years 2022, 2021, and 2020, respectively. Natural Gas Supply Obligations The Company has entered into various firm supply, transportation and storage service contracts in order to ensure adequate availability of natural gas supply for its customers and generation requirements. The Company contracts for its long-term natural gas supply on a firm basis, which means the Company has a 100% daily take obligation and the supplier has a 100% daily delivery obligation to ensure service to PSE’s customers and generation requirements. The transportation and storage contracts, which have remaining terms from 1 year to 22 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. The Company incurred demand charges of $138.3 million, $136.4 million, and $135.8 million for firm transportation, storage and peaking services for its natural gas customers for the years 2022, 2021, and 2020. The Company incurred demand charges of $53.9 million, $52.8 million, and $51.2 million for firm transportation, storage and peaking services for the natural gas supply for its combustion turbines for the years 2022, 2021, and 2020. The following table summarizes the Company’s obligations for future natural gas supply and demand charges through the primary terms of its existing contracts. The quantified obligations are based on the FERC and CER (Canadian Energy Regulator) currently authorized rates, which are subject to change. Natural Gas Supply and Demand Charge Obligations 2023 2024 2025 2026 2027 Thereafter Total Natural gas wholesale market transactions $ 1,013,547 $ 377,588 $ 351,129 $ 255,577 $ 76,453 $ — $ 2,074,294 Firm transportation service 175,136 146,675 112,327 94,417 94,123 570,687 1,193,365 Firm storage service 9,350 7,923 7,448 7,432 7,352 1,838 41,343 Total $ 1,198,033 $ 532,186 $ 470,904 $ 357,426 $ 177,928 $ 572,525 $ 3,309,002 Service Contracts The following table summarizes the Company’s estimated obligations for service contracts through the terms of its existing contracts. Service Contract Obligations 2023 2024 2025 2026 2027 Thereafter Total Energy production service contracts $ 33,971 $ 34,812 $ 35,772 $ 18,728 $ 19,221 $ 79,655 $ 222,159 Automated meter reading system 50,124 47,301 47,668 48,803 — — 193,896 Total $ 84,095 $ 82,113 $ 83,440 $ 67,531 $ 19,221 $ 79,655 $ 416,055 Chelan PUD Power Purchase Agreement On February 7, 2023, PSE and Chelan PUD entered into a new power purchase agreement, under which PSE will continue to purchase 25% of the total output from the Rocky Reach and Rock Island hydroelectric projects from November 1, 2031 through October 31, 2051. Estimated payment obligations under the new power sales agreement total $3.1 billion. Other Commitments and Contingencies For information regarding PSE's environmental remediation obligations, see Note 4, "Regulation and Rates," to the consolidated financial statements included in Item 8 of this report. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2022 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party TransactionsThe Company identified no material related party transactions during the year ended December 31, 2022 and December 31, 2021. |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2022 | |
Segment Reporting [Abstract] | |
Segment Information | Segment InformationPuget Energy and PSE operate one reportable segment referred to as the regulated utility segment. Puget Energy’s regulated utility operation generates, purchases and sells electricity and purchases, transports and sells natural gas. The service territory of PSE covers approximately 6,000 square miles in the state of Washington. |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income (Loss) | 12 Months Ended |
Dec. 31, 2022 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract] | |
Accumulated Other Comprehensive Income (Loss) | Accumulated Other Comprehensive Income (Loss) The following tables present the changes in the Company’s (loss) AOCI by component for the years ended December 31, 2022, 2021, and 2020, respectively: Puget Energy Net unrealized gain (loss) and prior service cost on pension plans Changes in AOCI, net of tax (Dollars in Thousands) Total Balance at December 31, 2019 $ (84,149) $ (84,149) Other comprehensive income (loss) before reclassifications (9,058) (9,058) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 6,770 6,770 Net current-period other comprehensive income (loss) (2,288) (2,288) Balance at December 31, 2020 $ (86,437) $ (86,437) Other comprehensive income (loss) before reclassifications 49,226 49,226 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 9,779 9,779 Net current-period other comprehensive income (loss) 59,005 59,005 Balance at December 31, 2021 $ (27,432) $ (27,432) Other comprehensive income (loss) before reclassifications (4,559) (4,559) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 7,217 7,217 Net current-period other comprehensive income (loss) 2,658 2,658 Balance at December 31, 2022 $ (24,774) $ (24,774) Puget Sound Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on treasury interest rate swaps Changes in AOCI, net of tax (Dollars in Thousands) Total Balance at December 31, 2019 $ (183,108) $ (5,369) $ (188,477) Other comprehensive income (loss) before reclassifications (8,717) — (8,717) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 15,853 385 16,238 Net current-period other comprehensive income (loss) 7,136 385 7,521 Balance at December 31, 2020 $ (175,972) $ (4,984) $ (180,956) Other comprehensive income (loss) before reclassifications 49,265 — 49,265 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 18,166 384 18,550 Net current-period other comprehensive income (loss) 67,431 384 67,815 Balance at December 31, 2021 $ (108,541) $ (4,600) $ (113,141) Other comprehensive income (loss) before reclassifications (4,512) — (4,512) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 14,223 386 14,609 Net current-period other comprehensive income (loss) 9,711 386 10,097 Balance at December 31, 2022 $ (98,830) $ (4,214) $ (103,044) Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2022, 2021, and 2020, respectively, are as follows: Puget Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented Amount reclassified from accumulated 2022 2021 2020 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ (311) $ 1,549 $ 1,631 Amortization of net gain (loss) (a) (8,824) (13,928) (10,200) Total before tax (9,135) (12,379) (8,569) Tax (expense) or benefit 1,918 2,600 1,799 Net of tax (7,217) (9,779) (6,770) Total reclassification for the period Net of tax $ (7,217) $ (9,779) $ (6,770) __________ (a) These AOCI components are included in the computation of net periodic pension cost, see Note 13, "Retirement Benefits," to the consolidated financial statements included in Item 8 of this report for additional details. Puget Sound Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented Amount reclassified from accumulated 2022 2021 2020 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ (311) $ 1,158 $ 1,224 Amortization of net gain (loss) (a) (17,693) (24,153) (21,291) Total before tax (18,004) (22,995) (20,067) Tax (expense) or benefit 3,781 4,829 4,214 Net of tax (14,223) (18,166) (15,853) Net unrealized gain (loss) on treasury interest rate swaps: Interest rate contracts Interest expense (488) (487) (487) Tax (expense) or benefit 102 103 102 Net of tax (386) (384) (385) Total reclassification for the period Net of tax $ (14,609) $ (18,550) $ (16,238) ____________ (a) These AOCI components are included in the computation of net periodic pension cost, see Note 13, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details. |
SCHEDULE I CONDENSED FINANCIAL
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY | 12 Months Ended |
Dec. 31, 2022 | |
Condensed Financial Information Disclosure [Abstract] | |
Schedule I: Condensed Financial Information of Puget Energy | SCHEDULE I: CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY Puget Energy Condensed Statements of Income and Comprehensive Income (Loss) (Dollars in Thousands) Year Ended December 31, 2022 2021 2020 Non-utility expense and other $ (1,206) $ (913) $ (1,579) Other income (deductions): Equity in earnings of subsidiary 474,873 337,405 277,654 Interest income 8,458 4,261 4,760 Interest expense (84,051) (100,002) (123,592) Income tax benefit (expense) 16,271 20,098 25,474 Net income (loss) $ 414,345 $ 260,849 $ 182,717 Comprehensive income (loss) $ 417,003 $ 319,854 $ 180,429 See accompanying notes to the condensed financial statements. Puget Energy Condensed Balance Sheets (Dollars in Thousands) December 31, 2022 2021 Assets: Investment in subsidiaries $ 4,938,998 $ 4,446,758 Other property and investments: Goodwill 1,656,513 1,656,513 Current assets: Cash 1,528 6,386 Receivables from affiliates 1 246,317 233,258 Income tax receivables 532 6,006 Total current assets 248,377 245,650 Long-term assets: Deferred income taxes 231,976 250,820 Other 3,370 984 Total long-term assets 235,346 251,804 Total assets $ 7,079,234 $ 6,600,725 Capitalization and liabilities: Common equity $ 4,964,089 $ 4,563,316 Long-term debt 2,020,734 1,571,287 Total capitalization 6,984,823 6,134,603 Current liabilities: Accounts payable to affiliates 1 133 147 Short-term debt 84,300 — Current maturities of long-term debt — 450,000 Interest 9,978 15,975 Total current liabilities 94,411 466,122 Commitments and contingencies (Note 16) Total capitalization and liabilities $ 7,079,234 $ 6,600,725 _______________ 1 Eliminated in consolidation. See accompanying notes to the condensed financial statements. Puget Energy Condensed Statements of Cash Flows (Dollars in Thousands) Year Ended December 31, 2022 2021 2020 Operating activities: Net cash provided by (used in) operating activities $ (10,197) $ 143,691 $ 38,280 Investing activities: Investment in subsidiaries (50,000) (21,783) — (Increase) decrease in loan to subsidiary (12,176) — (31,043) Net cash provided by (used in) investing activities (62,176) (21,783) (31,043) Financing activities: Dividends paid (16,230) (106,420) (45,421) Investment from Parent — 210,000 4,575 Change in short-term debts, net 84,300 — — Issuance of long-term debts 448,075 515,475 644,690 Redemption of long-term debts (450,000) (734,000) (609,400) Issue costs and others 1,370 (1,367) (1,838) Net cash provided by (used in) by financing activities 67,515 (116,312) (7,394) Increase (decrease) in cash (4,858) 5,596 (157) Cash at beginning of year 6,386 790 947 Cash at end of year $ 1,528 $ 6,386 $ 790 See accompanying notes to the condensed financial statements. NOTES TO CONDENSED FINANCIAL STATEMENTS (1) Basis of Presentation Puget Energy is an energy services holding company that conducts substantially all of its business operations through its regulated subsidiary, PSE. Puget Energy also has a wholly-owned non-regulated subsidiary, named Puget LNG, LLC (Puget LNG). Puget LNG was formed in November 2016, and has the sole purpose of owning, developing and financing the non-regulated activity of a liquefied natural gas (LNG) facility at the Port of Tacoma, Washington. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These financial statements, in which Puget Energy’s subsidiaries have been included using the equity method, should be read in conjunction with the consolidated financial statements and notes thereto of Puget Energy included in Item 8, "Financial Statements and Supplementary Data" of this report. Puget Energy owns 100% of the common stock of its subsidiaries. Equity earnings of subsidiary included earnings from PSE and PLNG of $473.8 million, $335.0 million and $274.3 million for the years ended December 31, 2022, 2021, and 2020, respectively, and business combination accounting adjustments under ASC 805 recorded at Puget Energy for PSE of $1.0 million, $2.4 million and $3.4 million for the years ended December 31, 2022, 2021, and 2020, respectively. Investment in subsidiaries includes Puget Energy business combination accounting adjustments under ASC 805 that are recorded at Puget Energy. (2) Long-Term Debt For information concerning Puget Energy’s long-term debt obligations, see Note 7, "Long-Term Debt" to the consolidated financial statements included in Item 8 of this report. (3) Commitments and Contingencies For information concerning Puget Energy’s material contingencies and guarantees, see Note 16, "Commitments and Contingencies" to the consolidated financial statements included in Item 8 of this report. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation Puget Energy is an energy services holding company that owns Puget Sound Energy (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma liquefied natural gas (LNG) facility. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that are incurred by PSE and allocated to Puget LNG are related party transactions by nature. In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any ASC 805, “Business Combinations” (ASC 805) purchase accounting adjustments. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. |
Utility Plant | Utility Plant Puget Energy and PSE capitalize, at original cost, additions to utility plant, including renewals and betterments. Costs include indirect costs such as engineering, supervision, certain taxes, pension and other employee benefits and an allowance for funds used during construction (AFUDC). Replacements of minor items of property are included in maintenance expense. When the utility plant is retired and removed from service, the original cost of the property is charged to accumulated depreciation and costs associated with removal of the property, less salvage, are charged to the cost of removal regulatory liability. Planned Major Maintenance Planned major maintenance is an activity that typically occurs when PSE overhauls or substantially upgrades various systems and equipment on a scheduled basis. Costs related to planned major maintenance are deferred and amortized to the next scheduled major maintenance. This accounting method also follows the Washington Utilities and Transportation Commission (Washington Commission) regulatory treatment related to these generating facilities. Other Property and Investments For PSE, the costs of other property and investments (i.e., non-utility) are stated at historical cost. Expenditures for refurbishment and improvements that significantly add to productive capacity or extend useful life of an asset are capitalized. Replacements of minor items are expensed on a current basis. Gains and losses on assets sold or retired, which were previously recorded in utility plant, are apportioned between regulatory assets/liabilities and earnings. However, gains and losses on assets sold or retired, not previously recorded in utility plant, are reflected in earnings. |
Depreciation and Amortization | Depreciation and Amortization The Company provides for depreciation and amortization on a straight-line basis. Amortization is recorded for intangibles such as regulatory assets and liabilities, computer software and franchises. The annual depreciation provision stated as a percent of a depreciable electric utility plant was 3.4%, 3.4%, and 3.5% in 2022, 2021, and 2020, respectively; depreciable natural gas utility plant was 2.9%, 2.8%, and 2.9% in 2022, 2021, and 2020, respectively; and depreciable common utility plant |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents consist of demand bank deposits and short-term highly liquid investments with original maturities of three months or less at the time of purchase. The carrying amounts of cash and cash equivalents are reported at cost and approximate fair value, due to the short-term maturity. |
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy | Restricted Cash Restricted cash amounts primarily represent cash posted as collateral for derivative contracts as well as funds required to be set aside for contractual obligations related to transmission and generation facilities. |
Materials and Supplies | Materials and Supplies Materials and supplies are used primarily in the operation and maintenance of electric and natural gas distribution and transmission systems as well as spare parts for combustion turbines used for the generation of electricity. The Company records these items at weighted-average cost. |
Fuel and Gas Inventory | Fuel and Natural Gas InventoryFuel and natural gas inventory is used in the generation of electricity and for future sales to the Company’s natural gas customers. Fuel inventory consists of coal, diesel and natural gas used for generation. Natural gas inventory consists of natural gas and LNG held in storage for future sales. The Company records fuel inventory and natural gas inventory for unregulated operations at the lower of cost or net realizable value and natural gas inventory for regulated operations at average cost. |
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities PSE accounts for its regulated operations in accordance with ASC 980, “Regulated Operations” (ASC 980). ASC 980 requires PSE to defer certain costs or losses that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. It similarly requires deferral of revenues or gains that are expected to be returned to customers in the future. Accounting under ASC 980 is appropriate as long as rates are established by or subject to approval by independent third-party regulators; rates are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that rates set at levels that will recover costs can be charged to and collected from customers. In most cases, PSE classifies regulatory assets and liabilities as long-term when amortization periods extend longer than one year. For further details regarding regulatory assets and liabilities, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report. Puget Energy recorded regulatory assets and liabilities at the time of the merger related to power purchase contracts. |
Allowance for Funds Used During Construction | Allowance for Funds Used During Construction AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. The amount of AFUDC recorded in each accounting period varies depending primarily upon the level of construction work in progress and the AFUDC rate used. AFUDC is capitalized as a part of the cost of utility plant; the AFUDC debt portion is credited to interest expense, while the AFUDC equity portion is credited to other income. Cash inflow related to AFUDC does not occur until these charges are reflected in rates. The AFUDC rate authorized by the Washington Commission for natural gas and electric utility plant additions effective December 19, 2017, was 7.60%. Effective October 1, 2020 for natural gas and October 15, 2020 for electric the authorized AFUDC rate is 7.39%. The Washington Commission authorized the Company to calculate AFUDC using its allowed rate of return. To the extent amounts calculated using this rate exceed the AFUDC calculated rate using the Federal Energy Regulatory Commission (FERC) formula, PSE capitalizes the excess as a deferred asset, crediting other income. The deferred asset is being amortized over the average useful life of PSE’s non-project electric utility plant which is approximately 30 years. |
Revenue Recognition | Revenue Recognition Operating utility revenue is recognized when the basis of services is rendered, which includes estimated unbilled revenue. Revenue from retail sales is billed based on tariff rates approved by the Washington Commission. PSE's estimate of unbilled revenue is based on a calculation using meter readings from its automated meter reading system. The estimate calculates unbilled usage at the end of each month as the difference between the customer meter readings on the last day of the month and the last customer meter readings billed. The unbilled usage is then priced at published rates for each tariff rate schedule to estimate the unbilled revenues by customer. PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $292.8 million, $268.5 million and $240.8 million for 2022, 2021, and 2020, respectively. The Company reports the collection of such taxes on a gross basis in operation revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income. PSE's electric and natural gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, natural gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. The mechanism mitigates volatility in revenue and gross margin erosion due to weather and energy efficiency. Any differences in revenue are deferred to a regulatory asset for under recovery or regulatory liability for over recovery under alternative revenue recognition standard. Revenue is recognized under this program when deemed collectible within 24 months based on alternative revenue recognition guidance. Decoupled rate increases are effective May 1 of each year subject to a soft rate cap of total revenue for decoupled rate schedules, where rate cap is applied to under-collected revenue and any over-collected revenues are passed back to customers at 100%. Any excess under-recovered revenue above the rate cap will be included in the following year's decoupled rate and the Company will only be able to recognize revenue below the rate cap of total revenue for decoupled rate schedules. For revenue deferrals exceeding the annual rate cap of total revenue for decoupled rate schedules, the Company will assess the excess amount to determine its ability to be collected within 24 months per GAAP rules. The soft rate cap test, which limits the amount of revenues PSE can collect in its annual filings, is 5.0% for natural gas customers and 3.0% for electric customers. The Company will not record any decoupling revenue that is expected to take longer than 24 months to collect following the end of the annual period in which the revenues would have otherwise been recognized. Once determined to be collectible within 24 months, any previously non-recognized amounts will be recognized. Revenues associated with energy costs under the power cost adjustment (PCA) mechanism and purchased gas adjustment (PGA) mechanism are excluded from the decoupling mechanism. |
Allowance for Doubtful Accounts | Allowance for Credit Losses The Company measures expected credit losses on trade receivables on a collective basis by receivable type, which include electric retail receivables, gas retail receivables, and electric wholesale receivables. The estimate of expected credit losses considers historical credit loss information that is adjusted for current conditions and reasonable and supportable forecasts. The following table presents the activity in the allowance for credit losses for accounts receivable at December 31, 2022, and 2021: Puget Energy and (Dollars in Thousands) Year Ended December 31, Allowance for credit losses: 2022 2021 Beginning balance $ 34,958 20,080 Provision for credit loss expense 1 28,316 27,204 Receivables charged-off (21,312) (12,326) Total ending allowance balance $ 41,962 $ 34,958 1 $7.1 million and $2.8 million of provision were deferred as cost specific to COVID-19 in 2022 and 2021, respectively. |
Federal Income Taxes | Federal Income Taxes For presentation in Puget Energy's and PSE’s separate financial statements, income taxes are allocated to the subsidiaries on the basis of separate company computations of tax, modified by allocating certain consolidated group limitations which are attributed to the separate company. Taxes payable or receivable are settled with Puget Holdings, which is the ultimate taxpayer. |
Natural Gas Off System Sales and Capacity Release | Natural Gas Off-System Sales and Capacity Release PSE contracts for firm natural gas supplies and holds firm transportation and storage capacity sufficient to meet the expected peak winter demand for natural gas by its firm customers. Due to the variability in weather, winter peaking consumption of natural gas by most of its customers and other factors, PSE holds contractual rights to natural gas supplies and transportation and storage capacity in excess of its average annual requirements to serve firm customers on its distribution system. For much of the year, there is excess capacity available for third-party natural gas sales, exchanges and capacity releases. PSE sells excess natural gas supplies, enters into natural gas supply exchanges with third parties outside of its distribution area and releases to third parties excess interstate natural gas pipeline capacity and natural gas storage rights on a short-term basis to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. The proceeds from such activities, net of transactional costs, are accounted for as reductions in the cost of purchased natural gas and passed on to customers through the PGA mechanism, with no direct impact on net income. As a result, PSE nets the sales revenue and associated cost of sales for these transactions in purchased natural gas. |
Non-Core Gas Sales | As part of the Company’s electric operations, PSE purchases natural gas for its gas-fired generation facilities. The projected volume of natural gas for power is relative to the price of natural gas. Based on the market prices for natural gas, PSE may use the natural gas it has already purchased to generate power or PSE may sell the already purchased natural gas. The net proceeds from selling natural gas, previously purchased for power generation, are accounted for in electric operating revenue and are included in the PCA mechanism. |
Production Tax Credit | Production Tax Credit Production Tax Credits (PTCs) represent federal income tax incentives available to taxpayers that generate energy from qualifying renewable sources during the first ten years of operation. Before the 2017 GRC, the tax savings from these credits were intended to be refunded by PSE to its customers when monetized, used on the income tax return, through its revenue requirement as initially approved by the Washington Commission. As the Company had not generated taxable income with which to monetize the credits, they had not been refunded to customers. Amounts to be refunded have been recorded as a regulatory liability with an offsetting reduction to revenue as it was intended to be refunded through the revenue requirement. A deferred tax asset and reduction to deferred tax expense were also recorded for the regulatory liability. These entries resulted |
Accounting for Derivatives | Accounting for Derivatives ASC 815, "Derivatives and Hedging" (ASC 815) requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value unless the contracts qualify for an exception. PSE enters into derivative contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts and swaps. Some of PSE’s physical electric supply contracts qualify for the normal purchase normal sale (NPNS) exception to derivative accounting rules. PSE may enter into financial fixed price contracts to economically hedge the variability of certain index-based contracts. Those contracts that do not meet the NPNS exception are marked-to-market to current earnings in the statements of income, subject to deferral under ASC 980, for natural gas related derivatives due to the PGA mechanism. For additional information, see Note 10, "Accounting for Derivative Instruments and Hedging Activities" to the consolidated financial statements included in Item 8 of this report. |
