Puget Energy (PSD) 10-K 26 Feb 21 2020 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2020	Jun. 30, 2018
Entity Information [Line Items]
Entity Registrant Name	PUGET ENERGY INC /WA
Entity Central Index Key	0001085392
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float		$ 0
Entity Common Stock, Shares Outstanding	200
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Document Period End Date	Dec. 31, 2020
Document Transition Report	false
Subsidiaries [Member]
Entity Information [Line Items]
Entity Registrant Name	PUGET SOUND ENERGY INC
Entity Central Index Key	0000081100
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float		$ 0
Entity Common Stock, Shares Outstanding	85,903,791
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Document Period End Date	Dec. 31, 2020
Document Transition Report	false

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Electric	$ 2,319,416,000	$ 2,497,041,000	$ 2,455,919,000
Natural gas	980,913,000	875,371,000	850,748,000
Other	26,121,000	28,718,000	39,829,000
Total operating revenue	3,326,450,000	3,401,130,000	3,346,496,000
Purchased electricity	593,719,000	652,560,000	638,775,000
Electric generation fuel	199,107,000	282,864,000	204,174,000
Residential exchange	(80,294,000)	(79,187,000)	(77,454,000)
Purchased natural gas	362,872,000	290,976,000	296,699,000
Unrealized (gain) loss on derivative instruments, net	26,807,000	3,574,000	(41,662,000)
Utility operations and maintenance	597,048,000	596,676,000	602,638,000
Non-utility expense and other	43,425,000	47,907,000	54,519,000
Depreciation and amortization	647,755,000	656,323,000	666,432,000
Conservation amortization	99,585,000	96,571,000	111,714,000
Taxes other than income taxes	328,602,000	333,858,000	336,603,000
Total operating expenses	2,818,626,000	2,882,122,000	2,792,438,000
Operating income (loss)	507,824,000	519,008,000	554,058,000
Other income	58,759,000	59,905,000	52,957,000
Other Nonoperating Expense	(23,207,000)	(9,053,000)	(11,201,000)
AFUDC	14,827,000	14,559,000	13,695,000
Interest expense	(373,822,000)	(356,638,000)	(343,795,000)
Income (loss) before income taxes	184,381,000	227,781,000	265,714,000
Income tax (benefit) expense	1,664,000	17,073,000	30,092,000
Net income (loss)	182,717,000	210,708,000	235,622,000
Subsidiaries [Member]
Electric	2,319,416,000	2,497,041,000	2,455,919,000
Natural gas	980,913,000	875,371,000	850,748,000
Other	26,121,000	28,718,000	39,829,000
Total operating revenue	3,326,450,000	3,401,130,000	3,346,496,000
Purchased electricity	593,719,000	652,560,000	638,775,000
Electric generation fuel	199,107,000	282,864,000	204,174,000
Residential exchange	(80,294,000)	(79,187,000)	(77,454,000)
Purchased natural gas	362,872,000	290,976,000	296,699,000
Unrealized (gain) loss on derivative instruments, net	26,807,000	3,574,000	(41,662,000)
Utility operations and maintenance	597,048,000	596,676,000	602,638,000
Non-utility expense and other	42,266,000	44,403,000	51,549,000
Depreciation and amortization	647,546,000	656,220,000	666,324,000
Conservation amortization	99,585,000	96,571,000	111,714,000
Taxes other than income taxes	328,602,000	333,858,000	336,603,000
Total operating expenses	2,817,258,000	2,878,515,000	2,789,360,000
Operating income (loss)	509,192,000	522,615,000	557,136,000
Other income	46,923,000	47,766,000	39,847,000
Other Nonoperating Expense	(23,207,000)	(9,053,000)	(11,201,000)
AFUDC	14,827,000	14,559,000	13,695,000
Interest expense	(247,213,000)	(243,815,000)	(231,615,000)
Income (loss) before income taxes	300,522,000	332,072,000	367,862,000
Income tax (benefit) expense	26,242,000	39,148,000	50,700,000
Net income (loss)	$ 274,280,000	$ 292,924,000	$ 317,162,000

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Net Income (Loss) Attributable to Parent	$ 182,717,000	$ 210,708,000	$ 235,622,000
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	(2,288,000)	(6,947,000)	(47,690,000)
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	0	0	5,230,000
Other comprehensive income (loss)	(2,288,000)	(6,947,000)	(52,920,000)
Comprehensive income (loss)	180,429,000	203,761,000	182,702,000
Subsidiaries [Member]
Net Income (Loss) Attributable to Parent	274,280,000	292,924,000	317,162,000
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	7,136,000	2,022,000	(37,030,000)
Amortization of treasury interest rate swaps to earnings, net of tax	385,000	385,000	385,000
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	0	0	(27,333,000)
Other comprehensive income (loss)	7,521,000	2,407,000	(63,978,000)
Comprehensive income (loss)	$ 281,801,000	$ 295,331,000	$ 253,184,000

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Net unrealized gain (loss) from pension and postretirement plans, tax	$ (609)	$ (1,846)	$ (12,677)
Subsidiaries [Member]
Net unrealized gain (loss) from pension and postretirement plans, tax	1,897	539	(9,844)
Amortization of Financing Cash Flow Hedge Contracts to Earnings Tax	$ 102	$ 102	$ 102

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Utility Plant [Abstract]
Electric plant	$ 9,200,231	$ 8,811,889
Natural gas plant	4,227,532	3,916,040
Common plant	1,116,524	1,096,649
Less: accumulated provision for depreciation	(3,671,094)	(3,236,240)
Net utility plant	10,873,193	10,588,338
Other property and investments:
Goodwill	1,656,513	1,656,513
Other property and investments	324,184	286,975
Total other property and investments	1,980,697	1,943,488
Current assets:
Cash and cash equivalents	52,307	45,259
Restricted cash	29,544	20,887
Accounts receivable, net of allowance for doubtful accounts	352,132	316,352
Unbilled revenue	221,871	224,657
Materials and supplies, at average cost	118,333	115,684
Fuel and natural gas inventory, at average cost	48,795	52,083
Unrealized gain on derivative instruments	33,015	23,626
Prepaid expenses and other	45,746	27,504
Power contract acquisition adjustment gain	14,874	9,067
Total current assets	916,617	835,119
Other long-term and regulatory assets:
Power cost adjustment mechanism	82,801	41,745
purchase gas adjustment, long-term	87,655	132,766
Regulatory assets related to power contracts	11,728	14,146
Other regulatory assets	747,651	673,021
Unrealized gain on derivative instruments	8,805	7,682
Operating lease right-of-use asset	172,167	183,048
Power contract acquisition adjustment gain	80,900	147,530
Other	80,751	92,980
Total other long-term and regulatory assets	1,272,458	1,292,918
Total assets	15,042,965	14,659,863
Common shareholder’s equity:
Common stock	0	0
Additional paid-in capital	3,313,532	3,308,957
Retained earnings	912,787	775,491
Accumulated other comprehensive income (loss), net of tax	(86,437)	(84,149)
Total common shareholder’s equity	4,139,882	4,000,299
Long-term debt:
First mortgage bonds and senior notes	4,212,000	4,212,000
Pollution control bonds	161,860	161,860
Long-term debt	1,724,700	1,758,100
Debt discount, issuance costs and other	(206,120)	(211,635)
Total long-term debt	5,892,440	5,920,325
Total capitalization	10,032,322	9,920,624
Current liabilities:
Accounts payable	342,404	325,913
Short-term debt	373,800	176,000
Current maturities of long-term debt	526,412	452,412
Accrued expenses:
Taxes	110,752	99,979
Salaries and wages	42,530	50,091
Interest	73,647	74,855
Unrealized loss on derivative instruments	31,441	13,428
Power contract acquisition adjustment loss	2,039	2,418
Operating lease liabilities	19,204	15,862
Other	73,385	107,809
Total current liabilities	1,595,614	1,318,767
Other Long-term and regulatory liabilities:
Deferred income taxes	810,729	824,720
Unrealized loss on derivative instruments	29,833	12,693
Regulatory liabilities	732,498	730,879
Regulatory liability for deferred income taxes	953,274	946,179
Regulatory liabilities related to power contracts	95,774	156,597
Power contract acquisition adjustment loss	9,689	11,728
Operating lease liabilities	160,980	174,327
Other deferred credits	622,252	563,349
Total long-term and regulatory liabilities	3,415,029	3,420,472
Commitments and contingencies (Note 16)
Total capitalization and liabilities	$ 15,042,965	$ 14,659,863
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	$ 11,035,402	$ 10,671,328
Natural gas plant	4,786,419	4,478,048
Common plant	1,139,120	1,121,568
Less: accumulated provision for depreciation	(6,087,748)	(5,682,606)
Net utility plant	10,873,193	10,588,338
Other property and investments:
Other property and investments	83,855	81,112
Total other property and investments	83,855	81,112
Current assets:
Cash and cash equivalents	51,177	44,004
Restricted cash	29,544	20,887
Accounts receivable, net of allowance for doubtful accounts	355,850	319,229
Unbilled revenue	221,871	224,657
Materials and supplies, at average cost	118,333	115,684
Fuel and natural gas inventory, at average cost	47,531	50,818
Unrealized gain on derivative instruments	33,015	23,626
Prepaid expenses and other	45,746	27,504
Total current assets	903,067	826,409
Other long-term and regulatory assets:
Power cost adjustment mechanism	82,801	41,745
purchase gas adjustment, long-term	87,655	132,766
Other regulatory assets	747,651	673,021
Unrealized gain on derivative instruments	8,805	7,682
Operating lease right-of-use asset	172,167	183,048
Other	79,231	90,924
Total other long-term and regulatory assets	1,178,310	1,129,186
Total assets	13,038,425	12,625,045
Common shareholder’s equity:
Common stock	859	859
Additional paid-in capital	3,485,105	3,485,105
Retained earnings	876,401	751,193
Accumulated other comprehensive income (loss), net of tax	(180,956)	(188,477)
Total common shareholder’s equity	4,181,409	4,048,680
Long-term debt:
First mortgage bonds and senior notes	4,212,000	4,212,000
Pollution control bonds	161,860	161,860
Debt discount, issuance costs and other	35,816	37,718
Total long-term debt	4,338,044	4,336,142
Total capitalization	8,519,453	8,384,822
Current liabilities:
Accounts payable	342,504	325,980
Short-term debt	373,800	176,000
Current maturities of long-term debt	2,412	2,412
Accrued expenses:
Taxes	107,254	99,977
Salaries and wages	42,530	50,091
Interest	48,189	48,917
Unrealized loss on derivative instruments	31,441	13,428
Operating lease liabilities	19,204	15,862
Other	73,385	107,809
Total current liabilities	1,040,719	840,476
Other Long-term and regulatory liabilities:
Deferred income taxes	987,382	977,163
Unrealized loss on derivative instruments	29,833	12,693
Regulatory liabilities	731,234	729,614
Regulatory liability for deferred income taxes	953,987	946,936
Operating lease liabilities	160,980	174,327
Other deferred credits	614,837	559,014
Total long-term and regulatory liabilities	3,478,253	3,399,747
Commitments and contingencies (Note 16)
Total capitalization and liabilities	$ 13,038,425	$ 12,625,045
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, 2020	Dec. 31, 2019
Assets
Construction work in progress	$ 712,204	$ 591,199
Current assets:
Allowance for doubtful accounts	$ 20,080	$ 8,294
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	$ 712,204	$ 591,199
Current assets:
Allowance for doubtful accounts	$ 20,080	$ 8,294
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 ($)	Total	Cumulative Effect, Period of Adoption, Adjustment	Common Stock	Additional Paid-in Capital	Retained Earnings	Retained EarningsCumulative Effect, Period of Adoption, Adjustment	Accumulated Other Comprehensive Income (Loss)	Subsidiaries [Member]	Subsidiaries [Member]Cumulative Effect, Period of Adoption, Adjustment	Subsidiaries [Member]Common Stock	Subsidiaries [Member]Additional Paid-in Capital	Subsidiaries [Member]Retained Earnings	Subsidiaries [Member]Retained EarningsCumulative Effect, Period of Adoption, Adjustment	Subsidiaries [Member]Accumulated Other Comprehensive Income (Loss)
Balance at Dec. 31, 2017	$ 3,750,030,000	$ 5,230,000	$ 0	$ 3,308,957,000	$ 465,355,000	$ 5,230,000	$ (24,282,000)	$ 3,601,124,000	$ 27,332,000	$ 859,000	$ 3,275,105,000	$ 452,066,000	$ 27,332,000	$ (126,906,000)
Balance (in shares) at Dec. 31, 2017			200							85,903,791
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	235,622,000				235,622,000			317,162,000				317,162,000
Dividends, Common Stock	(77,204,000)				(77,204,000)			(173,716,000)				(173,716,000)
Other comprehensive income (loss)	(52,920,000)						(52,920,000)	(63,978,000)						(63,978,000)
Proceeds from Contributions from Parent	0							0
Balance at Dec. 31, 2018	3,860,758,000			3,308,957,000	629,003,000		(77,202,000)	3,707,924,000		$ 859,000	3,275,105,000	622,844,000		(190,884,000)
Balance (in shares) at Dec. 31, 2018			200							85,903,791
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	210,708,000				210,708,000			292,924,000				292,924,000
Dividends, Common Stock	(64,220,000)				(64,220,000)			(164,575,000)				(164,575,000)
Other comprehensive income (loss)	(6,947,000)						(6,947,000)	2,407,000						2,407,000
Proceeds from Contributions from Parent	0							210,000,000			210,000,000
Balance at Dec. 31, 2019	$ 4,000,299,000			3,308,957,000	775,491,000		(84,149,000)	$ 4,048,680,000		$ 859,000	3,485,105,000	751,193,000		(188,477,000)
Balance (in shares) at Dec. 31, 2019	200		200					85,903,791		85,903,791
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 182,717,000				182,717,000			$ 274,280,000				274,280,000
Dividends, Common Stock	(45,421,000)				(45,421,000)			(149,072,000)				(149,072,000)
Other comprehensive income (loss)	(2,288,000)						(2,288,000)	7,521,000						7,521,000
Proceeds from Contributions from Parent	4,575,000			4,575,000				0
Balance at Dec. 31, 2020	$ 4,139,882,000			$ 3,313,532,000	$ 912,787,000		$ (86,437,000)	$ 4,181,409,000		$ 859,000	$ 3,485,105,000	$ 876,401,000		$ (180,956,000)
Balance (in shares) at Dec. 31, 2020	200		200					85,903,791		85,903,791

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net Income (Loss) Attributable to Parent	$ 182,717,000	$ 210,708,000	$ 235,622,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	647,755,000	656,323,000	666,432,000
Conservation amortization	99,585,000	96,571,000	111,714,000
Deferred Income Taxes and Tax Credits	(6,287,000)	7,475,000	19,457,000
Unrealized Gain (Loss) on Derivatives	26,807,000	3,574,000	(41,662,000)
Gain (Loss) on Extinguishment of Debt	13,546,000	0	0
Afudc Equity	(23,223,000)	(15,802,000)	(17,191,000)
Production tax credits	(39,761,000)	(68,622,000)	(83,976,000)
Other non-cash		(4,639,000)
Other non-cash	9,069,000		15,339,000
Payment for Pension Benefits	18,000,000	18,000,000	18,000,000
Increase (Decrease) in Other Regulatory Assets	152,417,000	79,233,000	71,348,000
increase (decrease) in purchased gas	(45,111,000)	132,766,000	0
Increase (Decrease) in Other Operating Assets	3,171,000	16,098,000	(2,695,000)
Change in certain current assets and liabilities:
Increase (Decrease) in Accounts and Other Receivables	32,994,000	(3,058,000)	(17,659,000)
Increase (Decrease) in Materials and Supplies	2,649,000	6,018,000	9,177,000
Increase Decrease In Fuel And Gas Inventories	(3,287,000)	(1,268,000)	3,443,000
increase (decrease) in purchased gas adjustment, short-term	0	(9,921,000)	25,972,000
Increase (Decrease) in Prepaid Expense and Other Assets	18,242,000	1,103,000	3,679,000
Increase (Decrease) in Accounts Payable	16,516,000	(116,311,000)	117,270,000
Increase (Decrease) in Income Taxes Payable	10,773,000	(18,133,000)	164,000
Increase (Decrease) in Other Accounts Payable and Accrued Liabilities	(30,854,000)	15,163,000	(7,723,000)
Net Cash Provided by (Used in) Operating Activities, Total	727,568,000	527,336,000	904,181,000
Net Cash Provided by (Used in) Investing Activities
Construction expenditures excluding equity allowance for funds used during construction	908,136,000	959,387,000	1,072,670,000
Payments for (Proceeds from) Other Investing Activities	(5,340,000)	(6,908,000)	(2,097,000)
Net Cash Provided by (Used in) Investing Activities, Total	(902,796,000)	(952,479,000)	(1,070,573,000)
Net Cash Provided by (Used in) Financing Activities
Proceeds from (Repayments of) Short-term Debt	197,800,000	(203,297,000)	49,834,000
Payments of Dividends	45,421,000	64,220,000	77,204,000
Proceeds from Contributions from Parent	4,575,000	0	0
Proceeds from Issuance of Long-term Debt	644,690,000	689,351,000	804,050,000
Repayments of Long-term Debt	450,000,000	0	600,000,000
Repayments of Debt	159,400,000	0	0
Proceeds from (Payments for) Other Financing Activities	(1,311,000)	13,893,000	8,513,000
Net Cash Provided by (Used in) Financing Activities, Total	190,933,000	435,727,000	185,193,000
Net increase (decrease) in cash, cash equivalents, and restricted cash	15,705,000	10,584,000	18,801,000
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Beginning Balance	66,146,000	55,562,000	36,761,000
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Ending Balance	81,851,000	66,146,000	55,562,000
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	336,441,000	328,703,000	322,476,000
Income Taxes Paid, Net	4,974,000	10,616,000	8,303,000
Non-cash financing and investing activities:
Capital Expenditures Incurred but Not yet Paid	58,304,000	58,329,000	97,673,000
Subsidiaries [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net Income (Loss) Attributable to Parent	274,280,000	292,924,000	317,162,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	647,546,000	656,220,000	666,324,000
Conservation amortization	99,585,000	96,571,000	111,714,000
Deferred Income Taxes and Tax Credits	15,271,000	20,474,000	30,995,000
Unrealized Gain (Loss) on Derivatives	26,807,000	3,574,000	(41,662,000)
Afudc Equity	(23,223,000)	(15,802,000)	(17,191,000)
Production tax credits	(39,761,000)	(68,622,000)	(83,976,000)
Other non-cash	(1,575,000)	(15,154,000)	4,428,000
Payment for Pension Benefits	18,000,000	18,000,000	18,000,000
Increase (Decrease) in Other Regulatory Assets	152,417,000	79,173,000	71,348,000
increase (decrease) in purchased gas	(45,111,000)	132,766,000	0
Increase (Decrease) in Other Operating Assets	(8,764,000)	8,967,000	(16,917,000)
Change in certain current assets and liabilities:
Increase (Decrease) in Accounts and Other Receivables	33,835,000	(7,650,000)	(12,626,000)
Increase (Decrease) in Materials and Supplies	2,649,000	6,018,000	9,177,000
Increase Decrease In Fuel And Gas Inventories	(3,287,000)	(1,210,000)	3,443,000
increase (decrease) in purchased gas adjustment, short-term	0	(9,921,000)	25,972,000
Increase (Decrease) in Prepaid Expense and Other Assets	18,242,000	1,103,000	3,679,000
Increase (Decrease) in Accounts Payable	16,549,000	(116,370,000)	117,397,000
Increase (Decrease) in Income Taxes Payable	7,277,000	(18,016,000)	930,000
Increase (Decrease) in Other Accounts Payable and Accrued Liabilities	(29,965,000)	15,371,000	(8,141,000)
Net Cash Provided by (Used in) Operating Activities, Total	824,810,000	623,924,000	995,904,000
Net Cash Provided by (Used in) Investing Activities
Construction expenditures excluding equity allowance for funds used during construction	876,437,000	919,271,000	1,010,506,000
Payments for (Proceeds from) Other Investing Activities	(5,340,000)	(6,908,000)	(2,097,000)
Net Cash Provided by (Used in) Investing Activities, Total	(871,097,000)	(912,363,000)	(1,008,409,000)
Net Cash Provided by (Used in) Financing Activities
Proceeds from (Repayments of) Short-term Debt	197,800,000	(203,297,000)	49,834,000
Payments of Dividends	149,072,000	164,575,000	173,716,000
Proceeds from Contributions from Parent	0	210,000,000	0
Proceeds from Issuance of Long-term Debt	0	443,151,000	594,750,000
Repayments of Long-term Debt	0	0	450,000,000
Proceeds from (Payments for) Other Financing Activities	13,389,000	14,558,000	9,121,000
Net Cash Provided by (Used in) Financing Activities, Total	62,117,000	299,837,000	29,989,000
Net increase (decrease) in cash, cash equivalents, and restricted cash	15,830,000	11,398,000	17,484,000
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Beginning Balance	64,891,000	53,493,000	36,009,000
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Ending Balance	80,721,000	64,891,000	53,493,000
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	228,420,000	219,665,000	221,155,000
Income Taxes Paid, Net	11,521,000	19,269,000	18,124,000
Non-cash financing and investing activities:
Capital Expenditures Incurred but Not yet Paid	58,304,000	58,329,000	97,673,000
Colstrip Units 1 – 4 Common Facilities
Non-cash financing and investing activities:
Increase (Decrease) in Regulatory Assets and Liabilities	$ 0	$ 4,163,000	$ (3,086,000)