Fair Value Measurements of Derivatives | Fair Value Measurements of Derivatives ASC 820, “Fair Value Measurements and Disclosures” (ASC 820), defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). As permitted under ASC 820, the Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements as it believes that the approach is used by market participants for these types of assets and liabilities. Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company values derivative instruments based on daily quoted prices from an independent external pricing service. When external quoted market prices are not available for derivative contracts, the Company uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves. All derivative instruments are sensitive to market price fluctuations that can occur on a daily basis. For additional information, see Note 11, "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report. |
Debt Related Costs | Debt-Related Costs Debt premiums, discounts, expenses and amounts received or incurred to settle hedges are amortized over the life of the related debt for the Company. The premiums and costs associated with reacquired debt are deferred and amortized over the life of the related new issuance, in accordance with ratemaking treatment for PSE and presented net of long-term liabilities on the balance sheet. |
Lessee, Leases | Leases PSE determines if an arrangement is, or contains, a lease at inception of the contract. If the arrangement is, or contains a lease, PSE assesses whether the lease is operating or financing for income statement and balance sheet classification. Operating leases are included in operating lease right-of-use (ROU) assets, operating lease current liabilities, and operating lease liabilities in our consolidated balance sheets. Finance leases are included in utility plant, other current liabilities, and finance lease liabilities in our consolidated balance sheets. ROU assets represent the right to use an underlying asset for the lease term, and consist of the amount of the initial measurement of the lease liability, any lease payments made to the lessor at or before the commencement date, minus any lease incentives received, and any initial direct costs incurred by the lessee. Lease liabilities represent our obligation to make lease payments arising from the lease and are measured at present value of the lease payments not yet paid, discounted using the discount rate for the lease, determined based on PSE's incremental borrowing rate, at commencement. As most of PSE's leases do not provide an implicit interest rate, PSE uses the incremental borrowing rate based on the information available at |
Consolidation, Variable Interest Entity, Policy | Variable Interest Entities On April 12, 2017, PSE entered into a Power Purchase Agreement (PPA) with Skookumchuck Wind Energy Project, LLC (Skookumchuck) in which Skookumchuck would develop a wind generation facility and, once completed, sell bundled energy and associated attributes, namely renewable energy credits to PSE over a term of 20 years. Skookumchuck commenced commercial operation in November 2020. PSE has no equity investment in Skookumchuck but is Skookumchuck’s only customer. Based on the terms of the contract, PSE will receive all of the output of the facility, subject to curtailment rights. PSE has concluded that it is not the primary beneficiary of this VIE since it does not control the commercial and operating activities of the facility. Additionally, PSE does not have the obligation to absorb losses or receive benefits. Therefore, PSE will not consolidate the VIE. Purchased energy of $14.6 million was recognized in purchased electricity on the Company's consolidated statements of income for the year ended December 31, 2022 and $1.4 million is included in accounts payable on the Company's consolidated balance sheet for the year ended December 31, 2022. Purchased energy of $19.0 million was recognized in purchased electricity on the Company's consolidated statements of income and $2.7 million included in accounts payable on the Company's consolidated balance sheet for the year ended December 31, 2021. On May 28, 2020, PSE entered into a PPA with Golden Hills Wind Farm, LLC (Golden Hills) pursuant to which Golden Hills would develop a wind generation facility and, once completed, sell bundled energy and associated attributes, namely RECs to PSE over a term of 20 years. On April 29, 2022, Golden Hills commenced commercial operations. PSE has no equity investment in Golden Hills but is Golden Hills’s only customer. Based on the terms of the contract, PSE will receive all of the output of the facility, subject to curtailment rights. PSE has concluded that Golden Hills is a VIE and that PSE is not the primary beneficiary of this VIE since it does not control the commercial and operating activities of the facility. Additionally, PSE does not have the obligation to absorb losses or receive benefits. Therefore, PSE will not consolidate the VIE. Purchased energy of $18.3 million was recognized in purchased electricity on the Company's consolidated statements of income for the year ended December 31, 2022. There was no balance in accounts payable on the Company's balance sheet as of December 31, 2022. On February 3, 2021, PSE entered into a PPA with Clearwater Wind Project, LLC (Clearwater) in which Clearwater will develop a wind generation facility on a site located in Rosebud, Custer and Garfield counties, Montana; and, once completed, sell energy and associated attributes to PSE over a term of 25 years. On November 8th, 2022, Clearwater commenced commercial operations. PSE has no equity investment in Clearwater but is Clearwater’s only customer. Based on the terms of the contract, PSE will receive all of the output of the facility, subject to curtailment rights. PSE has concluded that Clearwater is a VIE and that PSE is not the primary beneficiary of this VIE since it does not control the commercial and operating activities of the facility. Additionally, PSE does not have the obligation to absorb losses or receive benefits. Therefore, PSE will not consolidate the VIE. Purchased energy of $5.7 million was recognized in purchased electricity on the Company's consolidated statements of income for the year ended December 31, 2022. Additionally, $2.5 million was included in accounts payable on the Company's balance sheet as of December 31, 2022. |
Self Insurance Reserve | Self-Insurance PSE is self-insured for storm damage and certain environmental contamination associated with current operations occurring on PSE-owned property. In addition, PSE is required to meet a deductible for a portion of the risk associated with comprehensive liability, workers’ compensation claims and catastrophic property losses other than those which are storm related. The cumulative annual cost threshold for deferral of storms under the mechanism is $10.0 million. Additionally, costs may only be deferred if the outage meets the Institute of Electrical and Electronics Engineers outage criteria for system average interruption duration index and qualifying costs exceed $0.5 million per qualified storm. |
Accounting Policies (Tables)
Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Accounts Receivable, Allowance for Credit Loss | The following table presents the activity in the allowance for credit losses for accounts receivable at December 31, 2022, and 2021: Puget Energy and (Dollars in Thousands) Year Ended December 31, Allowance for credit losses: 2022 2021 Beginning balance $ 34,958 20,080 Provision for credit loss expense 1 28,316 27,204 Receivables charged-off (21,312) (12,326) Total ending allowance balance $ 41,962 $ 34,958 1 $7.1 million and $2.8 million of provision were deferred as cost specific to COVID-19 in 2022 and 2021, respectively. |
Revenue (Tables)
Revenue (Tables) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Revenue from Contract with Customer [Abstract] | |||
Disaggregation of Revenue [Table Text Block] | The following tables present disaggregated revenue from contracts with customers, and other revenue by major source for the years ended December 31, 2022, December 31, 2021, and December 31, 2020: Puget Energy and (Dollars in Thousands) Year Ended December 31, 2022 Revenue from contracts with customers: Electric Natural Gas Other 1 Total Retail Residential $ 1,381,858 $ 808,376 $ — $ 2,190,234 Commercial 981,170 352,243 — 1,333,413 Industrial 116,712 25,096 — 141,808 Other 18,759 — — 18,759 Wholesale 319,380 — — 319,380 Transmission and transportation 47,027 20,332 — 67,359 Miscellaneous 13,065 718 50,069 63,852 Total revenue from contracts with customers $ 2,877,971 $ 1,206,765 $ 50,069 $ 4,134,805 Total other revenue 2 83,486 2,871 — 86,357 Total operating revenue $ 2,961,457 $ 1,209,636 $ 50,069 $ 4,221,162 _____________ 1 Other includes $5.0 million of Puget LNG revenues recorded at Puget Energy. 2 Total other revenue includes revenues from derivatives and alternative revenue programs that are not considered revenues from contracts with customers. | Puget Energy and (Dollars in Thousands) Year Ended December 31, 2021 Revenue from contracts with customers: Electric Natural Gas Other Total Retail Residential $ 1,318,326 $ 722,003 $ — $ 2,040,329 Commercial 902,928 292,275 — 1,195,203 Industrial 108,267 21,741 — 130,008 Other 18,834 392 — 19,226 Wholesale 161,152 — — 161,152 Transmission and transportation 43,753 20,030 — 63,783 Miscellaneous 47,948 9,863 66,620 124,431 Total revenue from contracts with customers $ 2,601,208 $ 1,066,304 $ 66,620 $ 3,734,132 Total other revenue 1 70,415 1,114 — 71,529 Total operating revenue $ 2,671,623 $ 1,067,418 $ 66,620 $ 3,805,661 _____________ 1 Total other revenue includes revenues from derivatives, PTC deferral revenue and alternative revenue programs that are not considered revenues from contracts with customers. | Puget Energy and (Dollars in Thousands) Year Ended December 31, 2020 Revenue from contracts with customers: Electric Natural Gas Other Total Retail Residential $ 1,186,012 $ 662,503 $ — $ 1,848,515 Commercial 791,898 251,740 — 1,043,638 Industrial 101,567 18,592 — 120,159 Other 26,644 5,227 — 31,871 Wholesale 66,345 — — 66,345 Transmission and transportation 38,073 19,555 — 57,628 Miscellaneous 25,007 3,107 26,121 54,235 Total revenue from contracts with customers $ 2,235,546 $ 960,724 $ 26,121 $ 3,222,391 Total other revenue 1 83,870 20,189 — 104,059 Total operating revenue $ 2,319,416 $ 980,913 $ 26,121 $ 3,326,450 _____________ 1 Total other revenue includes revenues from derivatives, PTC deferral revenue and alternative revenue programs that are not considered revenues from contracts with customers. |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | Based on management’s best estimate of commencement, the Company expects to recognize this revenue over the following time periods: Puget Energy (Dollars in Thousands) 2024 2025 2026 2027 2028 Thereafter Total Remaining Performance Obligations $ 15,359 19,710 19,454 19,454 19,454 102,135 $ 195,566 |
Regulation and Rates (Tables)
Regulation and Rates (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Regulatory Assets [Line Items] | |
Schedule of Net Regulatory Assets and Liabilities | Puget Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2022 2021 Total PSE regulatory assets (a) $ 896,438 $ 952,539 Puget Energy acquisition adjustments: Regulatory assets related to power contracts 3 to 30 years 7,904 9,689 Total Puget Energy regulatory assets 904,342 962,228 Total PSE regulatory liabilities (a) (1,961,139) (1,709,461) Puget Energy acquisition adjustments: Deferred income taxes 563 565 Regulatory liabilities related to power contracts 3 to 30 years (63,660) (80,934) Various other regulatory liabilities Varies (1,264) (1,264) Total Puget Energy regulatory liabilities (2,025,500) (1,791,094) Puget Energy net regulatory asset (liabilities) $ (1,121,158) $ (828,866) ____________________ (a) Puget Energy’s regulatory assets and liabilities include purchase accounting adjustments under ASC 805. |
Subsidiaries [Member] | |
Regulatory Assets [Line Items] | |
Schedule of Net Regulatory Assets and Liabilities | The net regulatory assets and liabilities at December 31, 2022, and 2021, are included the following tables: Puget Sound Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2022 2021 Environmental remediation (a) $ 141,893 $ 127,977 Storm damage costs electric 3 to 5 years 127,524 127,789 PCA mechanism N/A 112,207 79,546 Chelan PUD contract initiation 8.8 years 62,611 69,699 Deferred Washington Commission AFUDC 30 years 61,463 62,244 Baker Dam licensing operating and maintenance costs (b) 55,049 54,525 Get to zero depreciation expense deferral (c) 1 to 4 years 49,605 50,220 Lower Snake River 14.4 years 48,536 53,757 Decoupling deferrals and interest (d) Less than 2 years 36,773 79,125 Unamortized loss on reacquired debt 1 to 45 years 33,732 35,805 Advanced metering infrastructure 3 years 30,431 23,037 Washington Commission LNG N/A 25,188 1,764 PGA receivable 2 years — 57,935 Generation plant major maintenance, excluding Colstrip 3 to 7 years 20,374 12,094 Low Income Program Costs N/A 17,370 21,755 Property tax tracker Less than 2 years 12,398 25,896 Energy conservation costs (a) 10,296 3,573 Washington Commission electric vehicle (c) 4 years 7,796 6,109 Regulatory filing fee deferral N/A 7,559 — Snoqualmie licensing operating and maintenance costs (b) 7,445 7,446 Washington Commission COVID-19 N/A 7,051 3,657 Water heater rental property loss N/A 5,725 5,725 Mint Farm ownership and operating costs 2.3 years 4,317 6,318 Colstrip major maintenance (c) 3 years 4,035 4,035 Various other regulatory assets (a) 7,060 32,508 Total PSE regulatory assets $ 896,438 $ 952,539 Deferred income taxes (e) N/A (811,724) (866,541) Cost of removal (f) (639,320) (563,129) PGA unrealized gain N/A (287,725) (60,728) Repurposed production tax credits N/A (133,855) (134,270) Decoupling liability Less than 2 years (63,206) (36,506) Green direct N/A (11,837) (13,194) Refund on counterparty settlement 1 year (4,353) — PGA liability 2 years (3,536) — Various other regulatory liabilities (a) (5,583) (35,093) Total PSE regulatory liabilities (1,961,139) (1,709,461) PSE net regulatory assets (liabilities) $ (1,064,701) $ (756,922) __________________ (a) Amortization periods vary depending on timing of underlying transactions. (b) The FERC license requires PSE to incur various O&M expenses over the life of the 40 year and 50 year license for Snoqualmie and Baker, respectively. The regulatory asset represents the net present value of future expenditures and will be offset by actual costs incurred. (c) Amortization period approved in 2022 GRC, beginning January 2023. (d) Decoupling deferrals and interest includes a 24 month GAAP reserve of zero and $3.0 million for December 31, 2022 and 2021, respectively. (e) For additional information, see Note 14,"Income Taxes" to the consolidated financial statements included in Item 8 of this report. (f) The balance is dependent upon the cost of removal of underlying assets and the life of utility plant. . |
Schedule of Graduated Scale of Rate Adjustment Mechanism | Effective January 1, 2017, the following graduated scale is used in the PCA mechanism: Company’s Share Customers' Share Annual Power Cost Variability Over Under Over Under Over or Under Collected by up to $17 million 100 % 100 % — % — % Over or Under Collected by between $17 million - $40 million 35 50 65 50 Over or Under Collected beyond $40 + million 10 10 90 90 |
Schedule of PGA Receivable Payable | The following table presents the PGA mechanism balances and activity at December 31, 2022 and December 31, 2021: Puget Energy and (Dollars in Thousands) At December 31, At December 31, PGA receivable balance and activity 2022 2021 PGA receivable beginning balance $ 57,935 $ 87,655 Actual natural gas costs 457,950 364,775 Allowed PGA recovery (496,879) (396,236) Interest 1,674 1,741 Refund from counterparty settlement (24,216) — PGA (liability)/receivable ending balance $ (3,536) $ 57,935 |
Utility Plant (Tables)
Utility Plant (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Utility Plant [Abstract] | |
Schedule of Utility Plant | The following table presents electric, natural gas and common utility plant classified by account: Puget Energy Puget Sound Energy Utility Plant Estimated Useful Life 1 December 31, December 31, (Dollars in Thousands) (Years) 2022 2021 2022 2021 Distribution plant 7-65 $ 7,886,665 $ 7,488,629 $ 9,406,017 $ 9,026,042 Production plant 3-90 3,131,578 3,147,987 3,780,910 3,815,599 Transmission plant 44-75 1,576,916 1,556,666 1,683,737 1,663,559 General plant 5-75 735,298 746,758 760,094 773,662 Intangible plant (including capitalized software) 2 3-50 755,430 797,691 745,973 788,240 Plant acquisition adjustment N/A 242,826 242,826 282,792 282,792 Underground storage 25-60 45,305 43,391 58,716 56,820 Liquefied natural gas storage 25-50 12,628 12,628 14,498 14,498 Plant held for future use N/A 46,079 46,020 46,232 46,172 Recoverable Cushion Gas N/A 8,784 8,655 8,784 8,655 Plant not classified N/A 723,383 316,933 723,383 316,933 Finance leases, net of accumulated amortization 3 N/A 99,967 105,020 99,967 105,020 Less: accumulated provision for depreciation (4,341,789) (4,031,458) (6,688,033) (6,416,246) Subtotal $ 10,923,070 $ 10,481,746 $ 10,923,070 $ 10,481,746 Construction work in progress 861,801 870,204 861,801 870,204 Net utility plant $ 11,784,871 $ 11,351,950 $ 11,784,871 $ 11,351,950 _______________________ 1. Estimated Useful Life years have been approved in the 2022 GRC. 2. Intangible assets include capitalized software and franchise agreements with useful lives ranging between 3-10 years and 10-50 years, respectively. 3. At December 31, 2022, and 2021, accumulated amortization of finance leases at Puget Energy and PSE was $7.3 million and $2.6 million, respectively. |
Schedule of Jointly Owned Utility Plants | Jointly owned generating plant service costs are included in utility plant service cost at the Company's ownership share. The Company provides financing for its ownership interest in the jointly owned utility plants. The following tables indicate the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2022. These amounts are also included in the Utility Plant table above, with the exception of Puget Energy's portion of the Tacoma LNG facility, which is reported in the Puget Energy "Other property and investments" financial statement line item. The Company's share of fuel costs and operating expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income. Puget Energy Jointly Owned Generating Plants Energy Source (Fuel) Company’s Ownership Share Plant in Service at Cost Construction Work in Progress Accumulated Depreciation Colstrip Units 3 & 4 Coal 25.00% $ 321,767 $ — $ (176,847) Frederickson 1 Natural Gas 49.85 63,348 — (21,894) Jackson Prairie Natural Gas 33.34 44,708 837 (12,178) Tacoma LNG Natural Gas various 494,795 2,936 (10,922) Puget Sound Energy Jointly Owned Generating Plants Energy Source (Fuel) Company’s Ownership Share Plant in Service at Cost Construction Work in Progress Accumulated Depreciation Colstrip Units 3 & 4 Coal 25.00 % $ 579,019 $ — $ (434,099) Frederickson 1 Natural Gas 49.85 69,415 — (27,962) Jackson Prairie Natural Gas 33.34 58,716 837 (26,186) Tacoma LNG Natural Gas various 245,690 503 (5,052) |
Schedule of Asset Retirement Obligations | Puget Energy and Puget Sound Energy December 31, (Dollars in Thousands) 2022 2021 Asset retirement obligation at beginning of the period $ 209,041 $ 216,163 Relief of liability (6,867) (13,146) Revisions in estimated cash flows 1,519 (46) Accretion expense 5,713 6,070 Asset retirement obligation at end of period 1 $ 209,406 $ 209,041 ___________________ 1. Asset retirement obligations include $3.8 million and $3.7 million for Puget LNG held only at Puget Energy as of December 31, 2022, and 2021, respectively. |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Long-Term Debt, Unclassified [Abstract] | |
Schedule of Long-Term Debt Instruments | The following table presents outstanding long-term debt due dates and principal amounts, net of debt discount, issuance and other costs and fair value adjustments as of 2022 and 2021: (Dollars in Thousands) December 31, Series Type Due 2022 2021 Puget Sound Energy: 7.150% First Mortgage Bond 2025 $ 15,000 $ 15,000 7.200% First Mortgage Bond 2025 2,000 2,000 7.020% Senior Secured Note 2027 300,000 300,000 7.000% Senior Secured Note 2029 100,000 100,000 3.900% Pollution Control Bond 2031 138,460 138,460 4.000% Pollution Control Bond 2031 23,400 23,400 5.483% Senior Secured Note 2035 250,000 250,000 6.724% Senior Secured Note 2036 250,000 250,000 6.274% Senior Secured Note 2037 300,000 300,000 5.757% Senior Secured Note 2039 350,000 350,000 5.795% Senior Secured Note 2040 325,000 325,000 5.764% Senior Secured Note 2040 250,000 250,000 4.434% Senior Secured Note 2041 250,000 250,000 5.638% Senior Secured Note 2041 300,000 300,000 4.300% Senior Secured Note 2045 425,000 425,000 4.223% Senior Secured Note 2048 600,000 600,000 3.250% Senior Secured Note 2049 450,000 450,000 2.893% Senior Secured Note 2051 450,000 450,000 4.700% Senior Secured Note 2051 45,000 45,000 * Debt discount, issuance cost and other * (37,095) (39,141) Total PSE long-term debt $ 4,786,765 $ 4,784,719 Puget Energy: * Fair value adjustment of PSE long-term debt * $ (148,341) $ (156,849) * Revolving Credit Agreement 2027 34,300 33,300 3.650% Senior Secured Note 2025 400,000 400,000 2.379% Senior Secured Note 2028 500,000 500,000 4.100% Senior Secured Note 2030 650,000 650,000 4.224% Senior Secured Note 2032 450,000 — * Debt discount, issuance cost and other * (9,351) (7,404) Total Puget Energy long-term debt $ 6,663,373 $ 6,203,766 ___________________ |
Schedule of Maturities of Long-Term Debt | The principal amounts of long-term debt maturities for the next five years and thereafter are as follows: (Dollars in Thousands) 2023 2024 2025 2026 2027 Thereafter Total Maturities of: PSE $ — $ — $ 17,000 $ — $ 300,000 $ 4,506,860 $ 4,823,860 Puget Energy — — 400,000 — $ 34,300 1,600,000 2,034,300 Total long-term debt $ — $ — $ 417,000 $ — $ 334,300 $ 6,106,860 $ 6,858,160 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Lessee, Lease, Description [Line Items] | |
Lease, Cost | The components of lease cost were as follows: Puget Energy and Year Ended December 31, Year Ended December 31, (Dollars in Thousands) 2022 2021 Finance lease cost: Amortization of right-of-use asset $ 2,465 $ 1,291 Interest on lease liabilities 2,482 358 Total finance lease cost $ 4,947 $ 1,649 Operating lease cost 1 $ 23,984 $ 23,983 _______________ 1. Includes $1.5 million and $1.4 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease or both of the years ended December 31, 2022 and December 31, 2021, respectively. Supplemental cash flow information related to leases was as follows: Puget Energy and Year Ended December 31, Year Ended December 31, (Dollars in Thousands) 2022 2021 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flow for operating leases $ 16,574 $ 16,440 Investing cash flow for operating leases 1 7,410 7,543 Operating cash flow for finance leases 2,482 358 Financing cash flow for finance leases 2,465 1,291 Non-cash disclosure upon commencement of new lease Right-of-use assets obtained in exchange for new operating lease liabilities $ 5,338 $ 4,820 Right-of-use assets obtained in exchange for new finance lease liabilities — 105,176 Non-cash disclosure upon modification of existing lease Modification of operating lease right-of-use assets $ 21,068 $ 26,287 _______________ 1 Includes $1.5 million and $1.4 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for both of the years ended December 31, 2022 and December 31, 2021, respectively. |
Assets and Liabilities, Lessee | Supplemental balance sheet information related to leases was as follows: Puget Energy and (Dollars in Thousands) At December 31, At December 31, Operating Leases 2022 2021 Operating lease right-of-use asset $ 193,509 $ 184,957 Operating leases liabilities current $ 20,342 $ 20,398 Operating lease liabilities long-term 181,265 172,510 Total operating lease liabilities: $ 201,607 $ 192,908 Finance Leases Common plant $ 58,391 $ 61,227 Electric plant 41,576 43,793 Total finance lease assets $ 99,967 $ 105,020 Other current liabilities $ 3,167 $ 1,742 Finance lease liabilities 102,518 105,303 Total finance lease liabilities $ 105,685 $ 107,045 Weighted Average Remaining Lease Term Operating leases 22.00 Years 22.80 Years Finance leases 19.10 Years 20.15 Years Weighted Average Discount Rate Operating leases 3.62 % 3.27 % Finance leases 3.07 % 3.07 % |
Finance Lease, Liability, Maturity | The following table summarizes the Company’s estimated future minimum lease payments as of December 31, 2022: Puget Energy and Future Minimum Lease Payments (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2023 $ 23,676 $ 6,383 2024 23,232 6,408 2025 21,887 6,534 2026 21,472 6,591 2027 21,047 6,670 Thereafter 172,969 109,882 Total lease payments $ 284,283 $ 142,468 Less imputed interest (82,676) (36,783) Total net present value $ 201,607 $ 105,685 |
Lessee, Operating Lease, Liability, Maturity | The following table summarizes the Company’s estimated future minimum lease payments as of December 31, 2022: Puget Energy and Future Minimum Lease Payments (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2023 $ 23,676 $ 6,383 2024 23,232 6,408 2025 21,887 6,534 2026 21,472 6,591 2027 21,047 6,670 Thereafter 172,969 109,882 Total lease payments $ 284,283 $ 142,468 Less imputed interest (82,676) (36,783) Total net present value $ 201,607 $ 105,685 |
Accounting for Derivative Ins_2
Accounting for Derivative Instruments and Hedging Activities (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Derivative [Line Items] | |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value | The following table presents the volumes, fair values and classification of the Company's derivative instruments recorded on the balance sheets: Puget Energy and Year Ended December 31, (Dollars in Thousands) Volumes (millions) Assets 1 Liabilities² 2022 2021 2022 2021 2022 2021 Electric portfolio derivatives * * $ 337,703 $ 74,829 $ 87,120 $ 85,424 Natural gas derivatives (MMBtus) 3 322 347 343,947 79,578 56,222 18,850 Total derivative contracts $ 681,650 $ 154,407 $ 143,342 $ 104,274 Current 587,029 128,210 124,976 63,309 Long-term 94,621 26,197 18,366 40,965 Total derivative contracts $ 681,650 $ 154,407 $ 143,342 $ 104,274 __________ 1. Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments. 2. Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments. 3. All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 234.9 million One Million British Thermal Units (MMBtus) and purchased electricity of 5.3 million megawatt hours (MWhs) at December 31, 2022, and 238.0 million MMBtus and 8.1 million MWhs at December 31, 2021. |