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Significant Accounting Policies	(1) 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, currently under construction. 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 3.5%, 3.4%, and 3.3% in 2020, 2019, and 2018, respectively; depreciable natural gas utility plant was 2.9%, 2.8%, and 2.8% in 2020, 2019, and 2018, respectively; and depreciable common utility plant was 7.3%, 7.3% and 7.1% in 2020, 2019, and 2018, 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 August 2015, PSE filed a proposal with the Washington Commission to develop an LNG facility at the Port of Tacoma. Currently under construction at the Port of Tacoma, the facility is expected to be operational in 2021. The Tacoma LNG facility is designed to provide peak-shaving services to PSE’s natural gas customers. By storing surplus natural gas, PSE is able to meet the requirements of peak consumption. LNG will also provide fuel to transportation customers, particularly in the marine market. On January 24, 2018, Puget Sound Clean Air Agency (PSCAA) determined a Supplemental Environmental Impact Statement (SEIS) was necessary in order to rule on the air quality permit for the facility. As a result of requiring a SEIS, the Company's construction schedule was impacted. PSE received the SEIS which concluded the LNG facility would result in a net decrease in GHG emissions providing, in part, that the natural gas for the facility was sourced from British Columbia or Alberta. On December 10, 2019, the PSCAA approved the Notice of Construction permit, a decision which has been appealed to the Washington Pollution Control Hearings Board by each of the Puyallup Tribe of Indians and nonprofit law firm Earthjustice. 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, $231.6 million and $199.9 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, 2020, and December 31, 2019, respectively. Additionally, $0.6 million, $1.2 million, and $2.0 million of operating costs are reported in the Puget Energy "Non-utility expense and other" financial statement line item in 2020, 2019, and 2018, respectively. Additionally, $207.7 million and $162.8 million of 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, 2020, and December 31, 2019, 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 these items at the lower of cost or net realizable value method. 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 $240.8 million, $236.5 million and $239.3 million for 2020, 2019, and 2018, 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 3.0% cap of total revenue for decoupled rate schedules. Any excess revenue above 3.0% will be included in the following year's decoupled rate. The Company will be able to recognize revenue below the 3.0% cap of total revenue for decoupled rate schedules. For revenue deferrals exceeding the annual 3.0% 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. On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 general rate case (GRC) to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. The rate test which limits the amount of revenues PSE can collect in its annual filings increased from 3.0% to 5.0% for natural gas customers but will remain at 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 On January 1, 2020, the Company adopted Accounting Standards Update (ASU) 2016-13 Financial Instruments – Credit Losses (ASC 326) which replaces the incurred loss methodology with an expected loss methodology that is referred to as the current expected credit loss (CECL) methodology. The measurement of expected credit losses under the CECL methodology is applicable to financial assets measured at amortized cost, including trade receivables, loan receivables, and held-to-maturity debt securities. It also applies to off-balance sheet credit exposures not accounted for as insurance (loan commitments, standby letters of credit, financial guarantees, and other similar instruments) and net investments in leases recognized by a lessor in accordance with Topic 842 on leases. The only financial assets within the scope of ASU 2016-13 for the Company are trade receivables. The Company adopted ASU 2016-13 using the modified retrospective method. Results for reporting periods beginning after January 1, 2020 are presented under ASC 326 while prior period amounts continue to be reported in accordance with previously applicable GAAP. The Company did not record an adjustment to retained earnings as of January 1, 2020, for the cumulative effect of adopting ASU 2016-13, as the impact was immaterial. Management 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 for the year ended December 31, 2020: Puget Energy and (Dollars in Thousands) December 31, Allowance for credit losses: Beginning balance $ 8,294 Provision for credit loss expense 23,292 Receivables charged-off (11,506) Total ending allowance balance $ 20,080 The allowance increased during the period due to both an increase in the provision combined with a reduction in receivables charged-off during the period. During 2020, t he Ratepayer Assistance and Preservation of Essential Services proclamation issued by the governor in April 2020 included a moratorium on disconnecting customers, which resulted in a cessation of account receivable write-offs for non-payment. Additionally, the provision increased based on collection experience during the period. 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. Under the December 5, 2017, Washington Commission order regarding PSE’s GRC, the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018. Additionally, costs may only be deferred if the outage meets the Institute of Electrical and Electronics Engineers (IEEE) 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, 2020 and 2019, $39.8 million and $67.5 million of PTCs were estimated to be monetized through tax filings, respectively. 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 other deferred credits 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 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 RECs 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 $4.2 million was recognized in purchased electricity on the Company's consolidated statements of income and included in accounts payable on the Company's consolidated balance sheet for the year ended December 31, 2020.

New Accounting Pronouncements

New Accounting Pronouncements	12 Months Ended
	Dec. 31, 2020
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements	New Accounting Pronouncements Recently Adopted Accounting Guidance C redit Losses In 2016, the FASB issued ASU 2016-13, " Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments". The amendments in the update change how entities account for credit losses on receivables and certain other assets. The guidance requires use of a current expected loss model, which may result in earlier recognition of credit losses than under previous accounting standards. ASU 2016-13 is effective for interim and annual periods beginning on or after December 15, 2019. The measurement of expected credit losses under the CECL methodology is applicable to financial assets measured at amortized cost, including trade receivables. It also applies to off-balance sheet credit exposures not accounted for as insurance and net investments in leases recognized by a lessor in accordance with Topic 842. The Company adopted ASC 326 using the modified retrospective method for all financial assets measured at amortized cost. Results for reporting periods beginning after January 1, 2020, are presented under ASC 326 while prior period amounts continue to be reported in accordance with previously applicable GAAP. Upon implementation as of January 1, 2020, the impact was immaterial and the Company did not record a transition adjustment to retained earnings. Fair Value Measurement In August 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 has no material impact on the Company's results of operations, cash flows, or consolidated balance sheets. Goodwill In January 2017, the FASB issued ASU 2017-04, "Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment." The amendment is an accounting standards update to simplify the accounting for goodwill impairment. This accounting standard updates changes in the procedural steps in determining goodwill impairment by eliminating Step 2 from the goodwill impairment test. A goodwill impairment is measured by the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. This amendment is effective for financial statements issued for fiscal years beginning after December 15, 2019. The Company adopted this update in 2020, and it did not have a material impact on goodwill valuation. 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 ” (Issued March 2020): 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. The Company has term loans, credit agreements, and promissory notes that reference LIBOR. As of December 31, 2020, 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 2022. Retirement Benefits In August 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.

Revenue (Notes)

Revenue (Notes)	12 Months Ended
	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer	Revenue The following table presents disaggregated revenue from contracts with customers, and other revenue by major source: Puget Energy and (Dollars in Thousands) Year Ended December 31, Revenue from Contracts with Customers: 2020 2019 2018 Electric retail $ 2,106,122 $ 2,132,522 $ 2,138,008 Natural gas retail 938,061 870,457 849,898 Other 178,208 308,111 234,187 Total revenue from contracts with customers 3,222,391 3,311,090 3,222,093 Alternative revenue programs 35,006 (18,634) (22,852) Other non-customer revenue 69,053 108,674 147,255 Total operating revenue $ 3,326,450 $ 3,401,130 $ 3,346,496 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. 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: (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, 2020
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, 2020, and 2019, included the following: Puget Sound Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2020 2019 Storm damage costs electric 5 years $ 108,491 $ 121,894 Environmental remediation (a) 102,647 68,486 Decoupling deferrals and interest (b) Less than 2 years 88,504 43,509 PGA receivable 2 years 87,655 132,766 PCA mechanism N/A 82,801 41,745 Chelan PUD contract initiation 10.8 years 76,787 83,875 Deferred Washington Commission AFUDC 30 years 59,763 57,553 Lower Snake River 16.4 years 58,442 62,899 Baker Dam licensing operating and maintenance costs (c) 54,354 56,427 Get to zero depreciation expense deferral N/A 53,236 22,148 Unamortized loss on reacquired debt 1 to 47 years 37,991 40,177 Property tax tracker Less than 2 years 24,860 22,442 Advanced metering infrastructure (a) 22,652 14,845 Generation plant major maintenance, excluding Colstrip 3 to 10 years 10,494 12,744 Mint Farm ownership and operating costs 4.3 years 8,318 10,318 Energy conservation costs (a) 8,009 25,272 Snoqualmie licensing operating and maintenance costs (c) 7,435 7,442 Water heater rental property loss N/A 6,973 — Colstrip major maintenance (d) 4,335 2,929 Washington Commission electric vehicle N/A 3,641 1,430 Colstrip common property 3.4 years 2,472 3,188 White River relicensing and other costs 0.0 years — 6,399 Various other regulatory assets (a) 8,247 9,044 Total PSE regulatory assets $ 918,107 $ 847,532 Deferred income taxes (f) N/A (953,987) (946,936) Cost of removal (e) (508,707) (469,922) Repurposed production tax credits N/A (79,581) (24,823) Production tax credits (f) (47,094) (85,323) Treasury grants 3 years (43,164) (101,981) Decoupling liability Less than 2 years (16,448) (8,500) Green direct N/A (14,313) (2,421) Gain on Sale Shuffleton N/A (11,131) (12,483) Microsoft special contract regulatory liability N/A — (12,661) Various other regulatory liabilities (a) (10,796) (11,500) Total PSE regulatory liabilities (1,685,221) (1,676,550) PSE net regulatory assets (liabilities) $ (767,114) $ (829,018) __________________ (a) Amortization periods vary depending on timing of underlying transactions. (b) Decoupling deferrals and interest includes a 24 month GAAP reserve of $(8.0) million. (c) 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. (d) Amortization to be determined in a future rate filing. (e) The balance is dependent upon the cost of removal of underlying assets and the life of utility plant. (f) Amortize as PTCs are utilized by PSE on its tax return. (g) For additional information, see Note 14,"Income Taxes" to the consolidated financial statements included in Item 8 of this report. Puget Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2020 2019 Total PSE regulatory assets (a) $ 918,107 $ 847,532 Puget Energy acquisition adjustments: Regulatory assets related to power contracts 5 to 32 years 11,728 14,146 Total Puget Energy regulatory assets 929,835 861,678 Total PSE regulatory liabilities (a) (1,685,221) (1,676,550) Puget Energy acquisition adjustments: Deferred income taxes 713 757 Regulatory liabilities related to power contracts 5 to 32 years (95,774) (156,597) Various other regulatory liabilities Varies (1,264) (1,265) Total Puget Energy regulatory liabilities (1,781,546) (1,833,655) Puget Energy net regulatory asset (liabilities) $ (851,711) $ (971,977) ____________________ (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 $508.7 million and $469.9 million in 2020 and 2019, respectively, for the cost of removal of utility plant. These amounts are collected from PSE’s customers through depreciation rates. 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%). General Rate Case Filing 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. PSE requested a return on equity of 9.8% with an overall rate of return of 7.62%. In addition to the traditional areas of focus (revenue requirements, cost allocation, rate design and cost of capital), the Company completed an attrition study and included a portion of the attrition revenue requirement in the overall request in order address the expected regulatory lag in the rate year. Additionally, as the non-plant related excess deferred taxes that resulted from the Tax Cuts and Jobs Act (TCJA) remained outstanding from PSE’s Expedited Rate Filing (ERF) as discussed below, PSE requested in its GRC to pass back the amounts over four years. On September 17, 2019, PSE filed a supplemental filing in the GRC, which provided updates as discussed in our original filing, but did not impact the requested overall electric and natural gas rate increases, return on equity or overall rate of return as originally filed. On January 15, 2020, PSE filed rebuttal testimony which included a reduction to the requested return on equity to 9.5%, which decreased the rate of return to 7.48%. The requested rate increase for both electric and natural gas remained at 6.9% and 7.9%, respectively. For both electric and natural gas PSE did not originally request its full attrition adjustment; therefore, the decrease in return on equity led to a reduction in the electric rate increase of only $1.5 million and did not have an impact on the natural gas rate increase. On July 8, 2020, the Washington Commission issued its order on PSE’s 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 instability created by the COVID-19 pandemic, which reduced the electric revenue increase to approximately $0.9 million, or 0.05% and the natural gas increase to $1.3 million, or 0.15%. The Washington Commission also determined that the Company’s proposed attrition adjustment of $23.9 million for electric and $16.2 million for natural gas was not in the public interest at this time. The order also effectively ends the deferral of depreciation expense associated with PSE’s advanced metering infrastructure (AMI) investment while allowing the deferral on the return on AMI investments through December 31, 2019. Additional AMI investments will be evaluated in future proceedings for deferrals of return until the AMI project is complete. On July 17, 2020, PSE filed a motion for clarification with the Washington Commission seeking clarification on several items. On July 31, 2020, the Washington Commission issued an order granting PSE’s motion for clarification. The ruling adjusted certain items from the final order issued on July 8, 2020, which led to a combined net increase to electric of $59.6 million, or 2.9%, an increase of $30.1 million above the $29.5 million granted in the final order. The order also led to a combined net increase to natural gas of $42.9 million, or 5.6%, an increase of $6.4 million above the $36.5 million granted in the final order. The Washington Commission maintained adjustments which 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 $27.7 million, or 1.3% and the natural gas increase to $0.2 million, or 0.02%. On August 6, 2020, PSE filed a petition for judicial review with the Superior Court of the State of Washington for King County (Superior Court) challenging the portion of the final order that requires PSE to pass back to customers the reversal of plant-related excess deferred income taxes in a manner that may deviate from the Internal Revenue Service (IRS) normalization and consistency rules. On August 7, 2020, PSE filed a motion to stay with the Superior Court related to the portions of the final order under judicial review. On September 14, 2020, the Superior Court denied PSE's motion to stay. PSE reviewed the original Washington Commission order including the ramifications of certain tax issues and requested a Private Letter Ruling (PLR) with the IRS regarding this matter. PSE will continue to utilize the average rate assumption method (ARAM) in the turnaround of certain accelerated tax depreciation benefits on PSE assets. On September 23, 2020, PSE filed a compliance filing with the Washington Commission. The natural gas tariffs became effective October 1, 2020 and the electric tariffs on October 15, 2020. On October 7, 2020, PSE, the Washington Commission and interveners agreed to dismiss the petition for judicial review. The agreement is based on a commitment from the Washington Commission that if the IRS ruling finds that the Washington Commission’s methodology for reversing plant-related excess deferred income taxes is impermissible, the Washington Commission will open a proceeding to review and enact the changes required by the IRS ruling. There is approximately $25.6 million in annual revenue requirement related to the 2019 GRC which PSE has requested it be allowed to track in order to allow the Washington Commission to decide if it is appropriate for PSE to recover, pending the outcome of the IRS ruling. Expedited Rate Filing Rate Adjustment On November 7, 2018, PSE filed an ERF with the Washington Commission. The filing requested to change rates associated with PSE’s delivery and fixed production costs. It did not include variable power costs, purchased gas costs or natural gas pipeline replacement program costs, which are recovered in separate mechanisms. The filing was based on historical test year costs and rate base, and followed the reporting requirements of a Commission Basis Report, as defined by the Washington Administrative Code, but used end of period rate base and certain annualizing adjustments. It did not include any forward-looking or pro-forma adjustments. Included in the filing was a reduction to the overall authorized rate of return from 7.6% to 7.49% to recognize a reduction in debt costs associated with recent debt activity. PSE requested an overall increase in electric rates of $18.9 million annually, which is a 0.9% increase, and an overall increase in natural gas rates of $21.7 million annually, which is a 2.7% increase. On January 22, 2019, all parties in the proceeding reached an agreement on settlement terms that resolved all issues in the filing. The settlement agreement was filed on January 30, 2019. The parties agreed to a $21.5 million rate increase for natural gas and no rate increase for electric which became effective March 1, 2019. As is discussed below, these rates include the offsetting effect of passing back to customers plant related excess deferred income taxes that resulted from the TCJA, using the average rate assumption method (ARAM) amounts to arrive at the settlement rate changes. The settlement agreement provides for the pass back of plant related excess deferred income taxes that resulted from the TCJA using the ARAM methodology based on 2018 amounts beginning March 1, 2019, in the amount of $6.1 million for natural gas customers and $25.9 million for electric customers. The settlement agreement left the determination for the regulatory treatment of the remaining items related to the TCJA, listed below, to PSE’s next GRC, filed June 20, 2019: 1) excess deferred taxes for non-plant-related book/tax differences for periods prior to March 1, 2019, 2) the deferred balance associated with the over-collection of income tax expense for the period January 1 through April 30, 2018 (the time period that encompasses the effective date of the TCJA to May 1, 2018, the effective date of the TCJA rate change); and 3) the turnaround of plant related excess deferred income taxes using the ARAM method for the period from January 2018 through February 2019, the rate effective date for the ERF. The settlement agreement provides that PSE may defer the depreciation expense associated with PSE’s ongoing investment in its AMI investment and may defer the return on the AMI investment that was included in the test year of the filing. As noted above, the 2019 GRC effectively ends all deferrals of AMI depreciation expense and deferrals of return on additional AMI investments will be evaluated in future proceedings. The rate of return adopted in the settlement for reporting and deferral purposes is 7.49%. On February 21, 2019, the Washington Commission approved the settlement with one condition: PSE passed back the deferred balance associated with the tax over-collection of $34.6 million for the period from January 1, 2018, through April 30, 2018, over a one-year period which ended May 1, 2020. Washington Commission Tax Deferral Filing The TCJA was signed into law in December 2017. As a result of this change, PSE re-measured its deferred tax balances under the new corporate tax rate. PSE filed an accounting petition on December 29, 2017, requesting deferred accounting treatment for the impacts of tax reform. The requested deferral accounting treatment resulted in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes for GAAP purposes. Additionally, on March 30, 2018, PSE filed for a rate change for electric and natural gas customers associated with TCJA to reflect the decrease in the federal corporate income tax rate from 35.0% to 21.0%. The overall impact of the rate