Offsetting Assets and Liabilities [Table Text Block] | The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities: Puget Energy and December 31, 2022 (Dollars in Thousands) Gross Amount Recognized in the Consolidated Balance Sheet 1 Gross Amounts Offset in the Consolidated Balance Sheet Net of Amounts Presented in the Consolidated Balance Sheet Gross Amounts Not Offset in the Consolidated Balance Sheet Commodity Contracts 2 Cash Collateral Received/Pledged Net Amount Assets: Energy derivative contracts $ 681,650 $ — $ 681,650 $ (125,334) $ — $ 556,316 Liabilities: Energy derivative contracts 143,342 — 143,342 (125,334) (5,661) 12,347 Puget Energy and December 31, 2021 (Dollars in Thousands) Gross Amount Recognized 1 Gross Amounts Offset in the Consolidated Balance Sheet Net of Amounts Presented in the Consolidated Balance Sheet Gross Amounts Not Offset in the Consolidated Balance Sheet Commodity Contracts 2 Cash Collateral Received/Pledged Net Amount Assets Energy Derivative Contracts $ 154,407 $ — $ 154,407 $ (40,833) $ — $ 113,574 Liabilities Energy Derivative Contracts 104,274 — 104,274 (40,833) (1,743) 61,698 __________ 1. All derivative contract deals are executed under ISDA, NAESB, and WSPP master agreements with right of set-off. 2. Amounts reflect netting by Counterparty and right of set-off. |
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance [Table Text Block] | The following tables present the effect and locations of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income: Puget Energy and Year Ended December 31, (Dollars in Thousands) Location 2022 2021 2020 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net $ 61,761 $ 26,686 $ 5,534 Realized Electric generation fuel 158,550 76,504 5,246 Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 199,416 (12,901) (32,341) Realized Purchased electricity 20,917 (3,044) (14,958) Total gain (loss) recognized in income on derivatives $ 440,644 $ 87,245 $ (36,519) |
Schedule of Credit Risk Related Contingent Features [Table Text Block] | The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post: Puget Energy and December 31, (Dollars in Thousands) 2022 2021 Contingent Feature Fair Value 1 Liability Posted Contingent Fair Value 1 Liability Posted Contingent Credit rating 2 $ 3,157 $ — $ 3,157 $ 52,537 $ — $ 52,537 Requested credit for adequate assurance 4,157 — — 9,380 — — Forward value of contract 3 5,661 56,200 N/A 1,743 12,782 N/A Total $ 12,975 $ 56,200 $ 3,157 $ 63,660 $ 12,782 $ 52,537 _______________ 1. Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable. 2. Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral. 3. Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Fair Value Inputs, Liabilities, Quantitative Information | The carrying values and estimated fair values were as follows: Puget Energy December 31, 2022 December 31, 2021 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Financial liabilities: Long-term debt (fixed-rate), net of discount 1 2 $ 6,629,073 $ 6,149,797 $ 6,170,466 $ 7,769,896 Long-term debt (variable-rate), net of discount 2 34,300 34,300 33,300 33,300 Total $ 6,663,373 $ 6,184,097 $ 6,203,766 $ 7,803,196 Puget Sound Energy December 31, 2022 December 31, 2021 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Financial liabilities: Long-term debt (fixed-rate), net of discount 2 2 $ 4,786,765 $ 4,379,010 $ 4,784,719 $ 6,145,639 Total $ 4,786,765 $ 4,379,010 $ 4,784,719 $ 6,145,639 _______________ 1. The carrying value includes debt issuances costs of $21.5 million and $22.7 million for December 31, 2022, and 2021, respectively, which are not included in fair value. 2. The carrying value includes debt issuances costs of $21.4 million and $22.8 million for December 31, 2022, and 2021, respectively, which are not included in fair value. |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block] | Puget Energy and Year Ended December 31, Level 3 Roll-Forward Net Asset (Liability) 2022 2021 2020 (Dollars in Thousands) Electric Natural Gas Total Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ (42,752) $ (2,120) $ (44,872) $ (23,718) $ (1,135) $ (24,853) $ (3,379) $ 1,282 $ (2,097) Changes during period: Realized and unrealized energy derivatives Included in earnings 1 180,533 — 180,533 (15,839) — (15,839) (23,559) — (23,559) Included in regulatory assets / liabilities — 301 301 — (1,749) (1,749) — (1,049) (1,049) Settlements 2 (21,972) 1,369 (20,603) (3,195) 764 (2,431) 3,220 (1,368) 1,852 Transferred into Level 3 — — — — — — — — — Transferred out Level 3 269 323 592 — — $ — — — $ — Balance at end of period $ 116,078 $ (127) $ 115,951 $ (42,752) $ (2,120) $ (44,872) $ (23,718) $ (1,135) $ (24,853) __________________ 1. Income Statement classification: Unrealized gain (loss) on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $147.1 million, $(21.6) million and $(21.3) million for the years ended December 31, 2022, 2021, and 2020, respectively. 2. The Company had no purchases or sales of options during the reported periods. |
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Table Text Block] | Below are the forward price ranges for the Company's commodity contracts, as of December 31, 2022: Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Electricity $ 119,093 $ 3,015 Discounted cash flow Power Prices (per MWh) $ 55.79 $ 291.03 $ 131.51 Natural Gas $ 959 $ 1,086 Discounted cash flow Natural Gas Prices (per MMBtu) $ 3.84 $ 7.00 $ 4.87 _______________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. |
Fair Value, Measurements, Recurring | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | The following tables present the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis and the reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy and Fair Value Fair Value December 31, 2022 December 31, 2021 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric Derivative Instruments $ 218,610 $ 119,093 $ 337,703 $ 68,011 $ 6,818 $ 74,829 Gas Derivative Instruments 342,988 959 343,947 79,526 52 79,578 Total derivative assets $ 561,598 $ 120,052 $ 681,650 $ 147,537 $ 6,870 $ 154,407 Liabilities: Electric Derivative Instruments $ 84,105 $ 3,015 $ 87,120 $ 35,854 $ 49,570 $ 85,424 Gas Derivative Instruments 55,136 1,086 56,222 16,678 2,172 18,850 Total derivative liabilities $ 139,241 $ 4,101 $ 143,342 $ 52,532 $ 51,742 $ 104,274 |
Retirement Benefits (Tables)
Retirement Benefits (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Schedule of Changes in Projected Benefit Obligations | The following tables summarize the Company’s change in benefit obligation, change in plan assets and amounts recognized in the Statements of Financial Position for the years ended December 31, 2022, and 2021: Puget Energy and Qualified SERP Other (Dollars in Thousands) 2022 2021 2022 2021 2022 2021 Change in benefit obligation: Benefit obligation at beginning of period $ 834,960 $ 849,383 $ 43,155 $ 46,742 $ 11,654 $ 12,114 Amendments — — — — 38 205 Service cost 26,351 26,888 557 456 217 155 Interest cost 24,263 22,381 1,253 1,183 311 302 Actuarial loss (gain) (215,005) (6,826) (5,260) 828 (2,397) (514) Benefits paid (80,226) (55,831) (7,659) (6,054) (808) (803) Medicare part D subsidy received — — — — — 195 Administrative expense (1,065) (1,035) — — — — Benefit obligation at end of period $ 589,278 $ 834,960 $ 32,046 $ 43,155 $ 9,015 $ 11,654 |
Schedule of Changes in Fair Value of Plan Assets | Puget Energy and Qualified SERP Other (Dollars in Thousands) 2022 2021 2022 2021 2022 2021 Change in plan assets: Fair value of plan assets at beginning of period $ 898,550 $ 834,655 $ — $ — $ 6,341 $ 5,918 Actual return on plan assets (176,537) 102,787 — — (550) 1,005 Employer contribution 18,000 18,000 7,659 6,054 207 222 Benefits paid (80,226) (55,831) (7,659) (6,054) (808) (804) Administrative expense (1,254) (1,061) — — — — Fair value of plan assets at end of period $ 658,533 $ 898,550 $ — $ — $ 5,190 $ 6,341 Funded status at end of period $ 69,255 $ 63,590 $ (32,046) $ (43,155) $ (3,825) $ (5,313) |
Schedule of Net Benefit Costs | The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, 2022, 2021, and 2020. Puget Energy Qualified SERP Other (Dollars in Thousands) 2022 2021 2020 2022 2021 2020 2022 2021 2020 Components of net periodic benefit cost: Service cost $ 26,351 $ 26,888 $ 24,337 $ 557 $ 456 $ 756 $ 217 $ 155 $ 190 Interest cost 24,263 22,381 25,180 1,253 1,183 1,464 311 302 368 Expected return on plan assets (51,014) (48,239) (49,902) — — — (379) (355) (389) Amortization of prior service cost (credit) — (1,904) (1,980) 289 349 349 22 6 — Amortization of net loss (gain) 6,381 11,803 8,160 2,471 2,165 2,122 (29) (39) (82) Net periodic benefit cost $ 5,981 $ 10,929 $ 5,795 $ 4,570 $ 4,153 $ 4,691 $ 142 $ 69 $ 87 |
Schedule of Amounts Recognized in Other Comprehensive Income (Loss) | The following tables summarize Puget Energy's and PSE's benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, 2022, and 2021: Puget Energy Qualified SERP Other (Dollars in Thousands) 2022 2021 2022 2021 2022 2021 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 12,735 $ (61,348) $ (5,260) $ 828 $ (1,468) $ (1,164) Amortization of net (loss) gain (6,381) (11,803) (2,471) (2,164) 29 39 Settlements, mergers, sales, and closures — — (277) (830) — — Prior service cost (credit) — — — — 38 205 Amortization of prior service (cost) credit — 1,904 (289) (349) (22) (6) Total change in other comprehensive income for year $ 6,354 $ (71,247) $ (8,297) $ (2,515) $ (1,423) $ (926) |
Schedule of Assumptions Used | In accounting for pension and other benefit obligations and costs under the plans, the following weighted-average actuarial assumptions were used by the Company: Qualified SERP Other Benefit Obligation Assumptions: 2022 2021 2020 2022 2021 2020 2022 2021 2020 Discount rate 5.60 % 3.00 % 2.70 % 5.60 % 3.00 % 2.70 % 5.60 % 3.00 % 2.70 % Rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Interest crediting rate 4.00 4.00 4.00 N/A N/A N/A N/A N/A N/A Benefit Cost Assumptions: Discount rate 3.00 2.70 3.35 3.00 2.70 3.35 3.00 2.70 3.35 Return on plan assets 6.50 6.50 7.15 — — — 7.00 7.00 7.00 Rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Interest crediting rate 4.00 4.00 4.00 N/A N/A N/A N/A N/A N/A |
Schedule of Expected Benefit Payments | The expected total benefits to be paid during the next five years and the aggregate total to be paid for the five years thereafter are as follows: (Dollars in Thousands) 2023 2024 2025 2026 2027 2028-2032 Qualified Pension total benefits $ 46,500 $ 47,800 $ 48,700 $ 49,900 $ 50,700 $ 260,700 SERP Pension total benefits 3,532 1,844 7,634 2,271 10,956 7,479 Other Benefits total 912 890 881 879 854 3,829 |
Schedule of Allocation of Plan Assets | To obtain the desired return needed to fund the pension benefit plans, the Retirement Plan Committee has established investment allocation percentages by asset classes as follows: Allocation Asset Class Minimum Target Maximum Domestic large cap equity 25 % 31 % 40 % Domestic small cap equity — 9 15 Non-U.S. equity 10 25 30 Fixed income 25 35 40 Real estate — — 10 Cash — — 5 The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, 2022, and 2021: Recurring Fair Value Measures Recurring Fair Value Measures December 31, 2022 December 31, 2021 (Dollars in Thousands) Level 1 Level 2 Other Total Level 1 Level 2 Other Total Assets: Common Stock: Domestic $ 175,969 $ 298 $ — $ 176,267 $ 249,021 $ 99 $ — $ 249,120 Foreign 17,767 — — 17,767 25,963 — — 25,963 Government Securities 61,693 8,828 — 70,521 65,266 2,470 — 67,736 Corporate Securities: Domestic — 16,005 — 16,005 — 12,820 — 12,820 Foreign — 6,525 — 6,525 — 5,239 — 5,239 Cash and cash equivalents 4,678 (632) — 4,046 3,638 (540) — 3,098 Investments measured at NAV: Collective Investment Funds — — 262,910 262,910 — — 359,861 359,861 Partnership — — 86,827 86,827 — — 115,570 115,570 Mutual Funds — — 46,005 46,005 — — 80,724 80,724 Other — — 846 846 — — 1,434 1,434 Net (payable) receivable — — (29,186) (29,186) — — (23,015) (23,015) Total assets $ 260,107 $ 31,024 $ 367,402 $ 658,533 $ 343,888 $ 20,088 $ 534,574 $ 898,550 |
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets [Table Text Block] | Puget Energy and Qualified SERP Other (Dollars in Thousands) 2022 2021 2022 2021 2022 2021 Change in plan obligation and plan asset: Projected benefit obligation $ 589,278 $ 834,960 $ 32,046 $ 43,155 $ 9,015 $ 11,654 Accumulated benefit obligation 582,538 823,418 29,763 40,773 8,929 11,549 Fair value of plan assets 658,533 898,550 — — 5,190 6,341 |
Schedule of Amounts Recognized in Accumulated Other Comprehensive Income | The following tables summarize Puget Energy's and PSE's pension benefit amounts recognized in accumulated other comprehensive income (AOCI) for the years ended December 31, 2022, and 2021: Puget Energy Qualified SERP Other (Dollars in Thousands) 2022 2021 2022 2021 2022 2021 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 31,213 $ 24,859 $ 1,563 $ 9,571 $ (1,964) $ (525) Prior service cost (credit) — — 289 578 259 242 Total $ 31,213 $ 24,859 $ 1,852 $ 10,149 $ (1,705) $ (283) Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2022 2021 2022 2021 2022 2021 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 124,767 $ 127,111 $ 1,864 $ 10,103 $ (2,056) $ (622) Prior service cost (credit) — — 289 578 258 242 Total $ 124,767 $ 127,111 $ 2,153 $ 10,681 $ (1,798) $ (380) |
Schedule of Amounts Recognized in Balance Sheet | Puget Energy and Qualified SERP Other (Dollars in Thousands) 2022 2021 2022 2021 2022 2021 Amounts recognized in Consolidated Balance Sheet consist of: Noncurrent assets $ 69,255 $ 63,590 $ — $ — $ — $ — Current liabilities — — (3,532) (2,822) (252) (280) Noncurrent liabilities — — (28,514) (40,333) (3,573) (5,033) Net assets (liabilities) $ 69,255 $ 63,590 $ (32,046) $ (43,155) $ (3,825) $ (5,313) |
Other Pension Plan [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Schedule of Allocation of Plan Assets | The following table sets forth by level, within the fair value hierarchy, the Other Benefits plan assets which consist of insurance benefits for retired employees, at fair value: Recurring Fair Value Measures Recurring Fair Value Measures December 31, 2022 December 31, 2021 (Dollars in Thousands) Level 1 Level 2 Other Total Level 1 Level 2 Other Total Assets: Money Markets $ — $ — $ — $ — $ 4 $ — $ — $ 4 Mutual fund — 5,190 — 5,190 — 6,337 — 6,337 Net (payable) receivable — — — — — — — — Total assets $ — $ 5,190 $ — $ 5,190 $ 4 $ 6,337 $ — $ 6,341 The following discussion provides information regarding the methods used in valuation of the various asset class investments held for the pension and other postretirement benefit plans. • Mutual funds classified as Level 1 securities have pricing inputs that are based on unadjusted prices in an active market. Principal markets for equity prices include published exchanges such as NASDAQ and New York Stock Exchange (NYSE). Mutual fund assets not included in the fair value hierarchy are privately held funds. These funds are not actively traded and utilize net asset value (NAV) as a practical expedient to measure fair value. • Common stock investments are traded in active markets on national and international securities exchanges and are valued at closing prices on the last business day of each period presented. They are classified as Level 1 securities. • Corporate and some government debt securities are valued using pricing models maximizing the use of observable inputs for similar securities. This includes basing value on yields currently available on comparable securities of issuers with similar credit ratings. Some government debt securities have quoted prices such as certain treasury securities and are classified as Level 1 securities. • Cash and cash equivalents comprise mostly of money market funds and foreign currency held. Money market funds are classified as Level 1 instruments as pricing inputs are based on unadjusted prices in an active market while foreign currency held is classified as a Level 2 investment based on inputs that are indirectly observable. • Investments in collective trust funds and partnerships are stated at the NAV as determined by the issuer of fund and are based on the fair value of the underlying investments held by the fund less its liabilities. The NAV is used as a practical expedient to estimate fair value. These funds are primarily invested in a blend of corporate and government debt securities as well as international equities. |
Subsidiaries [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Schedule of Net Benefit Costs | Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2022 2021 2020 2022 2021 2020 2022 2021 2020 Components of net periodic benefit cost: Service cost $ 26,351 $ 26,888 $ 24,337 $ 557 $ 456 $ 756 $ 217 $ 155 $ 190 Interest cost 24,263 22,381 25,180 1,253 1,183 1,464 311 302 368 Expected return on plan assets (51,016) (48,242) (49,910) — — — (379) (355) (389) Amortization of prior service cost (credit) — (1,513) (1,573) 289 349 349 22 6 — Amortization of net loss (gain) 15,080 21,862 19,043 2,648 2,344 2,385 (35) (52) (137) Net periodic benefit cost $ 14,678 $ 21,376 $ 17,077 $ 4,747 $ 4,332 $ 4,954 $ 136 $ 56 $ 32 |
Schedule of Amounts Recognized in Other Comprehensive Income (Loss) | Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2022 2021 2022 2021 2022 2021 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 12,736 $ (61,345) $ (5,260) $ 828 $ (1,468) $ (1,164) Amortization of net (loss) gain (15,080) (21,862) (2,648) (2,343) 35 53 Settlements, mergers, sales, and closures — — (331) (886) — — Prior service cost (credit) — — — — 38 205 Amortization of prior service (cost) credit — 1,513 (289) (349) (22) (6) Total change in other comprehensive income for year $ (2,344) $ (81,694) $ (8,528) $ (2,750) $ (1,417) $ (912) |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Income Tax Disclosures [Line Items] | |
Schedule of Components of Income Tax Expense (Benefit) | The details of income tax (benefit) expense are as follows: Puget Energy Year Ended December 31, (Dollars in Thousands) 2022 2021 2020 Charged to operating expenses: Current: Federal $ 41,198 $ 25,395 $ 7,962 State 628 721 7 Deferred: Federal 17,866 (1,759) (6,414) State 6 158 109 Total income tax expense $ 59,698 $ 24,515 $ 1,664 |
Schedule of Effective Income Tax Rate Reconciliation | The following reconciliation compares pre-tax book income at the federal statutory rate of 21.0% to the actual income tax expense in the Statements of Income: Puget Energy Year Ended December 31, (Dollars in Thousands) 2022 2021 2020 Income taxes at the statutory rate $ 99,549 $ 59,927 $ 38,720 Increase (decrease): Utility plant differences 1 $ (23,028) $ (22,325) $ (22,991) AFUDC, net (3,567) 1,509 (6,095) Executive compensation 1,821 1,386 2,440 Treasury grant amortization (5,717) (5,424) (8,935) Excess deferred tax amortization (13,722) (13,392) (3,038) Other–net 4,362 2,834 1,563 Total income tax expense $ 59,698 $ 24,515 $ 1,664 Effective tax rate 12.6 % 8.6 % 0.9 % Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2022 2021 2020 Income taxes at the statutory rate $ 119,962 $ 79,868 $ 63,110 Increase (decrease): Utility plant differences 1 $ (23,028) $ (22,325) $ (22,991) AFUDC, net (3,567) 1,509 (6,095) Executive compensation 1,821 1,386 2,440 Treasury grant amortization (5,717) (5,424) (8,935) Excess deferred tax amortization (13,722) (13,392) (3,038) Other–net 4,546 2,637 1,751 Total income tax expense $ 80,295 $ 44,259 $ 26,242 Effective tax rate 14.1 % 11.6 % 8.7 % _______________ 1. Utility plant differences include the reversal of excess deferred taxes using the average rate assumption method in the amount of $27.2 million and $27.6 million in 2022 and 2021, respectively. |
Schedule of Deferred Tax Assets and Liabilities | The Company’s net deferred tax liability at December 31, 2022, and 2021, is composed of amounts related to the following types of temporary differences: Puget Energy At December 31, (Dollars in Thousands) 2022 2021 Utility plant and equipment $ 1,853,450 $ 1,892,692 Unrealized gain on derivative instruments 158,175 50,971 Other deferred tax liabilities 365,035 313,270 Subtotal deferred tax liabilities 2,376,660 2,256,933 Net operating loss carryforward (234,825) (254,007) Net regulatory liability for income taxes (811,161) (865,976) Other deferred tax assets (299,597) (184,023) Unrealized loss on derivative instruments (45,130) (40,443) Subtotal deferred tax assets (1,390,713) (1,344,449) Total net deferred tax liabilities $ 985,947 $ 912,484 Puget Sound Energy At December 31, (Dollars in Thousands) 2022 2021 Utility plant and equipment $ 1,852,644 $ 1,892,674 Unrealized gain on derivative instruments 143,147 31,940 Other deferred tax liabilities 279,612 225,753 Subtotal deferred tax liabilities 2,275,403 2,150,367 Net regulatory liability for income taxes (811,724) (866,541) Other deferred tax assets (293,977) (178,211) Unrealized loss on derivative instruments (30,102) (21,412) Subtotal deferred tax assets (1,135,803) (1,066,164) Total net deferred tax liabilities $ 1,139,600 $ 1,084,203 |
Subsidiaries [Member] | |
Income Tax Disclosures [Line Items] | |
Schedule of Components of Income Tax Expense (Benefit) | Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2022 2021 2020 Charged to operating expenses: Current: Federal $ 81,597 $ 52,616 $ 10,607 State 869 670 383 Deferred: Federal (2,171) (9,027) 15,252 State — — — Total income tax expense $ 80,295 $ 44,259 $ 26,242 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Long-term Purchase Commitment [Line Items] | |
Schedule of Long-term Contracts for Purchase of Electric Power | The Company's expenses under these PUD contracts were as follows for the years ended December 31: (Dollars in Thousands) 2022 2021 2020 PUD contract costs $ 149,575 $ 117,812 $ 116,874 As of December 31, 2022, the Company purchased portions of the power output of the PUDs' projects as set forth in the following table: Company's Share of (Dollars in Thousands) Contract 2023 Percent of Output 2023 Megawatt Capacity Estimated 2023 Total Costs 2023 Debt Service Costs Interest included in 2023 Debt Service Costs Debt Outstanding Chelan County PUD 1 : Rock Island Project 2031 30.0 % 187 $ 47,892 $ 12,072 $ 5,132 $ 93,493 Rocky Reach Project 2031 30.0 390 54,022 5,039 1,907 33,757 Douglas County PUD 2 : Wells Project 2028 32.8 276 45,489 — — — Grant County PUD 3 : Priest Rapids Development 2052 4.8 45 28,243 747 376 9,768 Wanapum Development 2052 4.8 58 28,243 747 376 9,768 Total 956 $ 203,889 $ 18,605 $ 7,791 $ 146,786 _______________ 1. In March 2021, PSE entered into a new PPA with Chelan County PUD for additional Rocky Reach and Rock Island output. The contract began on January 1, 2022, and continues through December 31, 2026. This agreement increases PSE’s share of output by 5% for each project, which equates to an additional capacity of 31MW for Rock Island and 65MW for Rocky Reach. 2. In March 2021, PSE entered into a new agreement with Douglas County PUD for the extension of the Wells Project Output that began on October 1, 2021, and continues through September 30, 2024. This agreement increases PSE's share of output by 5.5% for the Wells Project, which equates to an additional capacity of 46MW. 3. In November 2022, PSE elected to take its portion of the Priest Rapid Meaningful Priority and was granted 4.13% share of the 2023 Priest Rapids Project output. This one-year contract begins on January 1, 2023, and continues through December 31, 2023. This agreement increases PSE's share of output by 4.13%, which equates to an additional capacity of 39MW for Priest Rapids Development and 51 MW for Wanapum Development. |
Schedule of Long-term Purchase Commitments | The following table summarizes the Company’s estimated obligations for service contracts through the terms of its existing contracts. Service Contract Obligations 2023 2024 2025 2026 2027 Thereafter Total Energy production service contracts $ 33,971 $ 34,812 $ 35,772 $ 18,728 $ 19,221 $ 79,655 $ 222,159 Automated meter reading system 50,124 47,301 47,668 48,803 — — 193,896 Total $ 84,095 $ 82,113 $ 83,440 $ 67,531 $ 19,221 $ 79,655 $ 416,055 |
Electricity, Purchased [Member] | |
Long-term Purchase Commitment [Line Items] | |
Schedule of Long-term Purchase Commitments | The following table summarizes the Company’s estimated payment obligations for power purchases from the Columbia River projects, electric portfolio contracts and electric wholesale market transactions. These contracts have varying terms and may include escalation and termination provisions. (Dollars in Thousands) 2023 2024 2025 2026 2027 Thereafter Total Columbia River projects $ 191,618 $ 145,078 $ 140,887 $ 138,482 $ 123,152 $ 394,875 $ 1,134,092 Electric portfolio contracts 380,559 385,807 345,257 142,273 133,903 1,776,703 3,164,502 Electric wholesale market transactions 414,278 148,628 11,616 11,616 — — 586,138 Total $ 986,455 $ 679,513 $ 497,760 $ 292,371 $ 257,055 $ 2,171,578 $ 4,884,732 |
Natural Gas, US Regulated [Member] | |
Long-term Purchase Commitment [Line Items] | |
Schedule of Long-term Purchase Commitments | The following table summarizes the Company’s obligations for future natural gas supply and demand charges through the primary terms of its existing contracts. The quantified obligations are based on the FERC and CER (Canadian Energy Regulator) currently authorized rates, which are subject to change. Natural Gas Supply and Demand Charge Obligations 2023 2024 2025 2026 2027 Thereafter Total Natural gas wholesale market transactions $ 1,013,547 $ 377,588 $ 351,129 $ 255,577 $ 76,453 $ — $ 2,074,294 Firm transportation service 175,136 146,675 112,327 94,417 94,123 570,687 1,193,365 Firm storage service 9,350 7,923 7,448 7,432 7,352 1,838 41,343 Total $ 1,198,033 $ 532,186 $ 470,904 $ 357,426 $ 177,928 $ 572,525 $ 3,309,002 |
Accumulated Other Comprehensi_2
Accumulated Other Comprehensive Income (Loss) (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block] | The following tables present the changes in the Company’s (loss) AOCI by component for the years ended December 31, 2022, 2021, and 2020, respectively: Puget Energy Net unrealized gain (loss) and prior service cost on pension plans Changes in AOCI, net of tax (Dollars in Thousands) Total Balance at December 31, 2019 $ (84,149) $ (84,149) Other comprehensive income (loss) before reclassifications (9,058) (9,058) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 6,770 6,770 Net current-period other comprehensive income (loss) (2,288) (2,288) Balance at December 31, 2020 $ (86,437) $ (86,437) Other comprehensive income (loss) before reclassifications 49,226 49,226 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 9,779 9,779 Net current-period other comprehensive income (loss) 59,005 59,005 Balance at December 31, 2021 $ (27,432) $ (27,432) Other comprehensive income (loss) before reclassifications (4,559) (4,559) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 7,217 7,217 Net current-period other comprehensive income (loss) 2,658 2,658 Balance at December 31, 2022 $ (24,774) $ (24,774) |