change, based on the annual period from May 2018 through April 2019, is a revenue decrease of $72.9 million, or 3.4%, for electric and $23.6 million, or 2.7%, for natural gas and became effective May 1, 2018, by operation of law. The March 30, 2018, rate change filing did not address excess deferred taxes or the deferred balance associated with the over-collection of income tax expense of $34.6 million for the period January 1 through April 30, 2018 (the time period that encompasses the effective date of the TCJA through May 1, 2018, the effective date of the rate change). The $34.6 million tax over-collection decreased PSE's revenue and increased the regulatory liability for a refund to customers. While the settlement agreement in the ERF provides for the pass back of plant related excess deferred income taxes that resulted from the TCJA using the ARAM methodology based on 2018 amounts through the PSE Schedule 141X tariff, the ongoing treatment of excess deferred taxes associated with non-plant-related book/tax differences and the treatment of the excess deferred taxes associated with plant related book/tax differences was left to be addressed in PSE’s GRC, which was filed on June 20, 2019. The Washington Commission also required in the ERF order that PSE pass back the deferred balance associated with the tax over-collection for the period from January 1, 2018, through April 30, 2018, as discussed above, over a one-year period which began May 1, 2019. Per PSE’s Schedule 141Y tariff, following the May 2019 through April 2020 refund period, if the residual balance of credit owed to customers will be greater than $0.1 million, PSE would submit a filing no later than July 31, 2020 with a proposal of passing back the residual balance effective September 1, 2020 through August 31, 2021. As this balance was greater than $0.1 million, PSE filed tariff revisions on July 20, 2020 and the Washington Commission approved the filing on August 27, 2020. Finally, the GRC final order determined that PSE is required to pass back 2019 and 2020 protected excess deferred tax reversals totaling $70.8 million over the 12 months following the rate effective period through PSE’s Schedule 141X tariff. The GRC final order also determined that PSE is required to pass back unprotected excess deferred tax balances totaling $38.9 million over 36 months following the rate effective period through PSE’s Schedule 141Z tariff. Further details of the outcome associated with PSE’s tax deferral filing are discussed in the ERF and GRC disclosures. Decoupling Filings While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms assist in mitigating the impact of weather on operating revenue and net income. Since 2013, the Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs from most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues are recovered on a per customer basis regardless of actual consumption levels. PSE's energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. Following each calendar year, PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to April time period. On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with several changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues continue to be recovered on a per customer basis and electric fixed production energy costs are now decoupled and recovered on the basis of a fixed monthly amount. The allowed decoupling revenue for electric and natural gas customers will no longer increase annually each January 1 as occurred prior to December 19, 2017. Approved revenue per customer costs can only be changed in a GRC or ERF. Approved electric fixed production energy costs can only be changed in a GRC or a power cost only rate case. Other changes to the decoupling methodology approved by the Washington Commission include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate test, which limits the amount of revenues PSE can collect in its annual filings, increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism will be reviewed again in PSE’s first rate case filed in or after 2021, or in a separate proceeding, if appropriate. PSE’s decoupling mechanism over- and under- collections will still be collectible or refundable after this effective date even if the decoupling mechanism is not extended. On February 21, 2019, the Washington Commission approved the multi-party settlement agreement which was filed within PSE’s ERF filing. As part of this settlement agreement, electric and natural gas allowed delivery revenue per customer was updated to reflect changes in the approved revenue requirement. For electric, there were no changes to the annual allowed fixed power cost revenue. The changes took effect on March 1, 2019. On July 8, 2020, the Washington Commission issued the final order in Dockets 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 On December 1, 2020, PSE made a tariff correction filing for Schedule 142 amortization rates, with a proposed effective date of January 1, 2021, where it proposed to zero 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. This resulted in an over-collection from electric decoupled customers of approximately $4.3 million at year-end. As part of this filing, PSE has proposed to true up the over-collection amounts for the period of October 15, 2020 through December 31, 2020 in PSE’s annual May 2021 decoupling filing. On December 31, 2020, 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 $8.0 million of electric deferred revenue will not be collected within 24 months of the annual period; therefore a reserve adjustment was booked to 2020 electric decoupling revenue. Natural gas deferred revenue will be collected within 24 months of the annual period; therefore, no reserve adjustment was booked to 2020 natural gas decoupling revenue. The previously unrecognized decoupling deferrals of $0.8 million at December 31, 2018, were recognized as decoupling revenue in the year ended December 31, 2019. 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, 2020, in its PCA mechanism, PSE under recovered its allowable costs by $75.4 million of which $43.3 million was apportioned to customers and $2.0 million of interest was accrued on the deferred customer balance. This compares to an under recovery of allowable costs of $67.2 million for the year ended December 31, 2019, of which $36.0 million amounts were apportioned to customers and accrued $1.0 million of interest on the total deferred customer balance. Power Cost Adjustment Clause Filing On July 1, 2019, PSE updated its Schedule 95 rates in the Power Cost Adjustment Clause tariff to reflect the transition fee as required by Section 12 of the Microsoft Special Contract. Additionally, Schedule 95 rates also include portions of fixed power cost adjustments per the allowed decoupling rate re-allocation effective April 1, 2019, resulting from Microsoft becoming a transportation customer as well as small variable power cost adjustments. On July 8, 2020, the Washington Commission issued the final order in Dockets UE-190529 and UG-190530, which instructed PSE to remove Schedule 95 collection on decoupling allowed rates for Microsoft Special Contracts, which will be 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 2019. 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. Due to concerns about the economic impact of the COVID-19 pandemic on customers, PSE voluntarily, with Washington Commission Staff support, delayed filing an increase to its Schedule 95 rates in its annual PCA report filing in Docket UE-200398, which was approved on July 30, 2020. Subsequently, PSE filed to recover the deferred balance in Docket UE-200893, effective December 1, 2020, and the Washington Commission approved PSE’s request on November 24, 2020. During 2019, actual power costs were higher than baseline power costs, thereby creating an under-recovery of $67.2 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $31.2 million of the under-recovered amount, and customers were responsible for the remaining $36.0 million, or $37.0 million including interest. As PSE had an approved balance owing from customers including interest at the start of 2019 totaling $4.7 million, the approved cumulative deferral balance for the PCA as of December 2019 is $41.7 million. As previously stated, this filing is set to collect the customer’s share of the cumulative 2019 imbalance in PSE’s PCA mechanism. Purchased Gas Adjustment Mechanism On April 25, 2019, the Washington Commission approved PSE’s request for an out-of-cycle change to PGA rates with the rate change taking effect May 1, 2019. The out-of-cycle PGA filing was needed to begin amortizing a large PGA commodity deferral balance that had grown due to higher than projected commodity costs during the 2018/19 winter. These higher than projected commodity costs were primarily due to an October 9, 2018, rupture and subsequent explosion on Westcoast Pipeline which is one of the major pipelines feeding PSE’s distribution system. The pipeline was repaired in October 2018, however supply capacity on the pipeline was limited over the 2018/19 winter leading to higher prices. February weather was also much colder than normal which also increased the demand for natural gas. The out-of-cycle PGA rates were effective from May 1, 2019 through April 30, 2020 and on May 1, 2020 the rates were set to zero. At the end of the recovery period, an unamortized balance of $4.9 million remained which PSE requested to be amortized in its annual PGA filing for rates effective November 1, 2020. On October 24, 2019, the Washington Commission approved PSE’s request for November 2019 PGA rates, with the rate change taking effect on November 1, 2019. As part of that filing, PSE requested PGA rates increase annual revenue by $17.8 million, while the new tracker rates increased by annual revenue of $100.6 million; this was in addition to continuing the collection on the remaining balance of $54.0 million from the out-of-cycle PGA. The tracker rates include deferral balances for the three separate amounts: (i) $114.4 million of under collected commodity balances deferred in February and March; (ii) a $10.8 million balance of over-collected commodity costs for the 2018 PGA, and (iii) a $4.1 million remaining balance from the $54.7 million credit to customers, caused by the 2017 over-collection, established in the 2018 tracker. The high commodity deferral balances for winter months through March 2019 were the result of three noteworthy events last winter experienced by PSE: the Enbridge pipeline rupture, unusually low temperatures in February and March, and a compressor failure in February at the Jackson Prairie storage facility. Additionally, to reduce customer impact, as part of the approved PGA filing, PSE will be collecting $114.4 million commodity deferrals and related interest over a two-year period, instead of the historic one-year period, from November 2019 through October 2021. On July 8, 2020, the Washington Commission issued the final order in Dockets UE-190529 and UG-190530, which instructed PSE to extend the collection of amortization balances for the portion of PGA amortization balances originally filed through the annual November 1, 2019 PGA filing under the Supplemental Schedule 106B. The extension requires PSE to move amortization balances for PGA Schedule 106B as of August 31, 2020 to be collected from customers for a three-year period, instead of the originally approved two-year period. On October 29, 2020, the Washington Commission approved PSE’s request for November 2020 PGA rates in Docket UG-200832, effective November 1, 2020. As part of that filing, PSE requested PGA rates increase annual revenue by $32.6 million, while the new tracker rates increased annual revenue by $37.4 million; this was in addition to continuing the collection on the remaining balance of $69.4 million under Supplemental Schedule 106B. The following table presents the PGA mechanism balances and activity at December 31, 2020 and December 31, 2019: (Dollars in Thousands) At December 31, At December 31, PGA receivable balance and activity 2020 2019 PGA receivable beginning balance $ 132,766 $ 9,921 Actual natural gas costs 314,792 406,162 Allowed PGA recovery (363,886) (289,876) Interest 3,983 6,559 PGA receivable ending balance $ 87,655 $ 132,766 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, 2020 and December 31, 2019, PSE deferred $2.8 million and $21.7 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 Company’s currently authorized after tax rate of return, or 6.89% per the 2018 ERF. The GTZ accounting petition was consolidated with PSE’s 2019 GRC and on July 8, 2020, the Washington Commission issued its order in PSE’s 2019 GRC. The ruling authorized PSE to amortize deferred GTZ expenses as proposed in the original GRC filing. The ruling also allows continued deferral of the depreciation expense associated with GTZ investments not already approved for recovery with a book life of 10 years or less, through PSE's next GRC. Finally, the final order set the rate at which PSE could defer and recover carrying charges from PSE’s authorized rate of return to the quarterly interest rate established by the FERC. Crisis Affected Customer Assistance Program On April 6, 2020, PSE filed with the Washington Commission revisions to its currently effective Tariff WN U-60. The purpose of this filing is to incorporate into PSE’s low-income tariff a new temporary bill assistance program, Crisis Affected Customer Assistance Program (CACAP), to mitigate the economic impact of the COVID-19 pandemic on PSE’s customers. CACAP would allow PSE customers facing financial hardship due to COVID-19 to receive up to $1,000 in bill assistance. The program puts to immediate use $

Dividend Payment Restrictions

Dividend Payment Restrictions	12 Months Ended
	Dec. 31, 2020
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, 2020, approximately $1.1 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, 2020, and the EBITDA to interest expense was 5.2 to 1.0 for the twelve months ended December 31, 2020. 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 3.4 to 1.0 for the twelve months ended December 31, 2020. At December 31, 2020, 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, 2020
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 December 31, December 31, (Dollars in Thousands) (Years) 2020 2019 2020 2019 Distribution plant 20-65 $ 7,028,731 $ 6,602,934 $ 8,592,720 $ 8,185,700 Production plant 12-90 3,096,092 3,066,792 3,767,014 3,743,493 Transmission plant 43-75 1,494,781 1,463,288 1,601,731 1,571,186 General plant 5-75 697,501 698,275 726,327 731,279 Intangible plant (including capitalized software) 1 3-50 779,767 735,826 770,317 726,383 Plant acquisition adjustment N/A 242,826 242,826 282,792 282,792 Underground storage 25-60 39,498 37,511 52,927 50,963 Liquefied natural gas storage 25-60 12,628 12,628 14,498 14,498 Plant held for future use N/A 45,929 46,233 46,081 46,385 Recoverable Cushion Gas N/A 8,655 8,655 8,655 8,655 Plant not classified N/A 384,794 316,923 384,794 316,923 Finance leases, net of accumulated amortization 2 N/A 881 1,488 881 1,488 Less: accumulated provision for depreciation (3,671,094) (3,236,240) (6,087,748) (5,682,606) Subtotal $ 10,160,989 $ 9,997,139 $ 10,160,989 $ 9,997,139 Construction work in progress 712,204 591,199 712,204 591,199 Net utility plant $ 10,873,193 $ 10,588,338 $ 10,873,193 $ 10,588,338 _______________________ 1. Intangible assets include capitalized software and franchise agreements with useful lives ranging between 3-10 years and 10-50 years, respectively. 2. At December 31, 2020, and 2019, accumulated amortization of capital leases at Puget Energy and PSE was $1.6 million and $1.0 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, 2020. These amounts are also included in the Utility Plant table above. 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% $ 328,967 $ — $ (118,546) Frederickson 1 Natural Gas 49.85 62,519 — (14,533) Jackson Prairie Natural Gas 33.34 38,843 1,725 (9,620) Tacoma LNG Natural Gas various — 439,264 — 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 % $ 587,424 $ — $ (377,003) Frederickson 1 Natural Gas 49.85 68,586 — (20,601) Jackson Prairie Natural Gas 33.34 52,927 1,725 (23,705) Tacoma LNG Natural Gas various — 207,700 — In June 2019, Talen, the plant operator of Colstrip 1&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, 2020, and December 31, 2019, the unrecovered plant for Colstrip 1&2 was fully offset with PTCs. 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). On April 17, 2015, the EPA published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCR) under the Resource Conservation and Recovery Act, Subtitle D. The CCR ruling requires the Company to perform an extensive study on the effects of coal ash on the environment and public health. The rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments. The CCR rule and two legal agreements which include a consent decree with the Sierra Club and a settlement agreement with the Sierra Club and the National Wildlife Federation in 2016 made changes to the Company’s Colstrip operations, which were reviewed by the Company and the plant operator in 2015 and 2016. PSE had previously recognized a legal obligation in 2003 under the EPA rules to dispose of coal ash material at Colstrip. The actual ARO costs related to the CCR rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs. We will continue to gather additional data and coordinate with the plant operator to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, the Company will update the ARO obligation for these changes, which could be material. For the twelve months ended December 31, 2020, the Company reviewed the estimated remediation costs at Colstrip and increased the Colstrip ARO liability by $29.7 million for Colstrip Units 1 and 2 and $2.0 million for Colstrip Units 3 and 4. The environmental remediation liability for Colstrip Units 1 and 2 increased $39.0 million during the same period. The 2020 increase to these Colstrip related liabilities 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 is currently contesting the approved plan for Colstrip 1 & 2 under the defined process in the settlement with the state. The Company has recorded the incremental costs for this change under ASC 410-20 “Asset Retirement and Environmental Obligations" and ASC 410-30 “Environmental Remediation". For the twelve months ended December 31, 2019, the company increased the Colstrip ARO liability by $4.2 million for Colstrip Units 1 and 2, and increased $0.5 million for Colstrip Units 3 and 4. The 2019 change to the Colstrip ARO liability is primarily based on the plant site remedy report approved by the Montana Department of Environmental Quality. For the twelve months ended December 31, 2020 and 2019, the Company also recorded the Colstrip relief of liability of $9.6 million and $12.4 million, respectively. In addition, the Company recorded Tacoma LNG facility ARO liability of $3.3 million and $3.0 million for PSE and $7.4 million and $4.3 million for Puget LNG as of December 31, 2020 and December 31, 2019, respectively. The 2020 and 2019 increases to the Tacoma LNG facility ARO liabilities are primarily due to continued construction of the plant. Puget Energy and Puget Sound Energy December 31, (Dollars in Thousands) 2020 2019 Asset retirement obligation at beginning of the period $ 181,353 $ 182,203 Relief of liability (9,647) (12,449) Revisions in estimated cash flows 38,677 5,922 Accretion expense 5,780 5,677 Asset retirement obligation at end of period 1 $ 216,163 $ 181,353 ___________________ 1. Asset retirement obligations include $7.4 million and $4.3 million for Puget LNG held only at Puget Energy as of December 31, 2020, and 2019, 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, 2020: • 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, 2020
Long-term Debt, Unclassified [Abstract]
Long-term Debt	Long-Term Debt The following table presents outstanding long-term debt principal amounts and due dates as of 2020 and 2019: (Dollars in Thousands) December 31, Series Type Due 2020 2019 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 4.700% Senior Secured Note 2051 45,000 45,000 * Debt discount, issuance cost and other * (35,816) (37,718) Total PSE long-term debt $ 4,338,044 $ 4,336,142 Puget Energy: * Fair value adjustment of PSE long-term debt * $ (165,357) $ (173,865) * Revolving Credit Agreement 2023 14,700 24,100 * Term Loan Agreement 2 2021 — 174,000 * Term Loan Agreement 2022 210,000 210,000 6.000% Senior Secured Note 1 2021 — 500,000 5.625% Senior Secured Note 2022 450,000 450,000 3.650% Senior Secured Note 2025 400,000 400,000 4.100% Senior Secured Note 2030 650,000 — * Debt discount, issuance cost and other * (4,947) (52) Total Puget Energy long-term debt $ 5,892,440 $ 5,920,325 ___________________ * Not Applicable. 1. 6.000% Senior Secured Note in the amount of $500.0 million was classified on the Balance Sheet as short-term debt as of August 31, 2020. 2. Term Loan Agreement in the amount of $24.0 million was classified on the Balance Sheet as short-term debt as of October 1, 2020. PSE's senior secured notes will cease to be secured by the pledged first mortgage bonds on the 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, 2020, the latest maturity date of the first mortgage bonds, other than pledged first mortgage bonds, is December 22, 2025. Puget Energy Long-Term Debt In April 2019, Puget Energy entered into an additional $24.0 million of supplemental loans under the expansion feature of the term loan agreement with the existing lenders. All other terms and conditions of the agreement remain unchanged. The proceeds from the term loan and supplemental loans were used to repay borrowings under the revolving credit facility, which carries a higher interest rate. On September 26, 2019, Puget Energy entered into a separate $210.0 million, three-year term loan agreement with a small group of banks. The agreement allows Puget Energy to borrow at either the banks' prime rate or LIBOR plus a spread, which will vary as those base rates fluctuate over the loan period. The term loan agreement also includes an expansion feature, pursuant to which Puget Energy may request to increase the aggregate amount of the term loan agreement, obtain incremental term loans or any combination of increases and incremental term loans in an amount up to $100.0 million. The proceeds from the term loan were contributed as equity to PSE and used to repay outstanding short term debt under the Company's commercial paper program. On May 19, 2020, Puget Energy issued $650.0 million of senior secured notes (Notes) at an interest rate of 4.1%. The Notes pay interest semi-annually and are due to mature on June 15, 2030. On May 26, 2020, proceeds from the issuance of the Notes were used to pay $150.0 million under our term loan credit facility, pay $31.6 million of our revolving credit facility, and to redeem $450.0 million in principal amount of the 6.5% senior secured notes due December 15, 2020 and to pay related fees and expenses. On June 18, 2020, Puget Energy redeemed the $450.0 million senior secured notes due December 15, 2020 and paid related fees and expenses for a total redemption price of $463.2 million. Excluding the repayment of the $450.0 million principal amount and $0.3 million of unamortized debt discount and issuance cost, the extinguishment incurred a $13.5 million loss, which includes $0.4 million of accrued interest expense and is reported in the Puget Energy "Interest Expense" line item as of December 31, 2020. At December 31, 2020, Puget Energy maintained an $800.0 million credit facility, of which $14.7 million was drawn and outstanding under the facility. Puget Sound Energy Long-Term Debt On August 2, 2019, PSE filed a new shelf registration statement under which it may issue up to $1.0 billion aggregate principal amount of senior notes secured by first mortgage bonds. As of the date of this report, $550.0 million was available under the registration. The shelf registration will expire in August 2022. Substantially all utility properties owned by PSE are subject to the lien of the Company’s electric and natural gas mortgage indentures. To issue additional first mortgage bonds under these indentures, PSE’s earnings available for interest must exceed certain minimums as defined in the indentures. At December 31, 2020, the earnings available for interest exceeded the required amount. On August 30, 2019, PSE issued $450.0 million of senior notes at an interest rate of 3.25%. The notes pay interest semi-annually and are due to mature on September 15, 2049. Proceeds from the sale of the notes were used to repay outstanding short term debt under the Company’s commercial paper program. 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) 2021 2022 2023 2024 2025 Thereafter Total Maturities of: PSE $ 2,412 $ — $ — $ — $ 17,000 $ 4,356,860 $ 4,376,272 Puget Energy 524,000 660,000 14,700 — 400,000 650,000 2,248,700 Total long-term debt $ 526,412 $ 660,000 $ 14,700 $ — $ 417,000 $ 5,006,860 $ 6,624,972