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block] | Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2022, 2021, and 2020, respectively, are as follows: Puget Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented Amount reclassified from accumulated 2022 2021 2020 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ (311) $ 1,549 $ 1,631 Amortization of net gain (loss) (a) (8,824) (13,928) (10,200) Total before tax (9,135) (12,379) (8,569) Tax (expense) or benefit 1,918 2,600 1,799 Net of tax (7,217) (9,779) (6,770) Total reclassification for the period Net of tax $ (7,217) $ (9,779) $ (6,770) __________ (a) These AOCI components are included in the computation of net periodic pension cost, see Note 13, "Retirement Benefits," to the consolidated financial statements included in Item 8 of this report for additional details. |
Subsidiaries [Member] | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block] | Puget Sound Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on treasury interest rate swaps Changes in AOCI, net of tax (Dollars in Thousands) Total Balance at December 31, 2019 $ (183,108) $ (5,369) $ (188,477) Other comprehensive income (loss) before reclassifications (8,717) — (8,717) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 15,853 385 16,238 Net current-period other comprehensive income (loss) 7,136 385 7,521 Balance at December 31, 2020 $ (175,972) $ (4,984) $ (180,956) Other comprehensive income (loss) before reclassifications 49,265 — 49,265 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 18,166 384 18,550 Net current-period other comprehensive income (loss) 67,431 384 67,815 Balance at December 31, 2021 $ (108,541) $ (4,600) $ (113,141) Other comprehensive income (loss) before reclassifications (4,512) — (4,512) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 14,223 386 14,609 Net current-period other comprehensive income (loss) 9,711 386 10,097 Balance at December 31, 2022 $ (98,830) $ (4,214) $ (103,044) |
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block] | Puget Sound Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented Amount reclassified from accumulated 2022 2021 2020 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ (311) $ 1,158 $ 1,224 Amortization of net gain (loss) (a) (17,693) (24,153) (21,291) Total before tax (18,004) (22,995) (20,067) Tax (expense) or benefit 3,781 4,829 4,214 Net of tax (14,223) (18,166) (15,853) Net unrealized gain (loss) on treasury interest rate swaps: Interest rate contracts Interest expense (488) (487) (487) Tax (expense) or benefit 102 103 102 Net of tax (386) (384) (385) Total reclassification for the period Net of tax $ (14,609) $ (18,550) $ (16,238) ____________ (a) These AOCI components are included in the computation of net periodic pension cost, see Note 13, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Details) | 12 Months Ended | ||||||
Feb. 03, 2021 | May 28, 2020 | Dec. 19, 2017 | Dec. 31, 2022 USD ($) mi² | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | Jan. 01, 2018 USD ($) | |
Accounting Policies | |||||||
Allowance for doubtful accounts | $ 41,962,000 | $ 34,958,000 | |||||
Monetized production tax credits | $ 0 | 45,600,000 | $ 39,800,000 | ||||
PTC, Operation Period | 10 years | ||||||
Bad Debt Deferral, COVID 19 | $ 7,100,000 | 2,800,000 | |||||
Excise and Sales Taxes | $ 292,800,000 | $ 268,500,000 | $ 240,800,000 | ||||
Gas Transmission Equipment | |||||||
Accounting Policies | |||||||
Annual depreciation provision | 2.90% | 2.80% | 2.90% | ||||
Common Plant | |||||||
Accounting Policies | |||||||
Annual depreciation provision | 7.10% | 6.80% | 7.30% | ||||
Electricity, US Regulated [Member] | |||||||
Accounting Policies | |||||||
Annual depreciation provision | 3.40% | 3.40% | 3.50% | ||||
Subsidiaries [Member] | |||||||
Accounting Policies | |||||||
Area of service territory (sqmi) | mi² | 6,000 | ||||||
Allowance for doubtful accounts | $ 41,962,000 | $ (34,958,000) | |||||
Public Utilities, Rate Case, Deferred Storm Costs Threshold | $ 10,000,000 | ||||||
Regulatory Asset, Amortization Period | 1 year | ||||||
Regulatory Liability, Amortization Period | 1 year | ||||||
Subsidiaries [Member] | Clearwater Wind Project | |||||||
Accounting Policies | |||||||
Variable Interest Entity, Measure of Activity, Expense | $ 5,700,000 | ||||||
Contract Length, PPA | 25 years | ||||||
Variable Interest Entity, Payable | 2,500,000 | ||||||
Subsidiaries [Member] | Golden Hills Wind Farm | |||||||
Accounting Policies | |||||||
Variable Interest Entity, Measure of Activity, Expense | 18,300,000 | ||||||
Contract Length, PPA | 20 years | ||||||
Variable Interest Entity, Payable | 0 | ||||||
Subsidiaries [Member] | Skookumchuck Wind Energy Project | |||||||
Accounting Policies | |||||||
Variable Interest Entity, Measure of Activity, Expense | 14,600,000 | 19,000,000 | |||||
Variable Interest Entity, Payable | $ 1,400,000 | 2,700,000 | |||||
Long-Term Purchase Commitment, Period | 20 years | ||||||
Puget LNG [Member] | |||||||
Accounting Policies | |||||||
Jointly Owned Non-Utility Plant Share | 57% | ||||||
Construction in Progress, Gross | $ 244,700,000 | ||||||
Operating Costs and Expenses | 11,600,000 | 1,300,000 | $ 600,000 | ||||
Non-Utility Plant | $ 249,100,000 | ||||||
Tacoma LNG [Member] | |||||||
Accounting Policies | |||||||
Jointly Owned Non-Utility Plant Share | 43% | ||||||
Construction in Progress, Gross | $ 239,600,000 | ||||||
Public Utilities, Property, Plant and Equipment, Plant in Service | $ 245,700,000 | ||||||
Decoupling Mechanism [Member] | Electricity, US Regulated [Member] | Subsidiaries [Member] | Maximum | |||||||
Accounting Policies | |||||||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 3% | ||||||
Decoupling Mechanism [Member] | Natural Gas, US Regulated [Member] | Subsidiaries [Member] | Maximum | |||||||
Accounting Policies | |||||||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 5% |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - AFUDC (Details) | 12 Months Ended | |||
Oct. 15, 2020 | Oct. 01, 2020 | Dec. 19, 2017 | Dec. 31, 2022 | |
Regulatory Assets [Line Items] | ||||
Public Utilities, Property, Plant and Equipment, Non-project Electric Utility Plant, Estimated Useful Life Average | 30 years | |||
Subsidiaries [Member] | ||||
Regulatory Assets [Line Items] | ||||
Public Utilities, Allowance for Funds Used During Construction, Rate | 7.39% | 7.39% | 7.60% |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies - Allowance for Credit Losses (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Accounts Receivable, Allowance for Credit Loss [Roll Forward] | |||
Allowance for Credit Losses, Beginning Balance | $ 41,962 | $ 34,958 | $ 20,080 |
Receivables Charged-Off | $ (21,312) | $ (12,326) |
Revenue (Details)
Revenue (Details) - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | |||
Aug. 13, 2021 | Dec. 31, 2020 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Revenue from Contract with Customer, Including Assessed Tax | $ 4,134,805 | $ 3,734,132 | $ 3,222,391 | ||
Revenues | 4,221,162 | 3,805,661 | 3,326,450 | ||
Other | 50,069 | 66,620 | 26,121 | ||
Total Other Revenue | 86,357 | 71,529 | 104,059 | ||
Electric | 2,961,457 | 2,671,623 | 2,319,416 | ||
Natural gas | 1,209,636 | 1,067,418 | 980,913 | ||
Other | 50,069 | 66,620 | 26,121 | ||
Residential | |||||
Revenue from Contract with Customer, Including Assessed Tax | 2,190,234 | 2,040,329 | 1,848,515 | ||
Industrial | |||||
Revenue from Contract with Customer, Including Assessed Tax | 141,808 | 130,008 | 120,159 | ||
Other Retail Customer | |||||
Revenue from Contract with Customer, Including Assessed Tax | 18,759 | 19,226 | 31,871 | ||
Wholesale | |||||
Revenue from Contract with Customer, Including Assessed Tax | 319,380 | 161,152 | 66,345 | ||
Transmission and Transportation | |||||
Revenue from Contract with Customer, Including Assessed Tax | 67,359 | 63,783 | 57,628 | ||
Miscellaneous Customer | |||||
Revenue from Contract with Customer, Including Assessed Tax | 63,852 | 124,431 | 54,235 | ||
Commercial | |||||
Revenue from Contract with Customer, Including Assessed Tax | 1,333,413 | 1,195,203 | 1,043,638 | ||
Puget LNG [Member] | |||||
Revenue, Remaining Performance Obligation, Amount | 195,566 | ||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | 15,359 | ||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, 2025 | 19,710 | ||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, 2026 | 19,454 | ||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, 2027 | 19,454 | ||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, 2028 | 19,454 | ||||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Thereafter | 102,135 | ||||
Remaining Contract Term, PLNG | 10 years | ||||
Subsidiaries [Member] | |||||
Nonutility Expense | $ 12,900 | ||||
Revenue Not from Contract with Customer | 23,200 | ||||
Other | $ 23,200 | 45,080 | 66,620 | 26,121 | |
Electric | 2,961,457 | 2,671,623 | 2,319,416 | ||
Natural gas | 1,209,636 | 1,067,418 | 980,913 | ||
Electricity, US Regulated [Member] | |||||
Revenue from Contract with Customer, Including Assessed Tax | 2,877,971 | 2,601,208 | 2,235,546 | ||
Total Other Revenue | 83,486 | 70,415 | 83,870 | ||
Electricity, US Regulated [Member] | Residential | |||||
Revenue from Contract with Customer, Including Assessed Tax | 1,381,858 | 1,318,326 | 1,186,012 | ||
Electricity, US Regulated [Member] | Industrial | |||||
Revenue from Contract with Customer, Including Assessed Tax | 116,712 | 108,267 | 101,567 | ||
Electricity, US Regulated [Member] | Other Retail Customer | |||||
Revenue from Contract with Customer, Including Assessed Tax | 18,759 | 18,834 | 26,644 | ||
Electricity, US Regulated [Member] | Wholesale | |||||
Revenue from Contract with Customer, Including Assessed Tax | 319,380 | 161,152 | 66,345 | ||
Electricity, US Regulated [Member] | Transmission and Transportation | |||||
Revenue from Contract with Customer, Including Assessed Tax | 47,027 | 43,753 | 38,073 | ||
Electricity, US Regulated [Member] | Miscellaneous Customer | |||||
Revenue from Contract with Customer, Including Assessed Tax | 13,065 | 47,948 | 25,007 | ||
Electricity, US Regulated [Member] | Commercial | |||||
Revenue from Contract with Customer, Including Assessed Tax | 981,170 | 902,928 | 791,898 | ||
Other Revenue From Contracts with Customers [Member] | |||||
Revenue from Contract with Customer, Including Assessed Tax | 50,069 | 66,620 | 26,121 | ||
Total Other Revenue | 0 | 0 | 0 | ||
Other Revenue From Contracts with Customers [Member] | Residential | |||||
Revenue from Contract with Customer, Including Assessed Tax | 0 | 0 | 0 | ||
Other Revenue From Contracts with Customers [Member] | Industrial | |||||
Revenue from Contract with Customer, Including Assessed Tax | 0 | 0 | 0 | ||
Other Revenue From Contracts with Customers [Member] | Other Retail Customer | |||||
Revenue from Contract with Customer, Including Assessed Tax | 0 | 0 | 0 | ||
Other Revenue From Contracts with Customers [Member] | Wholesale | |||||
Revenue from Contract with Customer, Including Assessed Tax | 0 | 0 | 0 | ||
Other Revenue From Contracts with Customers [Member] | Transmission and Transportation | |||||
Revenue from Contract with Customer, Including Assessed Tax | 0 | 0 | 0 | ||
Other Revenue From Contracts with Customers [Member] | Miscellaneous Customer | |||||
Revenue from Contract with Customer, Including Assessed Tax | 50,069 | 66,620 | 26,121 | ||
Other Revenue From Contracts with Customers [Member] | Commercial | |||||
Revenue from Contract with Customer, Including Assessed Tax | 0 | 0 | 0 | ||
Other Revenue From Contracts with Customers [Member] | Puget LNG [Member] | Miscellaneous Customer | |||||
Revenue from Contract with Customer, Including Assessed Tax | 5,000 | ||||
Natural Gas, US Regulated [Member] | |||||
Revenue from Contract with Customer, Including Assessed Tax | 1,206,765 | 1,066,304 | 960,724 | ||
Total Other Revenue | 2,871 | 1,114 | 20,189 | ||
Natural Gas, US Regulated [Member] | Residential | |||||
Revenue from Contract with Customer, Including Assessed Tax | 808,376 | 722,003 | 662,503 | ||
Natural Gas, US Regulated [Member] | Industrial | |||||
Revenue from Contract with Customer, Including Assessed Tax | 25,096 | 21,741 | 18,592 | ||
Natural Gas, US Regulated [Member] | Other Retail Customer | |||||
Revenue from Contract with Customer, Including Assessed Tax | 0 | 392 | 5,227 | ||
Natural Gas, US Regulated [Member] | Wholesale | |||||
Revenue from Contract with Customer, Including Assessed Tax | 0 | 0 | 0 | ||
Natural Gas, US Regulated [Member] | Transmission and Transportation | |||||
Revenue from Contract with Customer, Including Assessed Tax | 20,332 | 20,030 | 19,555 | ||
Natural Gas, US Regulated [Member] | Miscellaneous Customer | |||||
Revenue from Contract with Customer, Including Assessed Tax | 718 | 9,863 | 3,107 | ||
Natural Gas, US Regulated [Member] | Commercial | |||||
Revenue from Contract with Customer, Including Assessed Tax | $ 352,243 | $ 292,275 | $ 251,740 |
Regulation and Rates Net regula
Regulation and Rates Net regulatory assets and liabilities (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Jan. 01, 2018 | |
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 904,342,000 | $ 962,228,000 | |
Regulatory Liabilities | 2,025,500,000 | 1,791,094,000 | |
Accrual for Environmental Loss Contingencies | 61,500,000 | ||
Deferred income tax charge | |||
Regulatory Assets [Line Items] | |||
Regulatory Liabilities | $ 563,000 | 565,000 | |
Regulatory liabilities related to power contracts | |||
Regulatory Assets [Line Items] | |||
Net Regulatory Assets, Remaining Amortization Period, Max | 30 years | ||
Net Regulatory Assets, Remaining Amortization Period, Min | 3 years | ||
Regulatory Liabilities | $ 63,660,000 | 80,934,000 | |
Various other regulatory liabilities | |||
Regulatory Assets [Line Items] | |||
Regulatory Liabilities | 1,264,000 | 1,264,000 | |
Net Regulatory Asset (Liability) | |||
Regulatory Assets [Line Items] | |||
Net Regulatory Assets | (1,121,158,000) | (828,866,000) | |
Requlatory Assets Related to Power Contracts | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 7,904,000 | 9,689,000 | |
Net Regulatory Assets, Remaining Amortization Period, Max | 30 years | ||
Net Regulatory Assets, Remaining Amortization Period, Min | 3 years | ||
Subsidiaries [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 896,438,000 | 952,539,000 | |
Regulatory Asset, Amortization Period | 1 year | ||
Regulatory Liability, Amortization Period | 1 year | ||
Regulatory Liabilities | $ 1,961,139,000 | 1,709,461,000 | |
Regulatory Liabilities Reclassified from Accumulated Depreciation | 639,300,000 | 563,100,000 | |
Storm Damage Costs Incurred During Period | 32,200,000 | 51,400,000 | |
Public Utilities, Rate Case, Deferred Storm Costs Threshold | $ 10,000,000 | ||
Public Utilities, Rate Case, Deferred Storm Qualifying Costs | $ 500,000 | ||
Subsidiaries [Member] | Deferred income tax charge | |||
Regulatory Assets [Line Items] | |||
Regulatory Liabilities | 811,724,000 | 866,541,000 | |
Subsidiaries [Member] | Repurposed production tax credits [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Liabilities | $ 133,855,000 | 134,270,000 | |
Subsidiaries [Member] | Deferred decoupling revenue, net [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Liability, Amortization Period | 2 years | ||
Regulatory Liabilities | $ 63,206,000 | 36,506,000 | |
Subsidiaries [Member] | Various other regulatory liabilities | |||
Regulatory Assets [Line Items] | |||
Regulatory Liabilities | 5,583,000 | 35,093,000 | |
Subsidiaries [Member] | Liabilities, Total | |||
Regulatory Assets [Line Items] | |||
Regulatory Liabilities | 1,961,139,000 | 1,709,461,000 | |
Subsidiaries [Member] | Green Direct | |||
Regulatory Assets [Line Items] | |||
Regulatory Liabilities | 11,837,000 | 13,194,000 | |
Subsidiaries [Member] | Net Regulatory Asset (Liability) | |||
Regulatory Assets [Line Items] | |||
Net Regulatory Assets | (1,064,701,000) | (756,922,000) | |
Subsidiaries [Member] | PGA Unrealized Gain | |||
Regulatory Assets [Line Items] | |||
Regulatory Liabilities | 287,725,000 | 60,728,000 | |
Subsidiaries [Member] | Removal Costs | |||
Regulatory Assets [Line Items] | |||
Regulatory Liabilities | $ 639,320,000 | 563,129,000 | |
Subsidiaries [Member] | PGA Liability | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Amortization Period | 2 years | ||
Regulatory Liabilities | $ 3,536,000 | 0 | |
Subsidiaries [Member] | Refund on Counterparty Settlement | |||
Regulatory Assets [Line Items] | |||
Regulatory Asset, Amortization Period | 1 year | ||
Regulatory Liabilities | $ 4,353,000 | 0 | |
Subsidiaries [Member] | Storm Costs [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 127,524,000 | 127,789,000 | |
Net Regulatory Assets, Remaining Amortization Period, Max | 5 years | ||
Net Regulatory Assets, Remaining Amortization Period, Min | 3 years | ||
Subsidiaries [Member] | Chelan PUD contract initiation | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 62,611,000 | 69,699,000 | |
Regulatory Asset, Amortization Period | 8 years 9 months 18 days | ||
Subsidiaries [Member] | Environmental remediation | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 141,893,000 | 127,977,000 | |
Subsidiaries [Member] | Lower Snake River | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 48,536,000 | 53,757,000 | |
Regulatory Asset, Amortization Period | 14 years 4 months 24 days | ||
Subsidiaries [Member] | Deferred decoupling revenue, net [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 36,773,000 | 79,125,000 | |
Regulatory Asset, Amortization Period | 2 years | ||
Subsidiaries [Member] | Baker Dam Licensing Operating Maintenance Costs [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 55,049,000 | 54,525,000 | |
Hydro license term | 50 years | ||
Subsidiaries [Member] | Deferred Washington Commission AFUDC | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 61,463,000 | 62,244,000 | |
Regulatory Asset, Amortization Period | 30 years | ||
Subsidiaries [Member] | Property tax tracker | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 12,398,000 | 25,896,000 | |
Regulatory Asset, Amortization Period | 2 years | ||
Subsidiaries [Member] | Unamortized loss on reacquired debt | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 33,732,000 | 35,805,000 | |
Net Regulatory Assets, Remaining Amortization Period, Max | 45 years | ||
Net Regulatory Assets, Remaining Amortization Period, Min | 1 year | ||
Subsidiaries [Member] | Energy Conservation Costs [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 10,296,000 | 3,573,000 | |
Subsidiaries [Member] | GTZ depreciation expense deferral [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 49,605,000 | 50,220,000 | |
Net Regulatory Assets, Remaining Amortization Period, Max | 4 years | ||
Net Regulatory Assets, Remaining Amortization Period, Min | 1 year | ||
Subsidiaries [Member] | Advanced metering infrastructure [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 30,431,000 | 23,037,000 | |
Regulatory Asset, Amortization Period | 3 years | ||
Subsidiaries [Member] | Generation plant major maintenance [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 20,374,000 | 12,094,000 | |
Net Regulatory Assets, Remaining Amortization Period, Max | 7 years | ||
Net Regulatory Assets, Remaining Amortization Period, Min | 3 years | ||
Subsidiaries [Member] | Mint Farm ownership and operating costs | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 4,317,000 | 6,318,000 | |
Regulatory Asset, Amortization Period | 2 years 3 months 18 days | ||
Subsidiaries [Member] | PGA receivable [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 0 | 57,935,000 | |
Regulatory Asset, Amortization Period | 2 years | ||
Subsidiaries [Member] | Snoqualmie Licensing Operating Maintenance Costs | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 7,445,000 | 7,446,000 | |
Hydro license term | 40 years | ||
Subsidiaries [Member] | Colstrip major maintenance [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 4,035,000 | 4,035,000 | |
Regulatory Asset, Amortization Period | 3 years | ||
Subsidiaries [Member] | PCA Mechanism [Member] | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 112,207,000 | 79,546,000 | |
Subsidiaries [Member] | WUTC Electric Vehicle | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 7,796,000 | 6,109,000 | |
Regulatory Asset, Amortization Period | 4 years | ||
Subsidiaries [Member] | WUTC COVID-19 | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 7,051,000 | 3,657,000 | |
Subsidiaries [Member] | Low Income Program Costs | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | 17,370,000 | 21,755,000 | |
Subsidiaries [Member] | Various other regulatory assets | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | 7,060,000 | 32,508,000 | |
Subsidiaries [Member] | Water Heater Rental Property Loss | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | 5,725,000 | 5,725,000 | |
Subsidiaries [Member] | Regulatory Filing Fee Deferral | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | 7,559,000 | 0 | |
Subsidiaries [Member] | WUTC LNG | |||
Regulatory Assets [Line Items] | |||
Regulatory Assets | $ 25,188,000 | $ 1,764,000 |
General Rate Case Filing (Detai
General Rate Case Filing (Details) - Subsidiaries [Member] - USD ($) $ in Millions | 12 Months Ended | ||||||||||
Jan. 10, 2023 | Jan. 31, 2022 | Oct. 01, 2021 | Sep. 28, 2021 | Jul. 31, 2020 | Jul. 08, 2020 | Apr. 06, 2020 | Jun. 20, 2019 | Dec. 31, 2025 | Dec. 31, 2024 | Dec. 31, 2023 | |
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 0 | ||||||||||
Rate Plan, number of years | 3 years | ||||||||||
Subsequent Event [Member] | |||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Rate Plan, number of years | 2 years | ||||||||||
General Rate Case [Member] | |||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Public Utilities, Approved Debt Capital Structure, Net of Tax, Percentage | 6.80% | ||||||||||
Public Utilities, Approved Equity Capital Structure, Percentage | 48.50% | ||||||||||
Public Utilities, Approved Return on Equity, Percentage | 9.40% | ||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 18.9 | ||||||||||
Forecast | General Rate Case [Member] | |||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Public Utilities, Requested Return on Equity, Percentage | 9.90% | 9.90% | 9.90% | ||||||||
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities | 7.49% | 7.44% | 7.39% | ||||||||
Electricity, US Regulated [Member] | General Rate Case [Member] | |||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 6.90% | ||||||||||
Public Utilities, Interim Rate Increase (Decrease), Amount | $ 48.3 | $ 59.6 | $ 29.5 | ||||||||
Public Utilities, Interim Rate Increase (Decrease), Percentage | 2.30% | 1.60% | |||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 15.8 | $ 0.9 | |||||||||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 0.70% | 0.10% | |||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | $ 77.1 | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage | 3.70% | ||||||||||
PublicUtilitiesIncremenalRateIncreaseDecreaseAmount | $ 17.5 | ||||||||||
Electricity, US Regulated [Member] | Forecast | General Rate Case [Member] | |||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 1.20% | 2.50% | 13.60% | ||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 33.1 | $ 247 | |||||||||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 1.33% | 10.75% | |||||||||
Natural Gas, US Regulated [Member] | General Rate Case [Member] | |||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 7.90% | ||||||||||
Public Utilities, Interim Rate Increase (Decrease), Amount | $ 4.9 | $ 42.9 | $ 36.5 | ||||||||
Public Utilities, Interim Rate Increase (Decrease), Percentage | 0.60% | 4% | |||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 3.1 | $ 1.3 | |||||||||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 0.30% | 0.20% | |||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount | $ 45.3 | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage | 5.90% | ||||||||||
PublicUtilitiesIncremenalRateIncreaseDecreaseAmount | $ 2.4 | ||||||||||
Natural Gas, US Regulated [Member] | Forecast | General Rate Case [Member] | |||||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | |||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 1.80% | 2.30% | 13% | ||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 19.5 | $ 70.8 | |||||||||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 1.65% | 6.40% |
Power Cost Only Rate Case (Deta
Power Cost Only Rate Case (Details) - Subsidiaries [Member] - USD ($) $ in Thousands | Jan. 11, 2023 | Jul. 01, 2021 | Mar. 02, 2021 | Feb. 02, 2021 | Dec. 09, 2020 | Apr. 06, 2020 |
Regulatory Assets [Line Items] | ||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 0 | |||||
Electricity, US Regulated [Member] | PCORC [Member] | ||||||
Regulatory Assets [Line Items] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 88,000 | $ 78,500 | ||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 4.10% | 3.70% | ||||
Electricity, US Regulated [Member] | Power Cost Only Rate Case | ||||||
Regulatory Assets [Line Items] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 65,300 | |||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 3.10% | |||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 70,900 | |||||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 3.30% | |||||
Electricity, US Regulated [Member] | Power Cost Only Rate Case | Subsequent Event [Member] | ||||||
Regulatory Assets [Line Items] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 0 |
Decoupling Filings (Details)
Decoupling Filings (Details) - Subsidiaries [Member] - Decoupling Mechanism [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 19, 2017 | Dec. 31, 2022 | Dec. 31, 2021 | |
Electricity, US Regulated [Member] | |||
Regulatory Assets [Line Items] | |||
Contract with Customer, Liability, Revenue Recognized | $ 0 | $ 3 | |
Electricity, US Regulated [Member] | Maximum | |||
Regulatory Assets [Line Items] | |||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 3% | ||
Natural Gas, US Regulated [Member] | Maximum | |||
Regulatory Assets [Line Items] | |||
Public Utilities, Approved Rate Increase (Decrease), Percentage | 5% | ||
Natural Gas [Member] | |||
Regulatory Assets [Line Items] | |||
Contract with Customer, Liability, Revenue Recognized | $ 0 | $ 0 |
Schedule of Power Cost Adjustme
Schedule of Power Cost Adjustment Mechanism (Details) - Subsidiaries [Member] $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | |
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability, Interest | $ 1.5 | $ 1.7 | |
Under-collection | |||
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability, Amount | 110.1 | 68 | $ 76.1 |
Customer's share | Under-collection | |||
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability, Amount | $ 74.6 | 36.7 | 44 |
Customer's share | Range 1 | Under-collection | |||
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability | 0 | ||
Customer's share | Range 1 | Over-collection | |||
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability | 0 | ||
Customer's share | Range 2 | Under-collection | |||
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability | 0.50 | ||
Customer's share | Range 2 | Over-collection | |||
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability | 0.65 | ||
Customer's share | Range 3 | Under-collection | |||
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability | 0.90 | ||
Customer's share | Range 3 | Over-collection | |||
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability | 0.90 | ||
Companys share | Under-collection | |||
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability, Amount | $ 31.3 | $ 32.1 | |
Companys share | Range 1 | Under-collection | |||
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability | 1 | ||
Companys share | Range 1 | Over-collection | |||
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability | 1 | ||
Companys share | Range 2 | Under-collection | |||
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability | 0.50 | ||
Companys share | Range 2 | Over-collection | |||
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability | 0.35 | ||
Companys share | Range 3 | Under-collection | |||
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability | 0.10 | ||
Companys share | Range 3 | Over-collection | |||
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability | 0.10 |
Power Cost Adjustment Clause Fi
Power Cost Adjustment Clause Filing (Details) - Subsidiaries [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Under-collection | |||
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability, Amount | $ 110.1 | $ 68 | $ 76.1 |
Under-collection | Companys share | |||
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability, Amount | 31.3 | 32.1 | |
Under-collection | Customer's share | |||
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability, Amount | $ 74.6 | 36.7 | 44 |
Under-collection | Customer's share plus interest [Member] | |||
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability, Amount | 38.4 | 46 | |
Maximum Power | Customer's share plus interest [Member] | |||
Regulatory Assets [Line Items] | |||
Annual Power Cost Variability, Amount | $ 20 | $ 20 |
Purchased Gas Adjustment Mechan
Purchased Gas Adjustment Mechanism (Details) - Subsidiaries [Member] - USD ($) $ in Thousands | 12 Months Ended | |||||
Nov. 01, 2022 | Nov. 01, 2021 | Apr. 06, 2020 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Regulatory Assets [Line Items] | ||||||
Purchased natural gas costs, credit for CP settlement | $ (24,200) | |||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 0 | |||||
PGA Receivable | (3,536) | $ 57,935 | $ 87,655 | |||
Purchased Gas Adjustment [Member] | ||||||
Regulatory Assets [Line Items] | ||||||
Out of Cycle PGA | $ 69,400 | |||||
Purchased natural gas costs | 457,950 | 364,775 | ||||
Purchased natural gas costs, recoverable | (496,879) | (396,236) | ||||
Purchased natural gas adjustment, interest | 1,674 | 1,741 | ||||
Purchased natural gas costs, credit for CP settlement | $ (24,216) | $ 0 | ||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 155,300 | 59,100 | ||||
Schedule 101 | ||||||
Regulatory Assets [Line Items] | ||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | 142,100 | 80,600 | ||||
Schedule 106 | ||||||
Regulatory Assets [Line Items] | ||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 13,200 | $ (21,500) |
Narrative (Details)
Narrative (Details) - USD ($) | 12 Months Ended | |||||||||
Oct. 15, 2021 | Oct. 01, 2021 | Jul. 08, 2020 | Apr. 06, 2020 | Apr. 10, 2019 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Apr. 12, 2021 | Jan. 01, 2018 | |
Regulatory Assets [Line Items] | ||||||||||
Depreciation and amortization | $ 663,232,000 | $ 704,783,000 | $ 647,755,000 | |||||||
Accrual for Environmental Loss Contingencies | $ 61,500,000 | |||||||||
Environmental Loss Contingency Statement Of Financial Position Extensible Enumeration Not Disclosed Flag | Environmental Remediation | |||||||||
Environmental Remediation Expense, Statement Of Income Or Comprehensive Income, Extensible Enumeration Not Disclosed Flag | Environmental Remediation | |||||||||
Natural Gas, US Regulated [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Environmental Remediation Expense | $ 84,400,000 | |||||||||
Environmental Expense and Liabilities | 90,400,000 | 75,800,000 | ||||||||
Electricity, US Regulated [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Environmental Remediation Expense | 48,300,000 | |||||||||
Environmental Expense and Liabilities | 51,500,000 | 52,200,000 | ||||||||
Subsidiaries [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Depreciation and amortization | 657,349,000 | 704,372,000 | 647,546,000 | |||||||
Customer Bill Assistance | $ 2,500 | $ 1,000 | ||||||||
Liabilities, Other than Long-term Debt, Noncurrent | 34,500,000 | 11,000,000 | ||||||||
Storm Damage Costs Incurred During Period | 32,200,000 | 51,400,000 | ||||||||
Public Utilities, Rate Case, Deferred Storm Costs Threshold | $ 10,000,000 | |||||||||
Public Utilities, Rate Case, Deferred Storm Qualifying Costs | $ 500,000 | |||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 0 | |||||||||
Subsidiaries [Member] | Natural Gas [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Liabilities, Other than Long-term Debt, Noncurrent | 10,800,000 | $ 7,700,000 | ||||||||
Subsidiaries [Member] | Electricity [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Liabilities, Other than Long-term Debt, Noncurrent | $ 23,700,000 | $ 20,000,000 | ||||||||
Subsidiaries [Member] | Storm that occurred in 2020 | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Storm Damage Costs Deferred During Period | $ 200,000 | |||||||||
Subsidiaries [Member] | Storm that occurred in 2021 | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Storm Damage Costs Deferred During Period | 200,000 | 40,900,000 | ||||||||
Subsidiaries [Member] | Storm that occurred in 2022 | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Storm Damage Costs Deferred During Period | 21,400,000 | |||||||||
Subsidiaries [Member] | Get to Zero Deferral Filing [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Public Utilities, Property, Plant and Equipment, Equipment, Useful Life | 10 years | |||||||||
Depreciation and amortization | $ 11,800,000 | $ 6,600,000 | ||||||||
Subsidiaries [Member] | General Rate Case [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 18,900,000 | |||||||||
Subsidiaries [Member] | General Rate Case [Member] | Natural Gas, US Regulated [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | 3,100,000 | $ 1,300,000 | ||||||||
Subsidiaries [Member] | General Rate Case [Member] | Electricity, US Regulated [Member] | ||||||||||
Regulatory Assets [Line Items] | ||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 15,800,000 | $ 900,000 |
Dividend Payment Restrictions (
Dividend Payment Restrictions (Details) | 12 Months Ended |
Dec. 31, 2022 USD ($) | |
Parent [Line Items] | |
Retained Earnings, Unappropriated | $ 1,400,000,000 |
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio, Threshold For Dividend Payment | 2 |
EBITDA Interest Expense Ratio | 3.7 |
EBITDA to Interest Expense Denominator | 1 |
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End | 1 |
Subsidiaries [Member] | |
Parent [Line Items] | |
Dividends, Common Equity Ratio, Threshold For Dividend Payment | 44% |
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio, Threshold For Dividend Payment | 3 |
Dividends, Common Equity Ratio at Period End | 48.10% |
EBITDA Interest Expense Ratio | 5 |
EBITDA to Interest Expense Denominator | 1 |
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End | 1 |
Utility Plant (Details)
Utility Plant (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Public Utility, Property, Plant and Equipment | ||
Accumulated amortization of capital leases | $ 7,300 | $ 2,600 |
Utility Plant | ||
Distribution plant | 7,886,665 | 7,488,629 |
Production plant | 3,131,578 | 3,147,987 |
Transmission plant | 1,576,916 | 1,556,666 |
General plant | 735,298 | 746,758 |
Intangible plant (including capitalized software)2 | 755,430 | 797,691 |
Plant acquisition adjustment | 242,826 | 242,826 |
Underground storage | 45,305 | 43,391 |
Liquefied natural gas storage | 12,628 | 12,628 |
Plant held for future use | 46,079 | 46,020 |
Recoverable Cushion Gas | 8,784 | 8,655 |
Plant not classified | 723,383 | 316,933 |
Finance leases, net of accumulated amortization3 | 99,967 | 105,020 |
Less: Accumulated depreciation and amortization | (4,341,789) | (4,031,458) |
Subtotal | 10,923,070 | 10,481,746 |
Construction work in progress | 861,801 | 870,204 |
Net utility plant | $ 11,784,871 | 11,351,950 |
Minimum | ||
Public Utility, Property, Plant and Equipment | ||
Distribution plant, Estimated Useful Life | 7 years | |
Production plant, Estimated Useful Life | 3 years | |
Transmission plant, Estimated Useful Life | 44 years | |
General plant, Estimated Useful Life | 5 years | |
Public Utilities, Property, Plant and Equipment, Intangible, Estimated Useful Life 1 | 3 years | |
Underground storage, Estimated Useful Life | 25 years | |
Liquefied natural gas storage, Estimated Useful Life | 25 years | |
Minimum | Franchise Rights [Member] | ||
Public Utility, Property, Plant and Equipment | ||
General plant, Estimated Useful Life | 10 years | |
Minimum | Software and Software Development Costs [Member] | ||
Public Utility, Property, Plant and Equipment | ||
General plant, Estimated Useful Life | 3 years | |
Maximum | ||
Public Utility, Property, Plant and Equipment | ||
Distribution plant, Estimated Useful Life | 65 years | |
Production plant, Estimated Useful Life | 90 years | |
Transmission plant, Estimated Useful Life | 75 years | |
General plant, Estimated Useful Life | 75 years | |
Public Utilities, Property, Plant and Equipment, Intangible, Estimated Useful Life 1 | 50 years | |
Underground storage, Estimated Useful Life | 60 years | |
Liquefied natural gas storage, Estimated Useful Life | 50 years | |
Maximum | Franchise Rights [Member] | ||
Public Utility, Property, Plant and Equipment | ||
General plant, Estimated Useful Life | 50 years | |
Maximum | Software and Software Development Costs [Member] | ||
Public Utility, Property, Plant and Equipment | ||
General plant, Estimated Useful Life | 10 years | |
Subsidiaries [Member] | ||
Utility Plant | ||
Distribution plant | $ 9,406,017 | 9,026,042 |
Production plant | 3,780,910 | 3,815,599 |
Transmission plant | 1,683,737 | 1,663,559 |
General plant | 760,094 | 773,662 |
Intangible plant (including capitalized software)2 | 745,973 | 788,240 |
Plant acquisition adjustment | 282,792 | 282,792 |
Underground storage | 58,716 | 56,820 |
Liquefied natural gas storage | 14,498 | 14,498 |
Plant held for future use | 46,232 | 46,172 |
Recoverable Cushion Gas | 8,784 | 8,655 |
Plant not classified | 723,383 | 316,933 |
Finance leases, net of accumulated amortization3 | 99,967 | 105,020 |
Less: Accumulated depreciation and amortization | (6,688,033) | (6,416,246) |
Subtotal | 10,923,070 | 10,481,746 |
Construction work in progress | 861,801 | 870,204 |
Net utility plant | $ 11,784,871 | $ 11,351,950 |
Utility Plant - Jointly Owned U
Utility Plant - Jointly Owned Utility Plant (Details) $ in Thousands | Dec. 31, 2022 USD ($) |
Colstrip Units 3 & 4 | |
Jointly Owned Utility Plant Interests | |
Plant in Service at Cost | $ 321,767 |
Construction Work in Progress | 0 |
Accumulated Depreciation | (176,847) |
Frederickson 1 | |
Jointly Owned Utility Plant Interests | |
Plant in Service at Cost | 63,348 |
Construction Work in Progress | 0 |
Accumulated Depreciation | (21,894) |
Jackson Prairie [Member] | |
Jointly Owned Utility Plant Interests | |
Plant in Service at Cost | 44,708 |
Construction Work in Progress | 837 |
Accumulated Depreciation | (12,178) |
Tacoma LNG [Member] | |
Jointly Owned Utility Plant Interests | |
Plant in Service at Cost | 494,795 |
Construction Work in Progress | 2,936 |
Accumulated Depreciation | $ (10,922) |
Subsidiaries [Member] | Colstrip Units 3 & 4 | |
Jointly Owned Utility Plant Interests | |
Company’s Ownership Share | 25% |
Plant in Service at Cost | $ 579,019 |
Construction Work in Progress | 0 |
Accumulated Depreciation | $ (434,099) |
Subsidiaries [Member] | Frederickson 1 | |
Jointly Owned Utility Plant Interests | |
Company’s Ownership Share | 49.85% |
Plant in Service at Cost | $ 69,415 |
Construction Work in Progress | 0 |
Accumulated Depreciation | $ (27,962) |
Subsidiaries [Member] | Jackson Prairie [Member] | |
Jointly Owned Utility Plant Interests | |
Company’s Ownership Share | 33.34% |
Plant in Service at Cost | $ 58,716 |
Construction Work in Progress | 837 |
Accumulated Depreciation | (26,186) |
Subsidiaries [Member] | Tacoma LNG [Member] | |
Jointly Owned Utility Plant Interests | |
Plant in Service at Cost | 245,690 |
Construction Work in Progress | 503 |
Accumulated Depreciation | $ (5,052) |
Utility Plant - Schedule of Ass
Utility Plant - Schedule of Asset Retirement Obligation (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Tacoma LNG [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Decommissioning Liability, Noncurrent | $ 3,900 | $ 3,800 |
Subsidiaries [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Asset retirement obligation at beginning of the period | 209,041 | 216,163 |
Relief of liability | (6,867) | (13,146) |
Revisions in estimated cash flows | 1,519 | (46) |
Accretion expense | 5,713 | 6,070 |
Asset Retirement Obligation, Ending Balance | 209,406 | 209,041 |
Decommissioning Liability, Noncurrent | 6,900 | 13,100 |
Puget LNG [Member] | Tacoma LNG [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Decommissioning Liability, Noncurrent | $ 3,800 | $ 3,700 |
Utility Plant - Narrative (Deta
Utility Plant - Narrative (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Tacoma LNG [Member] | |||
Jointly Owned Utility Plant Interests | |||
Decommissioning Liability, Noncurrent | $ 3.9 | $ 3.8 | |
Subsidiaries [Member] | |||
Jointly Owned Utility Plant Interests | |||
Decommissioning Liability, Noncurrent | 6.9 | 13.1 | |
Subsidiaries [Member] | Colstrip Units 1 and 2 [Member] | |||
Jointly Owned Utility Plant Interests | |||
Regulatory Assets, Unrecovered plant balance | $ 126.5 | ||
Decommissioning Liability, Noncurrent | 0 | 1.5 | |
Subsidiaries [Member] | Colstrip Units 3 and 4 [Member] | |||
Jointly Owned Utility Plant Interests | |||
Decommissioning Liability, Noncurrent | 3.1 | ||
Puget LNG [Member] | Tacoma LNG [Member] | |||
Jointly Owned Utility Plant Interests | |||
Decommissioning Liability, Noncurrent | $ 3.8 | $ 3.7 |
Long-Term Debt (Schedule of Lon
Long-Term Debt (Schedule of Long-Term Debt Instruments) (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | May 16, 2022 | Apr. 28, 2022 | Mar. 17, 2022 | Dec. 31, 2021 | Sep. 15, 2021 | Jun. 14, 2021 | Sep. 26, 2019 |
Debt Instrument [Line Items] | ||||||||
Total PSE long-term debt | $ 6,858,160 | |||||||
Long Term Debt, Reconciliation, Fair Value Adjustment | (148,341) | $ (156,849) | ||||||
Long-term Debt, term loan | $ 210,000 | |||||||
Long-term Line of Credit, Noncurrent | 34,300 | 33,300 | ||||||
Unamortized discount on senior notes | (9,351) | (7,404) | ||||||
Long-term Debt, Excluding Current Maturities | 6,663,373 | 6,203,766 | ||||||
Current maturities of long-term debt | 0 | 450,000 | ||||||
Short-term debt | $ 441,300 | 140,000 | ||||||
Working Capital Needs | ||||||||
Debt Instrument [Line Items] | ||||||||
Current borrowing capacity of line of credit | $ 800,000 | |||||||
Senior Secured Note | 5.625% Senior Secured Note Due 2022 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 5.625% | |||||||
Senior Secured Note | 3.650% Senior Secured Note Due 2025 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 3.65% | |||||||
Total PSE long-term debt | $ 400,000 | 400,000 | ||||||
Senior Secured Note | 6.000% Senior Secured Note Due 2021 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 6% | |||||||
Current maturities of long-term debt | $ 500,000 | |||||||
Senior Secured Note | 4.100% Senior Secured Note Due 2030 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 4.10% | |||||||
Total PSE long-term debt | $ 650,000 | 650,000 | ||||||
Senior Secured Note | 2.379% Senior Secured Note Due 2028 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 2.379% | 2.379% | ||||||
Total PSE long-term debt | $ 500,000 | 500,000 | $ 500,000 | |||||
Long-term Debt, Term | 7 years | |||||||
Senior Secured Note | 4.224% Senior Secured Note Due 2032 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 4.224% | 4.224% | ||||||
Total PSE long-term debt | $ 450,000 | $ 450,000 | 0 | |||||
Subsidiaries [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Total PSE long-term debt | 4,823,860 | |||||||
Unamortized discount on senior notes | (37,095) | (39,141) | ||||||
Long-term Debt, Excluding Current Maturities | 4,786,765 | 4,784,719 | ||||||
Short-term debt | $ 357,000 | 140,000 | ||||||
Subsidiaries [Member] | Working Capital Needs | ||||||||
Debt Instrument [Line Items] | ||||||||
Current borrowing capacity of line of credit | $ 800,000 | |||||||
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 7.150% Series Due 2025 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 7.15% | |||||||
Total PSE long-term debt | $ 15,000 | 15,000 | ||||||
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 7.200% Series Due 2025 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 7.20% | |||||||
Total PSE long-term debt | $ 2,000 | 2,000 | ||||||
Subsidiaries [Member] | Pollution Control Bonds | 3.900% Series Due 2031 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 3.90% | |||||||
Total PSE long-term debt | $ 138,460 | 138,460 | ||||||
Subsidiaries [Member] | Pollution Control Bonds | 4.000% Series Due 2031 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 4% | |||||||
Total PSE long-term debt | $ 23,400 | 23,400 | ||||||
Subsidiaries [Member] | Senior Secured Note | 7.020% Series Due 2027 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 7.02% | |||||||
Total PSE long-term debt | $ 300,000 | 300,000 | ||||||
Subsidiaries [Member] | Senior Secured Note | 7.000% Series Due 2029 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 7% | |||||||
Total PSE long-term debt | $ 100,000 | 100,000 | ||||||
Subsidiaries [Member] | Senior Secured Note | 5.483% Series Due 2035 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 5.483% | |||||||
Total PSE long-term debt | $ 250,000 | 250,000 | ||||||
Subsidiaries [Member] | Senior Secured Note | 6.724% Series Due 2036 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 6.724% | |||||||
Total PSE long-term debt | $ 250,000 | 250,000 | ||||||
Subsidiaries [Member] | Senior Secured Note | 6.274% Series Due 2037 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 6.274% | |||||||
Total PSE long-term debt | $ 300,000 | 300,000 | ||||||
Subsidiaries [Member] | Senior Secured Note | 5.757% Series Due 2039 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 5.757% | |||||||
Total PSE long-term debt | $ 350,000 | 350,000 | ||||||
Subsidiaries [Member] | Senior Secured Note | 5.795% Series Due 2040 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 5.795% | |||||||
Total PSE long-term debt | $ 325,000 | 325,000 | ||||||
Subsidiaries [Member] | Senior Secured Note | 5.764% Series Due 2040 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 5.764% | |||||||
Total PSE long-term debt | $ 250,000 | 250,000 | ||||||
Subsidiaries [Member] | Senior Secured Note | 4.434% Series Due 2041 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 4.434% | |||||||
Total PSE long-term debt | $ 250,000 | 250,000 | ||||||
Subsidiaries [Member] | Senior Secured Note | 5.638% Series Due 2041 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 5.638% | |||||||
Total PSE long-term debt | $ 300,000 | 300,000 | ||||||
Subsidiaries [Member] | Senior Secured Note | 4.300% Series Due 2045 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 4.30% | |||||||
Total PSE long-term debt | $ 425,000 | 425,000 | ||||||
Subsidiaries [Member] | Senior Secured Note | 4.223% Series Due 2048 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 4.223% | |||||||
Total PSE long-term debt | $ 600,000 | 600,000 | ||||||
Subsidiaries [Member] | Senior Secured Note | 3.250% Senior Secured Note Due 2049 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 3.25% | |||||||
Total PSE long-term debt | $ 450,000 | 450,000 | ||||||
Subsidiaries [Member] | Senior Secured Note | 4.700% Series Due 2051 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 4.70% | |||||||
Total PSE long-term debt | $ 45,000 | 45,000 | ||||||
Subsidiaries [Member] | Senior Secured Note | 2.893% Senior Secured Note Due 2051 | ||||||||
Debt Instrument [Line Items] | ||||||||
Stated interest rate percent | 2.893% | 2.893% | ||||||
Total PSE long-term debt | $ 450,000 | $ 450,000 | $ 450,000 | |||||
Long-term Debt, Term | 30 years |
Long-Term Debt (Narrative) (Det
Long-Term Debt (Narrative) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||||||||
Aug. 01, 2022 | Apr. 28, 2022 | Mar. 10, 2022 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Mar. 17, 2022 | Sep. 15, 2021 | Jun. 14, 2021 | Sep. 26, 2019 | |
Debt Instrument [Line Items] | ||||||||||
Long-term Debt, term loan | $ 210,000 | |||||||||
Total PSE long-term debt | $ 6,858,160 | |||||||||
Long-term Line of Credit, Noncurrent | 34,300 | $ 33,300 | ||||||||
Long-term debt | 6,858,160 | |||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 1,300,000 | |||||||||
Debt discount, issuance costs and other | 194,787 | 203,394 | ||||||||
Gain (Loss) on Extinguishment of Debt | 0 | 0 | $ (13,546) | |||||||
Repayment of term loan and revolving credit | 0 | 234,000 | $ 159,400 | |||||||
Line of Credit Facility, Maximum Amount Outstanding During Period | 118,600 | |||||||||
Line of Credit, Current | 84,300 | |||||||||
Debt Instrument, Unused Borrowing Capacity, Amount | $ 550,000 | |||||||||
Debt Instrument, Maximum Borrowing Capacity | $ 1,000,000 | |||||||||
Senior Secured Note | 2.379% Senior Secured Note Due 2028 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Total PSE long-term debt | 500,000 | 500,000 | $ 500,000 | |||||||
Long-term debt | $ 500,000 | 500,000 | $ 500,000 | |||||||
Stated interest rate percent | 2.379% | 2.379% | ||||||||
Long-term Debt, Term | 7 years | |||||||||
Senior Secured Note | 6.000% Senior Secured Note Due 2021 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate percent | 6% | |||||||||
Senior Secured Note | 4.224% Senior Secured Note Due 2032 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Total PSE long-term debt | $ 450,000 | 0 | $ 450,000 | |||||||
Long-term debt | $ 450,000 | 0 | $ 450,000 | |||||||
Stated interest rate percent | 4.224% | 4.224% | ||||||||
Senior Secured Note | 5.625% Senior Secured Note Due 2022 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate percent | 5.625% | |||||||||
Extinguishment of Debt, Amount | $ 457,200 | |||||||||
Debt Instrument, Increase, Accrued Interest | 7,200 | |||||||||
Long-term debt, Principal | $ 450,000 | |||||||||
Subsidiaries [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Total PSE long-term debt | $ 4,823,860 | |||||||||
Long-term debt | 4,823,860 | |||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 1,400,000 | |||||||||
Debt discount, issuance costs and other | 37,095 | 39,141 | ||||||||
Debt Instrument, Unused Borrowing Capacity, Amount | $ 1,400,000 | |||||||||
Debt Instrument, Maximum Borrowing Capacity | $ 1,400,000 | |||||||||
Subsidiaries [Member] | Senior Secured Note | 4.223% Series Due 2048 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Total PSE long-term debt | 600,000 | 600,000 | ||||||||
Long-term debt | $ 600,000 | 600,000 | ||||||||
Stated interest rate percent | 4.223% | |||||||||
Subsidiaries [Member] | Senior Secured Note | 2.893% Senior Secured Note Due 2051 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Total PSE long-term debt | $ 450,000 | 450,000 | $ 450,000 | |||||||
Long-term debt | $ 450,000 | $ 450,000 | $ 450,000 | |||||||
Stated interest rate percent | 2.893% | 2.893% | ||||||||
Long-term Debt, Term | 30 years |
Long-Term Debt (Schedule of Mat
Long-Term Debt (Schedule of Maturities of Long-Term Debt) (Details) $ in Thousands | Dec. 31, 2022 USD ($) |
Maturities of Long-term Debt [Abstract] | |
2023 | $ 0 |
2024 | 0 |
2025 | 417,000 |
2026 | 0 |
2027 | 334,300 |
Thereafter | 6,106,860 |
Total | 6,858,160 |
Subsidiaries [Member] | |
Maturities of Long-term Debt [Abstract] | |
2023 | 0 |
2024 | 0 |
2025 | 17,000 |
2026 | 0 |
2027 | 300,000 |
Thereafter | 4,506,860 |
Total | 4,823,860 |
Parent Company [Member] | |
Maturities of Long-term Debt [Abstract] | |
2023 | 0 |
2024 | 0 |
2025 | 400,000 |
2026 | 0 |
2027 | 34,300 |
Thereafter | 1,600,000 |
Total | $ 2,034,300 |
Liquidity Facilities and Othe_2
Liquidity Facilities and Other Financing Arrangements (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||
Sep. 26, 2022 | Feb. 10, 2012 | Dec. 31, 2022 | May 16, 2022 | Dec. 31, 2021 | |
Short-term Debt [Line Items] | |||||
Short-term debt | $ 441,300 | $ 140,000 | |||
Line of Credit Facility, Maximum Borrowing Capacity | 1,300,000 | ||||
Proceeds from Lines of Credit | $ 50,000 | ||||
Line of Credit, Current | 84,300 | ||||
Working Capital Needs | |||||
Short-term Debt [Line Items] | |||||
Current borrowing capacity of line of credit | $ 800,000 | ||||
Subsidiaries [Member] | |||||
Short-term Debt [Line Items] | |||||
Short-term debt | $ 357,000 | $ 140,000 | |||
Weighted-average interest rate on short-term debt (percent) | 6.10% | 1.60% | |||
Line of Credit Facility, Current Same-Day Borrowing Capacity | $ 75,000 | ||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 1,400,000 | ||||
Maximum capitalization percentage | 65% | ||||
Derivative, Basis Spread on Variable Rate | 1.25% | ||||
Line of Credit, Unused Capacity, Commitment Fee Percentage | 0.175% | ||||
Promissory Note Outstanding, Amount | $ 0 | ||||
Subsidiaries [Member] | Working Capital Needs | |||||
Short-term Debt [Line Items] | |||||
Current borrowing capacity of line of credit | $ 800,000 | ||||
Subsidiaries [Member] | Letter of Credit | Working Capital Needs | |||||
Short-term Debt [Line Items] | |||||
Current borrowing capacity of line of credit | 2,300 | ||||
Subsidiaries [Member] | Letter of Credit | Energy Dedging Activities | |||||
Short-term Debt [Line Items] | |||||
Current borrowing capacity of line of credit | 28,000 | ||||
Subsidiaries [Member] | Line of Credit [Member] | Promissory Note with Puget Energy | |||||
Short-term Debt [Line Items] | |||||
Current borrowing capacity of line of credit | $ 30,000 | ||||
Basis spread on variable rate (percent) | 0.25% | ||||
Debt instrument variable rate basis | one-month LIBOR | ||||
Parent | |||||
Short-term Debt [Line Items] | |||||
Short-term debt | $ 84,300 | $ 0 | |||
Revolving Credit Facility [Member] | |||||
Short-term Debt [Line Items] | |||||
Basis spread on variable rate (percent) | 1.75% | ||||
Line of Credit Facility, Commitment Fee Percentage | 0.275% | ||||
Line of Credit Facility, Fair Value of Amount Outstanding | $ 118,600 | ||||
Debt Instrument, Secured Overnight Financing Rate Adjustment | 0.10% | ||||