Liquidity Facilities and Other

Liquidity Facilities and Other Financing Arrangements	12 Months Ended
	Dec. 31, 2020
Liquidity Facilities and Other Financing Arrangements [Abstract]
Liquidity Facilities and Other Financing Arrangements	Liquidity Facilities and Other Financing Arrangements As of December 31, 2020, and 2019, PSE had $373.8 million and $176.0 million in short-term debt outstanding, respectively. Outside of the consolidation of PSE’s short-term debt, Puget Energy had no short-term debt outstanding in either year as borrowings under its credit facility are classified as long-term. PSE’s weighted-average interest rate on short-term debt, including borrowing rate, commitment fees and the amortization of debt issuance costs, during 2020 and 2019 was 2.0% and 3.4%, respectively. As of December 31, 2020, PSE and Puget Energy had several committed credit facilities that are described below. Puget Sound Energy Credit Facility In October 2017, PSE entered into a new $800.0 million credit facility which consolidates the two previous facilities into a single, smaller facility. All other features including fees, interest rate options, letter of credit, same day swingline borrowings, financial covenant and accordion feature remain substantially the same. The credit facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facility also has an expansion feature which, upon the banks' approval, would increase the total size of the facility to $1.4 billion. On September 25, 2019, with no changes to the size, terms or conditions, the maturity of the unsecured revolving credit facility was extended for one year. The facility now matures in October 2023. The credit agreement is syndicated among numerous lenders and contains usual and customary affirmative and negative covenants that, among other things, places 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 financial covenant of total debt to total capitalization of 65% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of December 31, 2020, PSE was in compliance with all applicable covenant ratios. The credit agreement provides PSE with the ability to borrow at different interest rate options. The credit agreement allows PSE to borrow at the bank's prime rate or to make floating rate advances at the LIBOR 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, the spread to the LIBOR is 1.25% and the commitment fee is 0.175%. As of December 31, 2020, no amounts were drawn and outstanding under PSE's credit facility. No letters of credit were outstanding and $373.8 million was outstanding under the commercial paper program. Outside of the credit agreement, PSE had a $2.7 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada. 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 (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 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, 2020, there was no outstanding balance under the Note. Puget Energy Credit Facility In October 2017, Puget Energy entered into a new $800.0 million credit facility to replace the existing facility. The terms and conditions, including fees, interest rate options, financial covenant, and expansion feature remain substantially the same. On September 25, 2019, with no changes to the size, terms or conditions, the maturity of the unsecured revolving credit facility was extended for one year. The facility now matures in October 2023. As of December 31, 2020, there was $14.7 million drawn and outstanding under the facility. The Puget Energy revolving senior secured credit facility also has an expansion feature which, upon the banks' approval, would increase the size of the facility to $1.3 billion. The revolving senior secured credit facility provides Puget Energy the ability to borrow at different interest rate options and includes variable fee levels. Interest rates may be based on the bank's prime rate or LIBOR 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 the date of this report, the spread over LIBOR was 1.75% and the commitment fee was 0.275%.

Leases

Leases	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
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. The finance leases are for office printers. The leases have remaining lease terms of less than a year to 49 years. PSE's ROU assets and lease liabilities include options to extend leases when it is reasonably certain that PSE will exercise that option. During the fourth quarter of 2019, PSE became reasonably certain to exercise an option to extend its lease at the Port of Tacoma for an additional 25 years as a result of the approval of the Notice of Construction permit for the Tacoma LNG facility. This remeasurement resulted in an increase of the Operating lease right-of-use asset and Operating lease liabilities of $14.7 million. The components of lease cost were as follows: Puget Energy and Year Ended December 31, Year Ended December 31, (Dollars in Thousands) 2020 2019 Finance lease cost: Amortization of right-of-use asset $ 607 $ 562 Interest on lease liabilities 34 40 Total finance lease cost $ 641 $ 602 Operating lease cost 1 $ 21,983 $ 20,639 _______________ 1. Includes $1.0 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease or both of the years ended December 31, 2020 and December 31, 2019, 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) 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flow for operating leases $ 15,305 $ 14,104 Investing cash flow for operating leases 1 6,678 6,535 Operating cash flow for finance leases 34 40 Financing cash flow for finance leases 607 562 Non-cash disclosure upon commencement of new lease Right-of-use assets obtained in exchange for new operating lease liabilities $ 6,302 $ 5,976 Right-of-use assets obtained in exchange for new finance lease liabilities — 745 Non-cash disclosure upon modification of existing lease Modification of operating lease right-of-use assets $ — $ 14,712 _______________ 1 Includes $1.0 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for both of the years ended December 31, 2020 and December 31, 2019, respectively. Supplemental balance sheet information related to leases was as follows: Puget Sound Energy (Dollars in Thousands) At December 31, At December 31, Operating Leases 2020 2019 Operating lease right-of-use asset $ 172,167 $ 183,048 Operating leases liabilities current 19,204 15,862 Operating lease liabilities long-term 160,980 174,327 Total Operating lease liabilities: $ 180,184 $ 190,189 Finance Leases Common Plant $ 881 $ 1,488 Other current liabilities 475 669 Other deferred credits 320 811 Total finance lease liabilities $ 795 $ 1,480 Weighted Average Remaining Lease Term Operating leases 18.97 Years 19.24 Years Finance leases 2.00 Years 2.76 Years Weighted Average Discount Rate Operating leases 3.59 % 3.59 % Finance leases 2.98 % 2.98 % The following tables summarize the Company’s estimated future minimum lease payments as of December 31, 2020, and December 31, 2019, respectively: Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2021 $ 23,170 $ 508 2022 22,785 279 2023 22,345 98 2024 21,613 — 2025 18,249 — Thereafter 144,912 — Total lease payments $ 253,074 $ 885 Less imputed interest (72,890) (90) Total net present value $ 180,184 $ 795 Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2020 $ 22,500 $ 643 2021 22,527 508 2022 21,856 279 2023 21,415 98 2024 20,690 — Thereafter 160,410 — Total lease payments $ 269,398 $ 1,528 Less imputed interest (79,209) (48) Total net present value $ 190,189 $ 1,480 PSE adopted ASU 2016-02 in 2019 and elected the modified transition method practical expedient. Consequently, comparative period disclosures are presented in accordance with ASC 840. Operating lease expense, which includes both cancellable and non-cancellable leases, net of sublease receipts are presented in the following table. (Dollars in Thousands) Operating Lease Expense Year Ended December 31, 2018 $ 34,093 Leases Not Yet Commenced During 2020, PSE entered into two leases for two service centers located in Kent and Puyallup, Washington. The Kent service center lease is expected to commence in 2021 and the Puyallup service center lease is expected to commence in 2022. These leases are expected to result in material rights and obligations upon commencement and will be classified as finance leases.