Revolving Credit Facility [Member] | Subsidiaries [Member] | |||||
Short-term Debt [Line Items] | |||||
Line of Credit Facility, Fair Value of Amount Outstanding | $ 0 | ||||
Debt Instrument, Secured Overnight Financing Rate Adjustment | 0.10% |
Leases (Details)
Leases (Details) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 USD ($) lease | Dec. 31, 2021 USD ($) | |
Lessee, Lease, Description [Line Items] | ||
Lease, Remaining Lease Term | 47 years | |
ROU Asset, Modification, Operating | $ 26,300 | |
Current Lease Liability, Modification, Operating | 400 | |
Long-Term Lease Liability, Modification, Operating | 25,900 | |
Subsidiaries [Member] | ||
Lessee, Lease, Description [Line Items] | ||
Right-of-Use, Modification, Operating | $ 21,068 | $ 26,287 |
Property Subject to or Available for Finance Lease, Number of Units | lease | 2 | |
Subsidiaries [Member] | Kent Service Center | ||
Lessee, Lease, Description [Line Items] | ||
Finance Lease ROU Asset, Addition | $ 45,100 | |
Current Lease Liability, Addition, Finance | 1,000 | |
Long-Term Lease Liability, Addition, Finance | $ 44,100 | |
Lessee, Finance Lease, Term of Contract | 20 years | |
Subsidiaries [Member] | Puyallup Service Center | ||
Lessee, Lease, Description [Line Items] | ||
Finance Lease ROU Asset, Addition | $ 61,300 | |
Current Lease Liability, Addition, Finance | 400 | |
Long-Term Lease Liability, Addition, Finance | $ 59,900 | |
Lessee, Finance Lease, Term of Contract | 20 years |
Leases (Schedule of Operating L
Leases (Schedule of Operating Lease Expense) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Operating Leased Assets [Line Items] | ||
Finance Lease, Right-of-Use Asset, Amortization | $ 2,465 | $ 1,291 |
Finance Lease, Interest Expense | 2,482 | 358 |
Finance Lease, Cost | 4,947 | 1,649 |
Operating Lease, Cost | 23,984 | 23,983 |
Subsidiaries [Member] | Land [Member] | ||
Operating Leased Assets [Line Items] | ||
Operating Lease, Cost | $ 1,500 | $ 1,400 |
Leases (Cash paid) (Details)
Leases (Cash paid) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Lessee, Lease, Description [Line Items] | ||
Operating Lease, Payments | $ 16,574 | $ 16,440 |
Operating Lease, Payments, Use | 7,410 | 7,543 |
Finance Lease, Interest Payment on Liability | 2,482 | 358 |
Finance Lease, Principal Payments | 2,465 | 1,291 |
Operating Lease, Cost | 23,984 | 23,983 |
Subsidiaries [Member] | ||
Lessee, Lease, Description [Line Items] | ||
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability | 5,338 | 4,820 |
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability | 0 | 105,176 |
Right-of-Use, Modification, Operating | 21,068 | 26,287 |
Subsidiaries [Member] | Land [Member] | ||
Lessee, Lease, Description [Line Items] | ||
Operating Lease, Cost | $ 1,500 | $ 1,400 |
Leases (Balance Sheet) (Details
Leases (Balance Sheet) (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Leases [Abstract] | ||
Operating lease right-of-use asset | $ 193,509 | $ 184,957 |
Operating lease liabilities | 20,342 | 20,398 |
Operating lease liabilities | 181,265 | 172,510 |
Operating Lease, Liability | 201,607 | 192,908 |
Finance Lease, Right-of-Use Asset | 99,967 | 105,020 |
Finance Lease, Liability, Current | 3,167 | 1,742 |
Finance lease liabilities | $ 102,518 | $ 105,303 |
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration] | Other | Other |
Finance Lease, Liability | $ 105,685 | $ 107,045 |
Operating Lease, Weighted Average Remaining Lease Term | 22 years | 22 years 9 months 18 days |
Finance Lease, Weighted Average Remaining Lease Term | 19 years 1 month 6 days | 20 years 1 month 24 days |
Operating Lease, Weighted Average Discount Rate, Percent | 3.62% | 3.27% |
Finance Lease, Weighted Average Discount Rate, Percent | 3.07% | 3.07% |
Operating Leased Assets [Line Items] | ||
Finance Lease, Right-of-Use Asset | $ 99,967 | $ 105,020 |
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Public Utilities, Property, Plant and Equipment, Net | Public Utilities, Property, Plant and Equipment, Net |
Common Plant | ||
Leases [Abstract] | ||
Finance Lease, Right-of-Use Asset | $ 58,391 | $ 61,227 |
Operating Leased Assets [Line Items] | ||
Finance Lease, Right-of-Use Asset | 58,391 | 61,227 |
Electric Transmission | ||
Leases [Abstract] | ||
Finance Lease, Right-of-Use Asset | 41,576 | 43,793 |
Operating Leased Assets [Line Items] | ||
Finance Lease, Right-of-Use Asset | $ 41,576 | $ 43,793 |
Leases (Remaining Cash Payments
Leases (Remaining Cash Payments) (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Leases [Abstract] | ||
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months | $ 23,676 | |
Lessee, Operating Lease, Liability, Payments, Due Year Two | 23,232 | |
Lessee, Operating Lease, Liability, Payments, Due Year Three | 21,887 | |
Lessee, Operating Lease, Liability, Payments, Due Year Four | 21,472 | |
Lessee, Operating Lease, Liability, Payments, Due Year Five | 21,047 | |
Lessee, Operating Lease, Liability, Payments, Due after Year Five | 172,969 | |
Lessee, Operating Lease, Liability, Payments, Due | 284,283 | |
Lessee, Operating Lease, Liability, Undiscounted Excess Amount | (82,676) | |
Operating Lease, Liability | 201,607 | $ 192,908 |
Finance Lease, Liability, Payments, Due Next Twelve Months | 6,383 | |
Finance Lease, Liability, Payments, Due Year Two | 6,408 | |
Finance Lease, Liability, Payments, Due Year Three | 6,534 | |
Finance Lease, Liability, Payments, Due Year Four | 6,591 | |
Finance Lease, Liability, Payments, Due Year Five | 6,670 | |
Finance Lease, Liability, Payments, Due after Year Five | 109,882 | |
Finance Lease, Liability, Payment, Due | 142,468 | |
Finance Lease, Liability, Undiscounted Excess Amount | (36,783) | |
Finance Lease, Liability | $ 105,685 | $ 107,045 |
Accounting for Derivative Ins_3
Accounting for Derivative Instruments and Hedging Activities (Schedule of Derivative Assets and Liabilities) (Details) $ in Thousands, MMBTU in Millions | Dec. 31, 2022 USD ($) MMBTU | Dec. 31, 2021 USD ($) MMBTU |
Derivative [Line Items] | ||
Assets, Current | $ 587,029 | $ 128,210 |
Assets, Long-term | 94,621 | 26,197 |
Liabilities, Current | 124,976 | 63,309 |
Liabilities, Long-term | 18,366 | 40,965 |
Not Designated as Hedging Instrument | ||
Derivative [Line Items] | ||
Assets, Current | 587,029 | 128,210 |
Assets, Long-term | 94,621 | 26,197 |
Total derivative assets | 681,650 | 154,407 |
Liabilities, Current | 124,976 | 63,309 |
Liabilities, Long-term | 18,366 | 40,965 |
Total derivative liabilities | $ 143,342 | $ 104,274 |
Not Designated as Hedging Instrument | Electric Generation Fuel | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | MMBTU | 234.9 | 238 |
Not Designated as Hedging Instrument | Purchased Electricity | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | MMBTU | 5.3 | 8.1 |
Not Designated as Hedging Instrument | Natural Gas Portfolio | ||
Derivative [Line Items] | ||
Total derivative assets | $ 343,947 | $ 79,578 |
Total derivative liabilities | 56,222 | 18,850 |
Not Designated as Hedging Instrument | Electric Portfolio | ||
Derivative [Line Items] | ||
Total derivative assets | 337,703 | 74,829 |
Total derivative liabilities | $ 87,120 | $ 85,424 |
Not Designated as Hedging Instrument | Gas Derivatives | ||
Derivative [Line Items] | ||
Derivative, Nonmonetary Notional Amount | MMBTU | 322 | 347 |
Accounting for Derivative Ins_4
Accounting for Derivative Instruments and Hedging Activities (Offsetting) (Details) - Commodity Contract [Member] - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Derivative Asset, Fair Value, Amount Offset Against Collateral [Abstract] | ||
Derivative Asset, Fair Value, Gross Asset | $ 681,650 | $ 154,407 |
Derivative Asset, Collateral, Obligation to Return Cash, Offset | 0 | 0 |
Derivative Asset | 681,650 | 154,407 |
Derivative, Collateral, Obligation to Return Securities | 125,334 | 40,833 |
Derivative, Collateral, Obligation to Return Cash | 0 | 0 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 556,316 | 113,574 |
Derivative Liability, Fair Value, Amount Offset Against Collateral [Abstract] | ||
Derivative Liability, Fair Value, Gross Liability | 143,342 | 104,274 |
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 0 | 0 |
Derivative Liability | 143,342 | 104,274 |
Derivative, Collateral, Right to Reclaim Securities | 125,334 | 40,833 |
Derivative, Collateral, Right to Reclaim Cash | 5,661 | 1,743 |
Derivative Liability, Fair Value, Amount Offset Against Collateral | $ 12,347 | $ 61,698 |
Accounting for Derivative Ins_5
Accounting for Derivative Instruments and Hedging Activities (Schedule of Amounts Recognized in Statement of Income) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Derivative Instruments, (Loss) Gain [Line Items] | |||
Unrealized (gain) loss on derivative instruments, net | $ 261,177 | $ 13,785 | $ (26,807) |
Electricity, US Regulated [Member] | |||
Derivative Instruments, (Loss) Gain [Line Items] | |||
Posted Collateral | 23,200 | ||
Electric Portfolio | |||
Derivative Instruments, (Loss) Gain [Line Items] | |||
Posted Collateral | 56,200 | 12,782 | |
Unrealized gain (loss) on derivative instruments, net | 147,100 | (21,600) | (21,300) |
Electric Portfolio | Credit Rating | |||
Derivative Instruments, (Loss) Gain [Line Items] | |||
Posted Collateral | 0 | 0 | |
Not Designated as Hedging Instrument | |||
Derivative Instruments, (Loss) Gain [Line Items] | |||
Unrealized (gain) loss on derivative instruments, net | 440,644 | 87,245 | (36,519) |
Not Designated as Hedging Instrument | Commodity Contract [Member] | Electric Generation Fuel | |||
Derivative Instruments, (Loss) Gain [Line Items] | |||
Unrealized (gain) loss on derivative instruments, net | 158,550 | 76,504 | 5,246 |
Not Designated as Hedging Instrument | Commodity Contract [Member] | Purchased Electricity | |||
Derivative Instruments, (Loss) Gain [Line Items] | |||
Unrealized (gain) loss on derivative instruments, net | 20,917 | (3,044) | (14,958) |
Not Designated as Hedging Instrument | Electric Generation Fuel | Unrealized (Gain) Loss on Derivative Instruments, Net | |||
Derivative Instruments, (Loss) Gain [Line Items] | |||
Unrealized (gain) loss on derivative instruments, net | 61,761 | 26,686 | 5,534 |
Not Designated as Hedging Instrument | Electricity, US Regulated [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net | |||
Derivative Instruments, (Loss) Gain [Line Items] | |||
Unrealized (gain) loss on derivative instruments, net | $ 199,416 | $ (12,901) | $ (32,341) |
Accounting for Derivative Ins_6
Accounting for Derivative Instruments and Hedging Activities (Narrative) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Derivative [Line Items] | ||||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs | $ 115,951 | $ (44,872) | $ (24,853) | $ (2,097) |
Included in earnings | 180,533 | (15,839) | (23,559) | |
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities) | 301 | (1,749) | (1,049) | |
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements | (20,603) | (2,431) | 1,852 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3 | 0 | 0 | 0 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3 | $ 592 | 0 | 0 | |
Fair Value, Net Derivative Asset (Liability), Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Unrealized (gain) loss on derivative instruments, net | |||
Subsidiaries [Member] | ||||
Derivative [Line Items] | ||||
Hedging strategy number of years extended | 3 years | |||
Natural Gas Portfolio | ||||
Derivative [Line Items] | ||||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs | $ (127) | (2,120) | (1,135) | 1,282 |
Included in earnings | 0 | 0 | 0 | |
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities) | 301 | (1,749) | (1,049) | |
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements | 1,369 | 764 | (1,368) | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3 | 0 | 0 | 0 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3 | 323 | 0 | 0 | |
Electric Portfolio | ||||
Derivative [Line Items] | ||||
Posted Collateral | 56,200 | 12,782 | ||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs | 116,078 | (42,752) | (23,718) | $ (3,379) |
Included in earnings | 180,533 | (15,839) | (23,559) | |
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities) | 0 | 0 | 0 | |
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements | (21,972) | (3,195) | 3,220 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3 | 0 | 0 | 0 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3 | 269 | 0 | $ 0 | |
Electricity, US Regulated [Member] | ||||
Derivative [Line Items] | ||||
Posted Collateral | 23,200 | |||
Natural Gas, US Regulated [Member] | ||||
Derivative [Line Items] | ||||
Posted Collateral | $ 33,000 | |||
External Credit Rating, Investment Grade [Member] | ||||
Derivative [Line Items] | ||||
Percentage of derivatives with credit risk exposure | 99.40% | |||
External Credit Rating, Non Investment Grade [Member] | ||||
Derivative [Line Items] | ||||
Percentage of derivatives with credit risk exposure | 0.60% | |||
Credit Rating | Natural Gas Portfolio | Standby Letters of Credit | ||||
Derivative [Line Items] | ||||
Posted Collateral | $ 28,000 | |||
Line of Credit Facility, Capacity Available for Specific Purpose Other than for Trade Purchases | 50,000 | |||
Credit Rating | Electric Portfolio | ||||
Derivative [Line Items] | ||||
Posted Collateral | $ 0 | $ 0 |
Accounting for Derivative Ins_7
Accounting for Derivative Instruments and Hedging Activities (Schedule of Contractual Contingent Liability Positions) (Details) - Electric Portfolio - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Derivative [Line Items] | ||
Fair Value Liability | $ 12,975 | $ 63,660 |
Posted Collateral | 56,200 | 12,782 |
Contingent Collateral | 3,157 | 52,537 |
Forward Value of Contract [Member] | ||
Derivative [Line Items] | ||
Fair Value Liability | 5,661 | 1,743 |
Posted Collateral | 56,200 | 12,782 |
Requested Credit for Adequate Assurance | ||
Derivative [Line Items] | ||
Fair Value Liability | 4,157 | 9,380 |
Posted Collateral | 0 | 0 |
Contingent Collateral | 0 | 0 |
Credit Rating | ||
Derivative [Line Items] | ||
Fair Value Liability | 3,157 | 52,537 |
Posted Collateral | 0 | 0 |
Contingent Collateral | $ 3,157 | $ 52,537 |
Fair Value Measurements - Debt
Fair Value Measurements - Debt at Carrying and Fair Value (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Carrying Amount | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Notes Receivable, Fair Value Disclosure | $ 55,000 | $ 53,200 |
Carrying Amount | Income Approach Valuation Technique | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Unamortized Debt Issuance Expense | 21,500 | 22,700 |
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure | 6,629,073 | 6,170,466 |
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure | 34,300 | 33,300 |
Total | Income Approach Valuation Technique | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure | 6,149,797 | 7,769,896 |
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure | 34,300 | 33,300 |
Subsidiaries [Member] | Carrying Amount | Income Approach Valuation Technique | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure | 4,786,765 | 4,784,719 |
Subsidiaries [Member] | Carrying Amount | Income Approach Valuation Technique | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Unamortized Debt Issuance Expense | 21,400 | 22,800 |
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure | 4,786,765 | 4,784,719 |
Subsidiaries [Member] | Total | Income Approach Valuation Technique | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure | 4,379,010 | 6,145,639 |
Subsidiaries [Member] | Total | Income Approach Valuation Technique | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure | 4,379,010 | 6,145,639 |
Parent Company [Member] | Carrying Amount | Income Approach Valuation Technique | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure | 6,663,373 | 6,203,766 |
Parent Company [Member] | Total | Income Approach Valuation Technique | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure | $ 6,184,097 | $ 7,803,196 |
Fair Value Measurements - Sched
Fair Value Measurements - Schedule of Assets and Liabilities (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Derivative Asset | $ 681,650 | $ 154,407 |
Derivative Liability | 143,342 | 104,274 |
Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Derivative Asset | 561,598 | 147,537 |
Derivative Liability | 139,241 | 52,532 |
Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Derivative Asset | 120,052 | 6,870 |
Derivative Liability | 4,101 | 51,742 |
Electric Portfolio | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Derivative Asset | 337,703 | 74,829 |
Derivative Liability | 87,120 | 85,424 |
Electric Portfolio | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Derivative Asset | 218,610 | 68,011 |
Derivative Liability | 84,105 | 35,854 |
Electric Portfolio | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Derivative Asset | 119,093 | 6,818 |
Derivative Liability | 3,015 | 49,570 |
Natural Gas Portfolio | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Derivative Asset | 343,947 | 79,578 |
Derivative Liability | 56,222 | 18,850 |
Natural Gas Portfolio | Fair Value, Inputs, Level 2 [Member] | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Derivative Asset | 342,988 | 79,526 |
Derivative Liability | 55,136 | 16,678 |
Natural Gas Portfolio | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Derivative Asset | 959 | 52 |
Derivative Liability | $ 1,086 | $ 2,172 |
Fair Value Measurements - Unobs
Fair Value Measurements - Unobservable Input Reconciliation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | |||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Beginning Balance | $ (44,872) | $ (24,853) | $ (2,097) |
Included in earnings | 180,533 | (15,839) | (23,559) |
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities) | 301 | (1,749) | (1,049) |
Settlements | (20,603) | (2,431) | 1,852 |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3 | 0 | 0 | 0 |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3 | 592 | 0 | 0 |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Ending Balance | 115,951 | (44,872) | (24,853) |
Electric Portfolio | |||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | |||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Beginning Balance | (42,752) | (23,718) | (3,379) |
Included in earnings | 180,533 | (15,839) | (23,559) |
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities) | 0 | 0 | 0 |
Settlements | (21,972) | (3,195) | 3,220 |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3 | 0 | 0 | 0 |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3 | 269 | 0 | 0 |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Ending Balance | 116,078 | (42,752) | (23,718) |
Unrealized gain (loss) on derivative instruments, net | 147,100 | (21,600) | (21,300) |
Natural Gas Portfolio | |||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | |||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Beginning Balance | (2,120) | (1,135) | 1,282 |
Included in earnings | 0 | 0 | 0 |
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities) | 301 | (1,749) | (1,049) |
Settlements | 1,369 | 764 | (1,368) |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3 | 0 | 0 | 0 |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3 | 323 | 0 | 0 |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Ending Balance | $ (127) | $ (2,120) | $ (1,135) |
Fair Value Measurements - Forwa
Fair Value Measurements - Forward Price Ranges (Details) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 USD ($) $ / MMBTU $ / MWh | Dec. 31, 2021 USD ($) | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair Value measurement, sensitivity analysis, hypothetical increase or decrease of market prices, result on fair value, percent | 10% | |
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value | $ 37,600 | |
Fair Value, Measurements, Recurring | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 681,650 | $ 154,407 |
Derivative Liability | 143,342 | 104,274 |
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 120,052 | 6,870 |
Derivative Liability | 4,101 | 51,742 |
Natural Gas Portfolio | Fair Value, Measurements, Recurring | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 343,947 | 79,578 |
Derivative Liability | 56,222 | 18,850 |
Natural Gas Portfolio | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 959 | 52 |
Derivative Liability | $ 1,086 | 2,172 |
Natural Gas Portfolio | Income Approach Valuation Technique | Minimum | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU | 3.84 | |
Natural Gas Portfolio | Income Approach Valuation Technique | Maximum | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU | 7 | |
Natural Gas Portfolio | Income Approach Valuation Technique | Weighted Average | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU | 4.87 | |
Natural Gas Portfolio | Parent Company [Member] | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | $ 959 | |
Derivative Liability | 1,086 | |
Electric Portfolio | Fair Value, Measurements, Recurring | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 337,703 | 74,829 |
Derivative Liability | 87,120 | 85,424 |
Electric Portfolio | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | 119,093 | 6,818 |
Derivative Liability | $ 3,015 | $ 49,570 |
Electric Portfolio | Income Approach Valuation Technique | Minimum | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Power prices (per MWh) | $ / MWh | 55.79 | |
Electric Portfolio | Income Approach Valuation Technique | Maximum | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Power prices (per MWh) | $ / MWh | 291.03 | |
Electric Portfolio | Income Approach Valuation Technique | Weighted Average | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Power prices (per MWh) | $ / MWh | 131.51 | |
Electric Portfolio | Parent Company [Member] | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset | $ 119,093 | |
Derivative Liability | $ 3,015 |
Fair Value Measurements - Valua
Fair Value Measurements - Valuations (Details) | 12 Months Ended |
Dec. 31, 2022 USD ($) | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |
Impairment of Intangible Assets, Finite-Lived | $ 0 |
Fair Value Measurements - Uno_2
Fair Value Measurements - Unobservable Input (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 USD ($) $ / MMBTU $ / MWh | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value | $ 37,600 | ||
Fair Value measurement, sensitivity analysis, hypothetical increase or decrease of market prices, result on fair value, percent | 10% | ||
Fair Value, Measurements, Recurring | |||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Derivative Asset | $ 681,650 | $ 154,407 | |
Derivative Liability | 143,342 | 104,274 | |
Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Recurring | |||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Derivative Asset | 120,052 | 6,870 | |
Derivative Liability | 4,101 | 51,742 | |
Electric Portfolio | Fair Value, Measurements, Recurring | |||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Derivative Asset | 337,703 | 74,829 | |
Derivative Liability | 87,120 | 85,424 | |
Electric Portfolio | Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Recurring | |||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Derivative Asset | 119,093 | 6,818 | |
Derivative Liability | 3,015 | 49,570 | |
Natural Gas Portfolio | Fair Value, Measurements, Recurring | |||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Derivative Asset | 343,947 | 79,578 | |
Derivative Liability | 56,222 | 18,850 | |
Natural Gas Portfolio | Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Recurring | |||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Derivative Asset | 959 | 52 | |
Derivative Liability | 1,086 | 2,172 | |
Parent Company [Member] | Electric Portfolio | Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Recurring | |||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Derivative Asset | 119,093 | ||
Derivative Liability | 3,015 | ||
Parent Company [Member] | Natural Gas Portfolio | Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Recurring | |||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Derivative Asset | 959 | ||
Derivative Liability | 1,086 | ||
Firm Storage and Peaking Service [Member] | |||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Long-term Purchase Commitment, Demand Charges | 138,300 | 136,400 | $ 135,800 |
Combustion turbines | |||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Long-term Purchase Commitment, Demand Charges | $ 53,900 | $ 52,800 | $ 51,200 |
Minimum | Income Approach Valuation Technique | Electric Portfolio | |||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Power prices (per MWh) | $ / MWh | 55.79 | ||
Minimum | Income Approach Valuation Technique | Natural Gas Portfolio | |||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU | 3.84 | ||
Maximum | Income Approach Valuation Technique | Electric Portfolio | |||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Power prices (per MWh) | $ / MWh | 291.03 | ||
Maximum | Income Approach Valuation Technique | Natural Gas Portfolio | |||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU | 7 | ||
Weighted Average | Income Approach Valuation Technique | Electric Portfolio | |||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Power prices (per MWh) | $ / MWh | 131.51 | ||
Weighted Average | Income Approach Valuation Technique | Natural Gas Portfolio | |||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU | 4.87 |
Employee Investment Plans - Nar
Employee Investment Plans - Narrative (Details) - Subsidiaries [Member] - USD ($) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Defined Contribution Plan Disclosure [Line Items] | |||
Employer discretionary contribution amount | $ 25,200,000 | $ 23,600,000 | $ 22,100,000 |
Employer matching contribution, percent | 4.50% | ||
Maximum annual contribution per employee, percent | 6% | ||
employer contribution [Member] | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Employer matching contribution, percent | 4% | ||
Collective Bargaining Arrangement Member [Member] | employer contribution [Member] | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Employer matching contribution, percent | 4% | ||
Cash Balance Formula | Collective Bargaining Arrangement Member [Member] | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Employer matching contribution, percent | 100% | ||
Maximum annual contribution per employee, percent | 6% | ||
Employer additional contribution of base pay, percentage | 1% | ||
Final Average Earnings Formula | Collective Bargaining Arrangement Member [Member] | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Employer matching contribution, percent | 55% | ||
Maximum annual contribution per employee, percent | 6% | ||
Second 3 Percent | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Employer matching contribution, percent | 50% | ||
Maximum annual contribution per employee, percent | 3% | ||
First 3 Percent | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Employer matching contribution, percent | 100% | ||
Maximum annual contribution per employee, percent | 3% |
Retirement Benefits - Change in
Retirement Benefits - Change in Net Benefit Obligation and Fair Value (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Other Pension Plan [Member] | ||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||
Benefit obligation at beginning of period | $ 11,654 | $ 12,114 |
Amendments | 38 | 205 |
Service cost | 217 | 155 |
Interest cost | 311 | 302 |
Actuarial loss (gain) | 2,397 | 514 |
Benefits paid | 808 | 803 |
Medicare part D subsidy received | 0 | 195 |
Administrative expense | 0 | 0 |
Benefit obligation at end of period | 9,015 | 11,654 |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||
Fair value of plan assets at beginning of period | 6,341 | 5,918 |
Actual return on plan assets | (550) | 1,005 |
Employer contribution | 207 | 222 |
Benefits paid | (808) | (804) |
Administrative expense | 0 | 0 |
Fair value of plan assets at end of period | 5,190 | 6,341 |
Funded status at end of period | (3,825) | (5,313) |
Nonqualified Plan | Pension Plan [Member] | ||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||
Benefit obligation at beginning of period | 43,155 | 46,742 |
Amendments | 0 | 0 |
Service cost | 557 | 456 |
Interest cost | 1,253 | 1,183 |
Actuarial loss (gain) | 5,260 | (828) |
Benefits paid | 7,659 | 6,054 |
Medicare part D subsidy received | 0 | 0 |
Administrative expense | 0 | 0 |
Benefit obligation at end of period | 32,046 | 43,155 |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||
Fair value of plan assets at beginning of period | 0 | 0 |
Actual return on plan assets | 0 | 0 |
Employer contribution | 7,659 | 6,054 |
Benefits paid | (7,659) | (6,054) |
Administrative expense | 0 | 0 |
Fair value of plan assets at end of period | 0 | 0 |
Funded status at end of period | (32,046) | (43,155) |
Qualified Plan | Pension Plan [Member] | ||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||
Benefit obligation at beginning of period | 834,960 | 849,383 |
Amendments | 0 | 0 |
Service cost | 26,351 | 26,888 |
Interest cost | 24,263 | 22,381 |
Actuarial loss (gain) | 215,005 | 6,826 |
Benefits paid | 80,226 | 55,831 |
Medicare part D subsidy received | 0 | 0 |
Administrative expense | (1,065) | (1,035) |
Benefit obligation at end of period | 589,278 | 834,960 |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||
Fair value of plan assets at beginning of period | 898,550 | 834,655 |
Actual return on plan assets | (176,537) | 102,787 |
Employer contribution | 18,000 | 18,000 |
Benefits paid | (80,226) | (55,831) |
Administrative expense | (1,254) | (1,061) |
Fair value of plan assets at end of period | 658,533 | 898,550 |
Funded status at end of period | $ 69,255 | $ 63,590 |
Retirement Benefits - Amounts R
Retirement Benefits - Amounts Recognized (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Other Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Projected benefit obligation | $ 9,015 | $ 11,654 | $ 12,114 |
Accumulated benefit obligation | 8,929 | 11,549 | |
Fair value of plan assets | 5,190 | 6,341 | 5,918 |
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract] | |||
Noncurrent assets | 0 | 0 | |
Current liabilities | (252) | (280) | |
Noncurrent liabilities | (3,573) | (5,033) | |
Net assets (liabilities) | (3,825) | (5,313) | |
Parent Company [Member] | Other Pension Plan [Member] | |||
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract] | |||
Accumulated Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Tax | (1,964) | (525) | |
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax | 259 | 242 | |
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total | (1,705) | (283) | |
Subsidiaries [Member] | Other Pension Plan [Member] | |||
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract] | |||
Accumulated Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Tax | (2,056) | (622) | |
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax | 258 | 242 | |
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total | (1,798) | (380) | |
Nonqualified Plan | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Projected benefit obligation | 32,046 | 43,155 | 46,742 |
Accumulated benefit obligation | 29,763 | 40,773 | |
Fair value of plan assets | 0 | 0 | 0 |
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract] | |||
Noncurrent assets | 0 | 0 | |
Current liabilities | (3,532) | (2,822) | |
Noncurrent liabilities | (28,514) | (40,333) | |
Net assets (liabilities) | (32,046) | (43,155) | |
Nonqualified Plan | Parent Company [Member] | Pension Plan [Member] | |||
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract] | |||
Accumulated Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Tax | 1,563 | 9,571 | |
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax | 289 | 578 | |
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total | 1,852 | 10,149 | |
Nonqualified Plan | Subsidiaries [Member] | Pension Plan [Member] | |||
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract] | |||
Accumulated Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Tax | 1,864 | 10,103 | |
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax | 289 | 578 | |
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total | 2,153 | 10,681 | |
Qualified Plan | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Projected benefit obligation | 589,278 | 834,960 | 849,383 |
Accumulated benefit obligation | 582,538 | 823,418 | |
Fair value of plan assets | 658,533 | 898,550 | $ 834,655 |
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract] | |||
Noncurrent assets | 69,255 | 63,590 | |
Current liabilities | 0 | 0 | |
Noncurrent liabilities | 0 | 0 | |
Net assets (liabilities) | 69,255 | 63,590 | |
Qualified Plan | Parent Company [Member] | Pension Plan [Member] | |||
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract] | |||
Accumulated Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Tax | 31,213 | 24,859 | |
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax | 0 | 0 | |
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total | 31,213 | 24,859 | |
Qualified Plan | Subsidiaries [Member] | Pension Plan [Member] | |||
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract] | |||
Accumulated Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Tax | 124,767 | 127,111 | |
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax | 0 | 0 | |
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total | $ 124,767 | $ 127,111 |
Retirement Benefits - Net Perio
Retirement Benefits - Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Other Pension Plan [Member] | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||
Service cost | $ 217 | $ 155 | |
Interest cost | 311 | 302 | |
Parent Company [Member] | Other Pension Plan [Member] | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||
Service cost | 217 | 155 | $ 190 |
Interest cost | 311 | 302 | 368 |
Expected return on plan assets | (379) | (355) | (389) |
Amortization of prior service cost (credit) | 22 | 6 | 0 |
Amortization of net loss (gain) | (29) | (39) | (82) |
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total | 142 | 69 | 87 |
Subsidiaries [Member] | Other Pension Plan [Member] | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||
Service cost | 217 | 155 | 190 |
Interest cost | 311 | 302 | 368 |
Expected return on plan assets | (379) | (355) | (389) |
Amortization of prior service cost (credit) | 22 | 6 | 0 |
Amortization of net loss (gain) | (35) | (52) | (137) |
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total | 136 | 56 | 32 |
Nonqualified Plan | Pension Plan [Member] | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||
Service cost | 557 | 456 | |
Interest cost | 1,253 | 1,183 | |
Nonqualified Plan | Parent Company [Member] | Pension Plan [Member] | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||
Service cost | 557 | 456 | 756 |
Interest cost | 1,253 | 1,183 | 1,464 |
Expected return on plan assets | 0 | 0 | 0 |
Amortization of prior service cost (credit) | 289 | 349 | 349 |
Amortization of net loss (gain) | 2,471 | 2,165 | 2,122 |
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total | 4,570 | 4,153 | 4,691 |
Nonqualified Plan | Subsidiaries [Member] | Pension Plan [Member] | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||
Service cost | 557 | 456 | 756 |
Interest cost | 1,253 | 1,183 | 1,464 |
Expected return on plan assets | 0 | 0 | 0 |
Amortization of prior service cost (credit) | 289 | 349 | 349 |
Amortization of net loss (gain) | 2,648 | 2,344 | 2,385 |
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total | 4,747 | 4,332 | 4,954 |
Qualified Plan | Pension Plan [Member] | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||
Service cost | 26,351 | 26,888 | |
Interest cost | 24,263 | 22,381 | |
Qualified Plan | Parent Company [Member] | Pension Plan [Member] | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||
Service cost | 26,351 | 26,888 | 24,337 |
Interest cost | 24,263 | 22,381 | 25,180 |
Expected return on plan assets | (51,014) | (48,239) | (49,902) |
Amortization of prior service cost (credit) | 0 | (1,904) | (1,980) |
Amortization of net loss (gain) | 6,381 | 11,803 | 8,160 |
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total | 5,981 | 10,929 | 5,795 |
Qualified Plan | Subsidiaries [Member] | Pension Plan [Member] | |||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract] | |||
Service cost | 26,351 | 26,888 | 24,337 |
Interest cost | 24,263 | 22,381 | 25,180 |
Expected return on plan assets | (51,016) | (48,242) | (49,910) |
Amortization of prior service cost (credit) | 0 | (1,513) | (1,573) |
Amortization of net loss (gain) | 15,080 | 21,862 | 19,043 |
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total | $ 14,678 | $ 21,376 | $ 17,077 |
Retirement Benefits - Benefit O
Retirement Benefits - Benefit Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Subsidiaries [Member] | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Employer matching contribution, percent | 4.50% | |
Defined Contribution Plan, Interest Credit | 4% | |
Subsidiaries [Member] | employer contribution [Member] | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Employer matching contribution, percent | 4% | |
Subsidiaries [Member] | employer contribution [Member] | Collective Bargaining Arrangement Member [Member] | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Employer matching contribution, percent | 4% | |
Subsidiaries [Member] | employer contribution [Member] | Collective Bargaining Arrangement Member [Member] | UA represented [Member] | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Employer matching contribution, percent | 4% | |
Subsidiaries [Member] | employer contribution [Member] | Collective Bargaining Arrangement Member [Member] | IBEW represented [Member] | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Employer matching contribution, percent | 4% | |
Other Pension Plan [Member] | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Net loss (gain) | $ 1,468 | $ 1,164 |
Amortization of net (loss) gain | 29 | 39 |
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax | 0 | 0 |
Prior service cost (credit) | 38 | 205 |
Amortization of prior service (cost) credit | 22 | 6 |
Total change in other comprehensive income for year | (1,423) | (926) |
Other Pension Plan [Member] | Subsidiaries [Member] | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Net loss (gain) | 1,468 | 1,164 |
Amortization of net (loss) gain | 35 | 53 |
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax | 0 | 0 |
Prior service cost (credit) | 38 | 205 |
Amortization of prior service (cost) credit | 22 | 6 |
Total change in other comprehensive income for year | (1,417) | (912) |
Qualified Plan | Pension Plan [Member] | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Net loss (gain) | (12,735) | 61,348 |
Amortization of net (loss) gain | (6,381) | (11,803) |
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax | 0 | 0 |
Prior service cost (credit) | 0 | 0 |
Amortization of prior service (cost) credit | 0 | (1,904) |
Total change in other comprehensive income for year | 6,354 | (71,247) |
Qualified Plan | Pension Plan [Member] | Subsidiaries [Member] | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Net loss (gain) | (12,736) | 61,345 |
Amortization of net (loss) gain | (15,080) | (21,862) |
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax | 0 | 0 |
Prior service cost (credit) | 0 | 0 |
Amortization of prior service (cost) credit | 0 | (1,513) |
Total change in other comprehensive income for year | (2,344) | (81,694) |
Nonqualified Plan | Pension Plan [Member] | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Net loss (gain) | 5,260 | (828) |
Amortization of net (loss) gain | (2,471) | (2,164) |
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax | 277 | (830) |
Prior service cost (credit) | 0 | 0 |
Amortization of prior service (cost) credit | 289 | 349 |
Total change in other comprehensive income for year | (8,297) | (2,515) |
Nonqualified Plan | Pension Plan [Member] | Subsidiaries [Member] | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Net loss (gain) | 5,260 | (828) |
Amortization of net (loss) gain | (2,648) | (2,343) |
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax | 331 | (886) |
Prior service cost (credit) | 0 | 0 |
Amortization of prior service (cost) credit | 289 | 349 |
Total change in other comprehensive income for year | $ (8,528) | $ (2,750) |
Retirement Benefits - Textuals
Retirement Benefits - Textuals (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2023 | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Five-year smoothing of asset gains (losses) | 5 years | |
Subsidiaries [Member] | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Contribution Plan, Interest Credit | 4% | |
Forecast | Qualified Plan | Subsidiaries [Member] | Pension Plan [Member] | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Estimated Future Employer Contributions in Current Fiscal Year | $ 18 | |
Forecast | Nonqualified Plan | Subsidiaries [Member] | Pension Plan [Member] | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Estimated Future Employer Contributions in Current Fiscal Year | 3.5 | |
Forecast | Other Pension Plan [Member] | Subsidiaries [Member] | Pension Plan [Member] | ||
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Estimated Future Employer Contributions in Current Fiscal Year | $ 0.3 |
Retirement Benefits - Assumptio
Retirement Benefits - Assumptions (Details) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Other Pension Plan [Member] | |||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Discount rate | 5.60% | 3% | 2.70% |
Rate of compensation increase | 4.50% | 4.50% | 4.50% |
Benefit Cost Assumptions: | |||
Discount rate | 3% | 2.70% | 3.35% |
Return on plan assets | 7% | 7% | 7% |
Rate of compensation increase | 4.50% | 4.50% | 4.50% |
Nonqualified Plan | Pension Plan [Member] | |||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Discount rate | 5.60% | 3% | 2.70% |
Rate of compensation increase | 4.50% | 4.50% | 4.50% |
Benefit Cost Assumptions: | |||
Discount rate | 3% | 2.70% | 3.35% |
Return on plan assets | 0% | 0% | 0% |
Rate of compensation increase | 4.50% | 4.50% | 4.50% |
Qualified Plan | Pension Plan [Member] | |||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Discount rate | 5.60% | 3% | 2.70% |
Rate of compensation increase | 4.50% | 4.50% | 4.50% |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Weighted-Average Interest Crediting Rate | 4% | 4% | 4% |
Benefit Cost Assumptions: | |||
Discount rate | 3% | 2.70% | 3.35% |
Return on plan assets | 6.50% | 6.50% | 7.15% |
Rate of compensation increase | 4.50% | 4.50% | 4.50% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Weighted-Average Interest Crediting Rate | 4% | 4% | 4% |
Retirement Benefits - Future Be
Retirement Benefits - Future Benefit Payments (Details) $ in Thousands | Dec. 31, 2022 USD ($) |
Other Pension Plan [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2020 | $ 912 |
2021 | 890 |
2022 | 881 |
2023 | 879 |
2024 | 854 |
2025-2029 | 3,829 |
Qualified Plan | Pension Plan [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2020 | 46,500 |
2021 | 47,800 |
2022 | 48,700 |
2023 | 49,900 |
2024 | 50,700 |
2025-2029 | 260,700 |
Nonqualified Plan | Pension Plan [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2020 | 3,532 |
2021 | 1,844 |
2022 | 7,634 |
2023 | 2,271 |
2024 | 10,956 |
2025-2029 | $ 7,479 |
Retirement Benefits - Plan Asse
Retirement Benefits - Plan Asset Allocation (Details) | Dec. 31, 2022 |
Domestic Large Cap Equity Investments [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Allocation | 31% |
Domestic Small Cap Equity Investments [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Allocation | 9% |
Foreign Equity Funds [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Allocation | 25% |
Fixed Income Securities [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Allocation | 35% |
Real Estate Funds [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Allocation | 0% |
Cash and cash equivalents | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Allocation | 0% |
Minimum | Domestic Large Cap Equity Investments [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Allocation | 25% |
Minimum | Foreign Equity Funds [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Allocation | 10% |
Minimum | Fixed Income Securities [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Allocation | 25% |
Maximum | Domestic Large Cap Equity Investments [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Allocation | 40% |
Maximum | Domestic Small Cap Equity Investments [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Allocation | 15% |
Maximum | Foreign Equity Funds [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Allocation | 30% |
Maximum | Fixed Income Securities [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Allocation | 40% |
Maximum | Real Estate Funds [Member] | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Allocation | 10% |
Maximum | Cash and cash equivalents | |
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Allocation | 5% |
Retirement Benefits - Recurring
Retirement Benefits - Recurring Fair Value Measures (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Other Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | $ 5,190 | $ 6,341 | $ 5,918 |
Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 4 | |
Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 5,190 | 6,337 | |
Fair Value Measured at Net Asset Value Per Share [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 658,533 | 898,550 | |
Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 5,190 | 6,341 | |
Mutual Funds | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Mutual Funds | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 5,190 | 6,337 | |
Mutual Funds | Fair Value Measured at Net Asset Value Per Share [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Mutual Funds | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 5,190 | 6,337 | |
US Treasury and Government [Member] | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 61,693 | 65,266 | |
US Treasury and Government [Member] | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 8,828 | 2,470 | |
US Treasury and Government [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
US Treasury and Government [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 70,521 | 67,736 | |
Cash and cash equivalents | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 4,678 | 3,638 | |
Cash and cash equivalents | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | (632) | (540) | |
Cash and cash equivalents | Fair Value Measured at Net Asset Value Per Share [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Cash and cash equivalents | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 4,046 | 3,098 | |
Equity Investments [Member] | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 260,107 | 343,888 | |
Equity Investments [Member] | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 31,024 | 20,088 | |
Equity Investments [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 367,402 | 534,574 | |
Net Receivables [Member] | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Net Receivables [Member] | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Net Receivables [Member] | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Net Receivables [Member] | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Net Receivables [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | (29,186) | (23,015) | |
Net Receivables [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Net Receivables [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | (29,186) | (23,015) | |
Net Receivables [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Partnership/Jointed Ventures | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Partnership/Jointed Ventures | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Partnership/Jointed Ventures | Fair Value Measured at Net Asset Value Per Share [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 86,827 | 115,570 | |
Partnership/Jointed Ventures | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 86,827 | 115,570 | |
Collective Investment Funds | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Collective Investment Funds | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Collective Investment Funds | Fair Value Measured at Net Asset Value Per Share [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 262,910 | 359,861 | |
Collective Investment Funds | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 262,910 | 359,861 | |
Other Security Investments | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Other Security Investments | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Other Security Investments | Fair Value Measured at Net Asset Value Per Share [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 846 | 1,434 | |
Other Security Investments | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 846 | 1,434 | |
Mutual Fund | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Mutual Fund | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Mutual Fund | Fair Value Measured at Net Asset Value Per Share [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 46,005 | 80,724 | |
Mutual Fund | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 46,005 | 80,724 | |
Corporate Bond Securities - Foreign | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Corporate Bond Securities - Foreign | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 6,525 | 5,239 | |
Corporate Bond Securities - Foreign | Fair Value Measured at Net Asset Value Per Share [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Corporate Bond Securities - Foreign | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 6,525 | 5,239 | |
Corporate Bond Securities - US | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Corporate Bond Securities - US | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 16,005 | 12,820 | |
Corporate Bond Securities - US | Fair Value Measured at Net Asset Value Per Share [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Corporate Bond Securities - US | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 16,005 | 12,820 | |
Common Stock - US | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 175,969 | 249,021 | |
Common Stock - US | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 298 | 99 | |
Common Stock - US | Fair Value Measured at Net Asset Value Per Share [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Common Stock - US | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 176,267 | 249,120 | |
Common Stock - Foreign | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 17,767 | 25,963 | |
Common Stock - Foreign | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Common Stock - Foreign | Fair Value Measured at Net Asset Value Per Share [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Common Stock - Foreign | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 17,767 | 25,963 | |
Money Market Funds | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 4 | |
Money Market Funds | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Money Market Funds | Fair Value Measured at Net Asset Value Per Share [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 0 | 0 | |
Money Market Funds | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | $ 0 | $ 4 |
Income Taxes - Components of In
Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Income Tax Disclosures [Line Items] | |||
Current Federal Tax Expense (Benefit) | $ 41,198 | $ 25,395 | $ 7,962 |
Current State and Local Tax Expense (Benefit) | 628 | 721 | 7 |
Deferred Federal Income Tax Expense (Benefit) | 17,866 | (1,759) | (6,414) |
Deferred State and Local Income Tax Expense (Benefit) | 6 | 158 | 109 |
Total income tax expense | $ 59,698 | 24,515 | 1,664 |
Valuation Allowance, Commentary | No | ||
Subsidiaries [Member] | |||
Income Tax Disclosures [Line Items] | |||
Current Federal Tax Expense (Benefit) | $ 81,597 | 52,616 | 10,607 |
Current State and Local Tax Expense (Benefit) | 869 | 670 | 383 |
Deferred Federal Income Tax Expense (Benefit) | (2,171) | (9,027) | 15,252 |
Deferred State and Local Income Tax Expense (Benefit) | 0 | 0 | 0 |
Total income tax expense | $ 80,295 | $ 44,259 | $ 26,242 |
Income Taxes - Deferred Income
Income Taxes - Deferred Income Taxes (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Deferred Tax Liabilities, Gross | ||
Deferred Tax Liabilities, Property, Plant and Equipment | $ 1,853,450 | $ 1,892,692 |
Deferred tax liability, unrealized gain or loss on derivative instruments | 158,175 | 50,971 |
Deferred Tax Liabilities, Other | 365,035 | 313,270 |
Deferred Tax Liabilities, Gross, Total | 2,376,660 | 2,256,933 |
Deferred Tax Assets, Gross | ||
Deferred Tax Assets, Operating Loss Carryforwards | (234,825) | (254,007) |
Deferred Tax Assets, Net Regulatory Liability for Income Taxes | (811,161) | (865,976) |
Deferred Tax Assets, Tax Credit Carryforwards, Production | 0 | |
Deferred Tax Assets, Other | (299,597) | (184,023) |
Deferred tax asset, unrealized loss on derivative instruments | (45,130) | (40,443) |
Deferred Tax Assets, Gross | (1,390,713) | (1,344,449) |
Deferred Tax Liabilities, Net, Total | 985,947 | 912,484 |
Subsidiaries [Member] | ||
Deferred Tax Liabilities, Gross | ||
Deferred Tax Liabilities, Property, Plant and Equipment | 1,852,644 | 1,892,674 |
Deferred tax liability, unrealized gain or loss on derivative instruments | 143,147 | 31,940 |
Deferred Tax Liabilities, Other | 279,612 | 225,753 |
Deferred Tax Liabilities, Gross, Total | 2,275,403 | 2,150,367 |
Deferred Tax Assets, Gross | ||
Deferred Tax Assets, Net Regulatory Liability for Income Taxes | (811,724) | (866,541) |
Deferred Tax Assets, Other | (293,977) | (178,211) |
Deferred tax asset, unrealized loss on derivative instruments | (30,102) | (21,412) |
Deferred Tax Assets, Gross | (1,135,803) | (1,066,164) |
Deferred Tax Liabilities, Net, Total | $ 1,139,600 | $ 1,084,203 |
Income Taxes - Balance Sheet Lo
Income Taxes - Balance Sheet Location (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Income Tax Disclosures [Line Items] | |||
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount | $ (13,722) | $ (13,392) | $ (3,038) |
Subsidiaries [Member] | |||
Income Tax Disclosures [Line Items] | |||
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount | (13,722) | (13,392) | $ (3,038) |
ARAM [Member] | |||
Income Tax Disclosures [Line Items] | |||
Deferred Other Tax Expense (Benefit) | $ 27,200 | $ 27,600 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Operating Loss Carryforwards [Line Items] | |||
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount | $ 99,549 | $ 59,927 | $ 38,720 |
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depreciation and Amortization, Amount | (23,028) | (22,325) | (22,991) |
Income Tax Reconciliation, AFUDC (net) | (3,567) | 1,509 | (6,095) |
Income Tax Reconciliation, Executive Compensation | 1,821 | 1,386 | 2,440 |
Income Tax Reconciliation, Treasury Grant | (5,717) | (5,424) | (8,935) |
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount | (13,722) | (13,392) | (3,038) |
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount | 4,362 | 2,834 | 1,563 |
Total income tax expense | $ 59,698 | $ 24,515 | $ 1,664 |
Effective Income Tax Rate Reconciliation, Percent | 12.60% | 8.60% | 0.90% |
Deferred Tax Assets, Tax Credit Carryforwards, Production | $ 0 | ||
Subsidiaries [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount | $ 119,962 | 79,868 | $ 63,110 |
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depreciation and Amortization, Amount | (23,028) | (22,325) | (22,991) |
Income Tax Reconciliation, AFUDC (net) | (3,567) | 1,509 | (6,095) |
Income Tax Reconciliation, Executive Compensation | 1,821 | 1,386 | 2,440 |
Income Tax Reconciliation, Treasury Grant | (5,717) | (5,424) | (8,935) |
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount | (13,722) | (13,392) | (3,038) |
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount | 4,546 | 2,637 | 1,751 |
Total income tax expense | $ 80,295 | $ 44,259 | $ 26,242 |
Effective Income Tax Rate Reconciliation, Percent | 14.10% | 11.60% | 8.70% |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Operating Loss Carryforwards [Line Items] | ||
Valuation Allowance, Commentary | No | |
Unrecognized Tax Benefits | $ 0 | $ 0 |
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense | 0 | 0 |
Deferred Tax Assets, Tax Credit Carryforwards, Production | 0 | |
ARAM [Member] | ||
Operating Loss Carryforwards [Line Items] | ||
Deferred Other Tax Expense (Benefit) | $ 27,200,000 | $ 27,600,000 |
Litigation (Details)
Litigation (Details) - Subsidiaries [Member] | Dec. 31, 2022 |
Colstrip Unit 4 [Member] | |
Jointly Owned Utility Plant Interests | |
Company’s Ownership Share | 25% |
Colstrip Units 1 & 2 | |
Jointly Owned Utility Plant Interests | |
Company’s Ownership Share | 50% |
Commitments and Contingencies_2
Commitments and Contingencies (Details) | 1 Months Ended | 12 Months Ended | ||||
Feb. 07, 2023 USD ($) | Nov. 30, 2022 MW | Mar. 31, 2021 MW | Dec. 31, 2022 USD ($) MWh Contracts MW | Dec. 31, 2021 USD ($) MWh | Dec. 31, 2020 USD ($) MWh | |
Long-term Purchase Commitment [Line Items] | ||||||
Long-term Line of Credit, Noncurrent | $ 34,300,000 | $ 33,300,000 | ||||
Average cost of Company's energy output (US$ per kWh) | $ 0.034 | |||||
Number of Public Utility Districts with long term purchase agreements | Contracts | 3 | |||||
Contract expenses | $ 149,575,000 | $ 117,812,000 | $ 116,874,000 | |||
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased | 16.40% | |||||
Long-term Contract for Purchase of Electric Power, Capacity | MW | 956 | |||||
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost | $ 203,889,000 | |||||
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required | 18,605,000 | |||||
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges | 7,791,000 | |||||
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding | 146,786,000 | |||||
Payment Obligations for Power Purchases | ||||||
2023 | 986,455,000 | |||||
2024 | 679,513,000 | |||||
2025 | 497,760,000 | |||||
2026 | 292,371,000 | |||||
2027 | 257,055,000 | |||||
Thereafter | 2,171,578,000 | |||||
Total | $ 4,884,732,000 | |||||
Total energy obtained during period under purchased power contracts (MWh) | MWh | 15.3 | 13.1 | 13.2 | |||
Cost incurred during period to provide energy under purchased power contracts | $ 892,700,000 | $ 631,400,000 | $ 491,700,000 | |||
Daily take obligation under long-term service contract (percent) | 100% | |||||
Daily delivery obligation under long-term service contract (percent) | 100% | |||||
Natural Gas [Member] | ||||||
Payment Obligations for Power Purchases | ||||||
2023 | $ 1,013,547,000 | |||||
2024 | 377,588,000 | |||||
2025 | 351,129,000 | |||||
2026 | 255,577,000 | |||||
2027 | 76,453,000 | |||||
Thereafter | 0 | |||||
Total | 2,074,294,000 | |||||
Colombia River Projects [Member] | ||||||
Payment Obligations for Power Purchases | ||||||
2023 | 191,618,000 | |||||
2024 | 145,078,000 | |||||
2025 | 140,887,000 | |||||
2026 | 138,482,000 | |||||
2027 | 123,152,000 | |||||
Thereafter | 394,875,000 | |||||
Non-Utility Generators [Member] | ||||||
Payment Obligations for Power Purchases | ||||||
Total | 586,138,000 | |||||
Firm Transportation Service [Member] | ||||||
Payment Obligations for Power Purchases | ||||||
2023 | 175,136,000 | |||||
2024 | 146,675,000 | |||||
2025 | 112,327,000 | |||||
2026 | 94,417,000 | |||||
2027 | 94,123,000 | |||||
Thereafter | 570,687,000 | |||||
Total | 1,193,365,000 | |||||
Firm Storage and Peaking Service [Member] | ||||||
Payment Obligations for Power Purchases | ||||||
2023 | 9,350,000 | |||||
2024 | 7,923,000 | |||||
2025 | 7,448,000 | |||||
2026 | 7,432,000 | |||||
2027 | 7,352,000 | |||||
Thereafter | 1,838,000 | |||||
Total | 41,343,000 | |||||
Long-term Purchase Commitment, Demand Charges | 138,300,000 | 136,400,000 | 135,800,000 | |||
Combustion turbines | ||||||
Payment Obligations for Power Purchases | ||||||
Long-term Purchase Commitment, Demand Charges | 53,900,000 | $ 52,800,000 | $ 51,200,000 | |||
Energy production service contracts | ||||||
Payment Obligations for Power Purchases | ||||||
2023 | 33,971,000 | |||||
2024 | 34,812,000 | |||||
2025 | 35,772,000 | |||||
2026 | 18,728,000 | |||||
2027 | 19,221,000 | |||||
Thereafter | 79,655,000 | |||||
Total | 222,159,000 | |||||
Automated meter reading system | ||||||
Payment Obligations for Power Purchases | ||||||
2023 | 50,124,000 | |||||
2024 | 47,301,000 | |||||
2025 | 47,668,000 | |||||
2026 | 48,803,000 | |||||
2027 | 0 | |||||
Thereafter | 0 | |||||
Total | 193,896,000 | |||||
Service contract obligations | ||||||
Payment Obligations for Power Purchases | ||||||
2023 | 84,095,000 | |||||
2024 | 82,113,000 | |||||
2025 | 83,440,000 | |||||
2026 | 67,531,000 | |||||
2027 | 19,221,000 | |||||
Thereafter | 79,655,000 | |||||
Total | 416,055,000 | |||||
Service contract obligations | Subsequent Event [Member] | ||||||
Payment Obligations for Power Purchases | ||||||
Total | $ 3,100,000,000 | |||||
Colombia River Projects [Member] | ||||||
Payment Obligations for Power Purchases | ||||||
Total | 1,134,092,000 | |||||
Other Utilities [Member] | ||||||
Payment Obligations for Power Purchases | ||||||
Total | 3,164,502,000 | |||||
Electric Portfolio | ||||||
Payment Obligations for Power Purchases | ||||||
2023 | 380,559,000 | |||||
2024 | 385,807,000 | |||||
2025 | 345,257,000 | |||||
2026 | 142,273,000 | |||||
2027 | 133,903,000 | |||||
Thereafter | 1,776,703,000 | |||||
Firm natural gas supply | ||||||
Payment Obligations for Power Purchases | ||||||
2023 | 1,198,033,000 | |||||
2024 | 532,186,000 | |||||
2025 | 470,904,000 | |||||
2026 | 357,426,000 | |||||
2027 | 177,928,000 | |||||
Thereafter | 572,525,000 | |||||
Total | $ 3,309,002,000 | |||||
Minimum | Combustion turbines | ||||||
Payment Obligations for Power Purchases | ||||||
Remaining terms under contract | 1 year | |||||
Maximum | Combustion turbines | ||||||
Payment Obligations for Power Purchases | ||||||
Remaining terms under contract | 22 years | |||||
Rock Island Project | ||||||
Long-term Purchase Commitment [Line Items] | ||||||
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased | 5% | 30% | ||||
Long-term Contract for Purchase of Electric Power, Capacity | MW | 31 | 187 | ||||
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost | $ 47,892,000 | |||||
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required | 12,072,000 | |||||
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges | 5,132,000 | |||||
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding | $ 93,493,000 | |||||
Rock Island Project | Subsequent Event [Member] | ||||||
Long-term Purchase Commitment [Line Items] | ||||||
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased | 25% | |||||
Rocky Reach Project | ||||||
Long-term Purchase Commitment [Line Items] | ||||||
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased | 5% | 30% | ||||
Long-term Contract for Purchase of Electric Power, Capacity | MW | 65 | 390 | ||||
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost | $ 54,022,000 | |||||
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required | 5,039,000 | |||||
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges | 1,907,000 | |||||
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding | $ 33,757,000 | |||||
Rocky Reach Project | Subsequent Event [Member] | ||||||
Long-term Purchase Commitment [Line Items] | ||||||
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased | 25% | |||||
Wells Project [Member] | ||||||
Long-term Purchase Commitment [Line Items] | ||||||
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased | 5.50% | 32.80% | ||||
Long-term Contract for Purchase of Electric Power, Capacity | MW | 46,000,000 | 276 | ||||
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost | $ 45,489,000 | |||||
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required | 0 | |||||
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges | 0 | |||||
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding | $ 0 | |||||
Priest Rapids Development | ||||||
Long-term Purchase Commitment [Line Items] | ||||||
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased | 4.80% | |||||
Long-term Contract for Purchase of Electric Power, Capacity | MW | 39,000,000 | 45 | ||||
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost | $ 28,243,000 | |||||
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required | 747,000 | |||||
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges | 376,000 | |||||
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding | $ 9,768,000 | |||||
Wanapum Development | ||||||
Long-term Purchase Commitment [Line Items] | ||||||
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased | 4.80% | |||||
Long-term Contract for Purchase of Electric Power, Capacity | MW | 51,000,000 | 58 | ||||
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost | $ 28,243,000 | |||||
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required | 747,000 | |||||
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges | 376,000 | |||||
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding | 9,768,000 | |||||
Priest Rapids Project | ||||||
Long-term Purchase Commitment [Line Items] | ||||||
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased | 4.13% | |||||
Electricity, US Regulated [Member] | ||||||
Payment Obligations for Power Purchases | ||||||
2023 | 414,278,000 | |||||
2024 | 148,628,000 | |||||
2025 | 11,616,000 | |||||
2026 | 11,616,000 | |||||
2027 | 0 | |||||
Thereafter | $ 0 |
Related Party Transactions (Det
Related Party Transactions (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2022 USD ($) | |
Related Party Transaction [Line Items] | |
Related Party Transaction, Amounts of Transaction | $ 0 |
Segment Information (Details)
Segment Information (Details) | 12 Months Ended |
Dec. 31, 2022 mi² segment | |
Segment Reporting Information [Line Items] | |
Number of operating segments | segment | 1 |
Subsidiaries [Member] | |
Segment Reporting Information [Line Items] | |
Area of service territory (sqmi) | mi² | 6,000 |
Accumulated Other Comprehensi_3
Accumulated Other Comprehensive Income (Loss) Changes in AOCI, net of tax (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Accumulated other comprehensive income (loss), net of tax | $ (27,432) | ||
Accumulated other comprehensive income (loss), net of tax | (24,774) | $ (27,432) | |
Subsidiaries [Member] | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Accumulated other comprehensive income (loss), net of tax | (113,141) | ||
Accumulated other comprehensive income (loss), net of tax | (103,044) | (113,141) | |
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Accumulated other comprehensive income (loss), net of tax | (27,432) | (86,437) | $ (84,149) |
Other comprehensive income (loss) before reclassifications | (4,559) | 49,226 | (9,058) |
Amounts reclassified from accumulated other comprehensive income (loss), net of tax | 7,217 | 9,779 | 6,770 |
Net current-period other comprehensive income (loss) | 2,658 | 59,005 | (2,288) |
Accumulated other comprehensive income (loss), net of tax | (24,774) | (27,432) | (86,437) |
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | Subsidiaries [Member] | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Accumulated other comprehensive income (loss), net of tax | (108,541) | (175,972) | (183,108) |
Other comprehensive income (loss) before reclassifications | (4,512) | 49,265 | (8,717) |
Amounts reclassified from accumulated other comprehensive income (loss), net of tax | 14,223 | 18,166 | 15,853 |
Net current-period other comprehensive income (loss) | 9,711 | 67,431 | 7,136 |
Accumulated other comprehensive income (loss), net of tax | (98,830) | (108,541) | (175,972) |
Comprehensive Income [Member] | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Accumulated other comprehensive income (loss), net of tax | (27,432) | (86,437) | (84,149) |
Other comprehensive income (loss) before reclassifications | (4,559) | 49,226 | (9,058) |
Amounts reclassified from accumulated other comprehensive income (loss), net of tax | 7,217 | 9,779 | 6,770 |
Net current-period other comprehensive income (loss) | 2,658 | 59,005 | (2,288) |
Accumulated other comprehensive income (loss), net of tax | (24,774) | (27,432) | (86,437) |
Comprehensive Income [Member] | Subsidiaries [Member] | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Accumulated other comprehensive income (loss), net of tax | (113,141) | (180,956) | (188,477) |
Other comprehensive income (loss) before reclassifications | (4,512) | 49,265 | (8,717) |
Amounts reclassified from accumulated other comprehensive income (loss), net of tax | 14,609 | 18,550 | 16,238 |
Net current-period other comprehensive income (loss) | 10,097 | 67,815 | 7,521 |
Accumulated other comprehensive income (loss), net of tax | (103,044) | (113,141) | (180,956) |
Interest Rate Swap [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member] | Subsidiaries [Member] | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||
Accumulated other comprehensive income (loss), net of tax | (4,600) | (4,984) | (5,369) |
Other comprehensive income (loss) before reclassifications | 0 | 0 | 0 |
Amounts reclassified from accumulated other comprehensive income (loss), net of tax | 386 | 384 | 385 |
Net current-period other comprehensive income (loss) | 386 | 384 | 385 |
Accumulated other comprehensive income (loss), net of tax | $ (4,214) | $ (4,600) | $ (4,984) |
Accumulated Other Comprehensi_4
Accumulated Other Comprehensive Income (Loss) Reclassifications Out of Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Reclassification out of Accumulated Other Comprehensive Income | Parent Company [Member] | |||
Reclassification out of Accumulated Other Comprehensive Income [Line Items] | |||
Total reclassification for the period | $ (7,217) | $ (9,779) | $ (6,770) |
Reclassification out of Accumulated Other Comprehensive Income | Subsidiaries [Member] | |||
Reclassification out of Accumulated Other Comprehensive Income [Line Items] | |||
Total reclassification for the period | (14,609) | (18,550) | (16,238) |
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | Parent Company [Member] | |||
Reclassification out of Accumulated Other Comprehensive Income [Line Items] | |||
Amortization of prior service (cost) credit | (311) | 1,549 | 1,631 |
Amortization of net (loss) gain | (8,824) | (13,928) | (10,200) |
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax | (9,135) | (12,379) | (8,569) |
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax | 1,918 | 2,600 | 1,799 |
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, after Tax | (7,217) | (9,779) | (6,770) |
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Noncontrolling Interest [Member] | Subsidiaries [Member] | Interest Rate Swap [Member] | |||
Reclassification out of Accumulated Other Comprehensive Income [Line Items] | |||
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent | (488) | (487) | (487) |
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, Tax | (102) | (103) | (102) |
Total reclassification for the period | (386) | (384) | (385) |
Accumulated Defined Benefit Plans Adjustment Attributable to Noncontrolling Interest [Member] | Subsidiaries [Member] | |||
Reclassification out of Accumulated Other Comprehensive Income [Line Items] | |||
Amortization of prior service (cost) credit | (311) | 1,158 | 1,224 |
Amortization of net (loss) gain | (17,693) | (24,153) | (21,291) |
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax | (18,004) | (22,995) | (20,067) |
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax | 3,781 | 4,829 | 4,214 |
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, after Tax | $ (14,223) | $ (18,166) | $ (15,853) |
SCHEDULE I CONDENSED FINANCIA_2
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Statements of Income (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Condensed Financial Statements, Captions [Line Items] | ||||
Nonutility Expense And Other | $ (59,804) | $ (58,281) | $ (43,425) | |
Interest expense | (347,921) | (352,092) | (373,822) | |
Income Tax Expense (Benefit) | (59,698) | (24,515) | (1,664) | |
Net income (loss) | 414,345 | 260,849 | 182,717 | |
Comprehensive income (loss) | 417,003 | 319,854 | 180,429 | |
Condensed Cash Flow Statements, Captions [Line Items] | ||||
Net Cash Provided by (Used in) Operating Activities | 769,618 | 826,598 | 727,568 | |
Other | 567 | (1,367) | (5,340) | |
Net Cash Provided by (Used in) Investing Activities | (1,005,280) | (920,777) | (902,796) | |
Dividends paid | 16,230 | 106,420 | 45,421 | |
Investment from parent | 0 | 210,000 | 4,575 | |
Short-term debt | 301,300 | (233,800) | 197,800 | |
Proceeds from Issuance of Long-term Debt | 448,075 | 961,538 | 644,690 | |
Redemption of bonds and notes | 450,000 | 502,410 | 450,000 | |
Net Cash Provided by (Used in) Financing Activities | 301,297 | 115,478 | 190,933 | |
Net increase (decrease) in cash, cash equivalents, and restricted cash | 65,635 | 21,299 | 15,705 | |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | 168,785 | 103,150 | 81,851 | $ 66,146 |
Parent Company [Member] | ||||
Condensed Financial Statements, Captions [Line Items] | ||||
Nonutility Expense And Other | (1,206) | (913) | (1,579) | |
Equity In Net Income (Loss) Of Subsidiaries | 474,873 | 337,405 | 277,654 | |
Investment Income, Interest | 8,458 | 4,261 | 4,760 | |
Interest expense | (84,051) | (100,002) | (123,592) | |
Income Tax Expense (Benefit) | 16,271 | 20,098 | 25,474 | |
Net income (loss) | 414,345 | 260,849 | 182,717 | |
Comprehensive income (loss) | 417,003 | 319,854 | 180,429 | |
Condensed Cash Flow Statements, Captions [Line Items] | ||||
Net Cash Provided by (Used in) Operating Activities | (10,197) | 143,691 | 38,280 | |
Adjustments to Additional Paid in Capital, Other | 50,000 | 21,783 | 0 | |
Payments for (Proceeds from) Loans Receivable from Subsidiary | 12,176 | 0 | 31,043 | |
Net Cash Provided by (Used in) Investing Activities | (62,176) | (21,783) | (31,043) | |
Dividends paid | 16,230 | 106,420 | 45,421 | |
Investment from parent | 0 | (210,000) | (4,575) | |
Short-term debt | 84,300 | 0 | 0 | |
Proceeds from Issuance of Long-term Debt | 448,075 | 515,475 | 644,690 | |
Redemption of bonds and notes | 450,000 | 734,000 | 609,400 | |
Issue costs and others | (1,370) | 1,367 | 1,838 | |
Net Cash Provided by (Used in) Financing Activities | 67,515 | (116,312) | (7,394) | |
Net increase (decrease) in cash, cash equivalents, and restricted cash | (4,858) | 5,596 | (157) | |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | $ 1,528 | $ 6,386 | $ 790 | $ 947 |
SCHEDULE I CONDENSED FINANCIA_3
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Balance Sheets (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 |
Other Property And Investments [Abstract] | ||||
Goodwill | $ 1,656,513 | $ 1,656,513 | ||
Current assets: | ||||
Cash and Cash Equivalents, at Carrying Value | 105,740 | 56,946 | ||
Total current assets | 1,997,995 | 1,138,108 | ||
Assets, Noncurrent [Abstract] | ||||
Other | 180,204 | 163,374 | ||
Total assets | 17,187,514 | 15,871,884 | ||
Capitalization, Long-term Debt and Equity [Abstract] | ||||
Stockholders' Equity Attributable to Parent | 4,964,089 | 4,563,316 | $ 4,139,882 | $ 4,000,299 |
Long-term debt | 2,034,300 | 1,583,300 | ||
Total capitalization | 11,627,462 | 10,767,082 | ||
Current liabilities: | ||||
Accounts payable | 665,750 | 444,384 | ||
Short-term debt | 441,300 | 140,000 | ||
Current maturities of long-term debt | 0 | 450,000 | ||
Interest | 62,148 | 67,807 | ||
Unrealized loss on derivative instruments | 124,976 | 63,309 | ||
Total current liabilities | 1,563,474 | 1,425,423 | ||
Liabilities, Noncurrent [Abstract] | ||||
Unrealized loss on derivative instruments | 18,366 | 40,965 | ||
Total capitalization and liabilities | 17,187,514 | 15,871,884 | ||
Parent | ||||
Assets | ||||
Investments in subsidiaries | 4,938,998 | 4,446,758 | ||
Other Property And Investments [Abstract] | ||||
Goodwill | 1,656,513 | 1,656,513 | ||
Current assets: | ||||
Cash and Cash Equivalents, at Carrying Value | 1,528 | 6,386 | ||
Receivables from affiliates | 246,317 | 233,258 | ||
Income Taxes Receivable, Current | 532 | 6,006 | ||
Total current assets | 248,377 | 245,650 | ||
Assets, Noncurrent [Abstract] | ||||
Deferred Tax Assets, Net of Valuation Allowance, Noncurrent | 231,976 | 250,820 | ||
Other | 3,370 | 984 | ||
Assets, Noncurrent, Total | 235,346 | 251,804 | ||
Total assets | 7,079,234 | 6,600,725 | ||
Capitalization, Long-term Debt and Equity [Abstract] | ||||
Stockholders' Equity Attributable to Parent | 4,964,089 | 4,563,316 | ||
Long-term debt | 2,020,734 | 1,571,287 | ||
Total capitalization | 6,984,823 | 6,134,603 | ||
Current liabilities: | ||||
Accounts payable | 133 | 147 | ||
Short-term debt | 84,300 | 0 | ||
Current maturities of long-term debt | 0 | 450,000 | ||
Interest | 9,978 | 15,975 | ||
Total current liabilities | 94,411 | 466,122 | ||
Liabilities, Noncurrent [Abstract] | ||||
Total capitalization and liabilities | $ 7,079,234 | $ 6,600,725 |
SCHEDULE I CONDENSED FINANCIA_4
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Statements of Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2019 | |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||
Net Cash Provided by (Used in) Operating Activities | $ 769,618 | $ 826,598 | $ 727,568 | |
Net Cash Provided by (Used in) Investing Activities | ||||
Other | 567 | (1,367) | (5,340) | |
Net Cash Provided by (Used in) Investing Activities | (1,005,280) | (920,777) | (902,796) | |
Net Cash Provided by (Used in) Financing Activities | ||||
Dividends paid | 16,230 | 106,420 | 45,421 | |
Proceeds from Issuance of Long-term Debt | 448,075 | 961,538 | 644,690 | |
Redemption of bonds and notes | 450,000 | 502,410 | 450,000 | |
Net Cash Provided by (Used in) Financing Activities | 301,297 | 115,478 | 190,933 | |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect | 65,635 | 21,299 | 15,705 | |
Cash, cash equivalents, and restricted cash at end of period | 105,740 | 56,946 | ||
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | 168,785 | 103,150 | 81,851 | $ 66,146 |
Parent Company [Member] | ||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||
Net Cash Provided by (Used in) Operating Activities | (10,197) | 143,691 | 38,280 | |
Net Cash Provided by (Used in) Investing Activities | ||||
Adjustments to Additional Paid in Capital, Other | (50,000) | (21,783) | 0 | |
Net Cash Provided by (Used in) Investing Activities | (62,176) | (21,783) | (31,043) | |
Net Cash Provided by (Used in) Financing Activities | ||||
Dividends paid | 16,230 | 106,420 | 45,421 | |
Proceeds from Issuance of Long-term Debt | 448,075 | 515,475 | 644,690 | |
Redemption of bonds and notes | 450,000 | 734,000 | 609,400 | |
Net Cash Provided by (Used in) Financing Activities | 67,515 | (116,312) | (7,394) | |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect | (4,858) | 5,596 | (157) | |
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | $ 1,528 | $ 6,386 | $ 790 | $ 947 |
SCHEDULE I CONDENSED FINANCIA_5
SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY Notes (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Ownership percentage | 100% | ||
Net Income (Loss) | $ 414,345 | $ 260,849 | $ 182,717 |
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 417,003 | 319,854 | 180,429 |
Net Cash Provided by (Used in) Operating Activities | 769,618 | 826,598 | 727,568 |
Net Cash Provided by (Used in) Investing Activities | (1,005,280) | (920,777) | (902,796) |
Business Combination Adjustment, ASC 805 | 1,000 | 2,400 | 3,400 |
Parent Company [Member] | |||
Net Income (Loss) | 414,345 | 260,849 | 182,717 |
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 417,003 | 319,854 | 180,429 |
Net Cash Provided by (Used in) Operating Activities | (10,197) | 143,691 | 38,280 |
Net Cash Provided by (Used in) Investing Activities | (62,176) | (21,783) | (31,043) |
Subsidiaries [Member] | |||
Net Income (Loss) | 490,952 | 336,063 | 274,280 |
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 501,049 | 403,878 | 281,801 |
Net Cash Provided by (Used in) Operating Activities | 817,461 | 920,393 | 824,810 |
Net Cash Provided by (Used in) Investing Activities | (1,001,377) | (906,906) | (871,097) |
PSE and PLNG | |||
Net Income (Loss) | $ 473,800 | $ 335,000 | $ 274,300 |
SCHEDULE II__VALUATION AND QUAL
SCHEDULE II: VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) - SEC Schedule, 12-09, Allowance, Credit Loss [Member] - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward] | |||
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount, Beginning Balance | $ 34,958 | $ 20,080 | $ 8,294 |
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Cost and Expense | 28,316 | 27,204 | 23,292 |
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction | 21,312 | 12,326 | 11,506 |
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount, Ending Balance | $ 41,962 | $ 34,958 | $ 20,080 |