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2020
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 PCA. 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 2020 2019 2020 2019 2020 2019 Electric portfolio derivatives * * $ 22,544 $ 19,933 $ 46,922 $ 17,504 Natural gas derivatives (MMBtus) 3 320 316 19,276 11,375 14,352 8,617 Total derivative contracts $ 41,820 $ 31,308 $ 61,274 $ 26,121 Current 33,015 23,626 31,441 13,428 Long-term 8,805 7,682 29,833 12,693 Total derivative contracts $ 41,820 $ 31,308 $ 61,274 $ 26,121 __________ 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 212.2 million One Million British Thermal Units (MMBtus) and purchased electricity of 6.6 million megawatt hours (MWhs) at December 31, 2020, and 229.3 million MMBtus and 10.4 million MWhs at December 31, 2019. 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, 2020 (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 $ 41,820 $ — $ 41,820 $ (21,696) $ — $ 20,124 Liabilities: Energy derivative contracts 61,274 — 61,274 (21,696) (9,343) 30,235 Puget Energy and December 31, 2019 (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 $ 31,308 $ — $ 31,308 $ (14,922) $ — $ 16,386 Liabilities Energy Derivative Contracts 26,121 — 26,121 (14,922) 2,000 13,199 __________ 1. All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of set-off. 2. Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments. 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 2020 2019 2018 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net $ 5,534 $ 16,970 $ 23,186 Realized Electric generation fuel 5,246 10,828 26,222 Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net (32,341) (20,544) 18,476 Realized Purchased electricity (14,958) 48,686 12,240 Total gain (loss) recognized in income on derivatives $ (36,519) $ 55,940 $ 80,124 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 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, 2020, approximately 98.6% of the Company's energy portfolio exposure, excluding NPNS transactions, is with counterparties that are rated investment grade by rating agencies and 1.4% 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, such as credit default swaps and bond spreads, in the determination of reserves. 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, 2020, 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, 2020, PSE had cash posted as collateral of $17.9 million related to contracts executed on the ICE platform. Also, as of December 31, 2020, PSE had $3.0 million in cash posted as collateral and a $1.0 million letter of credit posted as a condition of transacting on the ICE NGX Exchange. PSE did not trigger any collateral requirements with any of its counterparties during the twelve months ended December 31, 2020, nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades. 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) 2020 2019 Contingent Feature Fair Value 1 Liability Posted Contingent Fair Value 1 Liability Posted Contingent Credit rating 2 $ 26,966 $ — $ 26,966 $ 6,110 $ — $ 6,110 Requested credit for adequate assurance 6,576 — — 5,253 — — Forward value of contract 3 9,343 20,903 N/A — 14,827 N/A Total $ 42,885 $ 20,903 $ 26,966 $ 11,363 $ 14,827 $ 6,110 _______________ 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 $52.7 million and $51.5 million at December 31, 2020, and 2019, 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 the junior subordinated and 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, 2020 December 31, 2019 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Financial liabilities: Long-term debt (fixed-rate), net of discount 1 2 $ 5,667,740 $ 7,755,946 $ 5,512,225 $ 7,004,316 Long-term debt (variable-rate), net of discount 2 224,700 224,700 408,100 408,100 Total $ 5,892,440 $ 7,980,646 $ 5,920,325 $ 7,412,416 Puget Sound Energy December 31, 2020 December 31, 2019 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Financial liabilities: Long-term debt (fixed-rate), net of discount 2 2 $ 4,338,044 $ 6,086,358 $ 4,336,142 $ 5,571,818 Total $ 4,338,044 $ 6,086,358 $ 4,336,142 $ 5,571,818 _______________ 1. The carrying value includes debt issuances costs of $22.7 million and $24.1 million for December 31, 2020, and 2019, respectively, which are not included in fair value. 2. The carrying value includes debt issuances costs of $22.9 million and $24.4 million for December 31, 2020, and 2019, 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, 2020 December 31, 2019 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric Derivative Instruments $ 21,947 $ 597 $ 22,544 $ 19,282 $ 651 $ 19,933 Gas Derivative Instruments 19,139 137 19,276 9,852 1,523 11,375 Total derivative assets $ 41,086 $ 734 $ 41,820 $ 29,134 $ 2,174 $ 31,308 Liabilities: Electric Derivative Instruments $ 22,607 $ 24,315 $ 46,922 $ 13,474 $ 4,030 $ 17,504 Gas Derivative Instruments 13,080 1,272 14,352 8,376 241 8,617 Total derivative liabilities $ 35,687 $ 25,587 $ 61,274 $ 21,850 $ 4,271 $ 26,121 Puget Energy and Year Ended December 31, Level 3 Roll-Forward Net Asset(Liability) 2020 2019 2018 (Dollars in Thousands) Electric Natural Gas Total Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ (3,379) $ 1,282 $ (2,097) $ 1,362 $ 1,673 $ 3,035 $ 1,098 $ 1,923 $ 3,021 Changes during period Realized and unrealized energy derivatives: Included in earnings 1 (23,559) — (23,559) 3,558 — 3,558 34,604 — 34,604 Included in regulatory assets / liabilities — (1,049) (1,049) — 3,151 3,151 — 6,075 6,075 Settlements 2 3,220 (1,368) 1,852 (11,265) (4,708) (15,973) (33,067) (7,197) (40,264) Transferred into Level 3 — — — 4,390 (398) 3,992 (1,987) — (1,987) Transferred out Level 3 — — — (1,424) 1,564 $ 140 714 872 $ 1,586 Balance at end of period $ (23,718) $ (1,135) $ (24,853) $ (3,379) $ 1,282 $ (2,097) $ 1,362 $ 1,673 $ 3,035 __________________ 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 $(21.3) million, $(3.2) million and $1.1 million for the years ended December 31, 2020, 2019, and 2018, respectively. 2. The Company had no purchases, sales or issuances 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, 2020, 2019, and 2018. 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, 2020: Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Electricity $ 597 $ 24,315 Discounted cash flow Power Prices (per MWh) $ 22.82 $ 41.66 $ 31.54 Natural Gas $ 137 $ 1,272 Discounted cash flow Natural Gas Prices (per MMBtu) $ 1.89 $ 3.42 $ 2.47 _______________ 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, 2020, 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 $5.5 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 2019 and determined there was no indication of impairment of its power purchase contracts. During 2020, decreases in forward power prices and decreases in forecasted revenue and cost estimates indicated the carrying value of Puget Energy’s power purchase contracts may not have been recoverable. Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. In 2020, the following impairments were recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability as follows: Puget Energy (Dollars in Thousands) Valuation Date Contract Name Carrying Value Fair Value Write Down March 31, 2020 Rocky Reach $ 147,168 $ 94,603 $ 52,565 Total 2020 Impairments $ 52,565 The valuations were measured using a discounted cash flow, income-based valuation methodology. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates classified as Level 3 within the fair value hierarchy. A less significant input is the discount rate reflective of PSE's cost of capital used in the valuation. Below are significant unobservable inputs used in estimating the impaired long-term power purchase contracts' fair value in 2020, there were no such impairments in 2019: Puget Energy Valuation Date Contract Unobservable Input Low High Average March 31, 2020 Rocky Reach Power prices (per MWh) $ 10.23 $ 38.84 $ 24.43 Power contract costs per quarter (in thousands) 6,308 7,085 6,468

Employee Investment Plans

Employee Investment Plans	12 Months Ended
	Dec. 31, 2020
Employee Investment Plans [Abstract]
Employee Investment Plans	Employee Investment Plans The 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 $22.1 million, $21.7 million and $20.7 million for the years 2020, 2019, and 2018, 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, 2020
Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Retirement Benefits	Retirement BenefitsPSE has a defined benefit pension plan (Qualified Pension Benefits) covering a substantial majority of PSE employees. 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. Starting with January 1, 2014, all UA represented employees will receive annual pay contributions of 4.0% of eligible pay each year in the cash balance formula plan of the defined benefit pension. Starting January 1, 2014, for non-represented employees, and December 12, 2014 for employees represented by the IBEW, participants will receive annual employer contributions of 4.0% of eligible pay each year in the cash balance formula of the defined benefit pension or 401k plan account. Those employees receiving contributions in the cash balance formula plan also receive interest credits, which are at least 1.0% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, they will have annuity and lump sum options for distribution. PSE also has a non-qualified Supplemental Executive Retirement Plan (SERP) for certain key senior management employees that closed to new participants in 2019. PSE has an officer restoration benefit for new officers who join PSE or are promoted beginning in 2019, such that company contributions under PSE’s applicable tax-qualified plan, which otherwise would have been earned if not for IRS limitations, are credited 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 Welfare Benefits Committee approved the termination of this benefit effective December 31, 2019, and the creation of a Retiree Health Reimbursement Account (HRA) Plan effective January 1, 2020. No eligible individual may become a participant or covered dependent in the Plan on or after January 1, 2020, and no benefits will be payable under insurance contracts or the Plan on or after January 1, 2020. Effective January 1, 2020, assets in the 401(h) account are allocated to the Retiree HRA instead of the Plan to cover the Company's portion of premiums for health benefits for retiree and their beneficiaries. 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 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, 2020, and 2019: Puget Energy and Qualified SERP Other (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Change in benefit obligation: Benefit obligation at beginning of period $ 774,305 $ 677,643 $ 63,000 $ 55,708 $ 11,627 $ 10,636 Amendments — — — — 44 9,049 Service cost 24,337 22,656 756 1,023 190 61 Interest cost 25,180 28,913 1,464 2,314 368 410 Curtailment Loss / (Gain) — — — — — (7,486) Actuarial loss (gain) 69,413 84,272 3,663 6,756 604 (287) Benefits paid (42,775) (36,740) (22,141) (2,801) (906) (982) Medicare part D subsidy received — — — — 187 226 Administrative expense (1,077) (2,439) — — — — Benefit obligation at end of period $ 849,383 $ 774,305 $ 46,742 $ 63,000 $ 12,114 $ 11,627 Puget Energy and Qualified SERP Other (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Change in plan assets: Fair value of plan assets at beginning of period $ 753,042 $ 640,242 $ — $ — $ 6,289 $ 5,960 Actual return on plan assets 107,409 133,939 — — 278 1,006 Employer contribution 18,000 18,000 22,141 2,801 257 305 Benefits paid (42,775) (36,740) (22,141) (2,801) (906) (982) Administrative expense (1,021) (2,399) — — — — Fair value of plan assets at end of period $ 834,655 $ 753,042 $ — $ — $ 5,918 $ 6,289 Funded status at end of period $ (14,728) $ (21,263) $ (46,742) $ (63,000) $ (6,196) $ (5,338) Puget Energy and Qualified SERP Other (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Amounts recognized in Consolidated Balance Sheet consist of: Noncurrent assets $ — $ — $ — $ — $ — $ — Current liabilities — — (6,763) (22,604) (293) (308) Noncurrent liabilities (14,728) (21,263) (39,979) (40,396) (5,903) (5,030) Net assets (liabilities) $ (14,728) $ (21,263) $ (46,742) $ (63,000) $ (6,196) $ (5,338) Puget Energy and Qualified SERP Other (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets: Projected benefit obligation $ 849,383 $ 774,305 $ 46,742 $ 63,000 $ 12,114 $ 11,627 Accumulated benefit obligation 837,455 762,838 44,033 59,988 12,070 11,604 Fair value of plan assets 834,655 753,042 — — 5,918 6,289 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, 2020, and 2019: Puget Energy Qualified SERP Other (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 98,010 $ 94,319 $ 11,738 $ 15,003 $ 600 $ (197) Prior service cost (credit) (1,904) (3,884) 927 1,276 44 — Total $ 96,106 $ 90,435 $ 12,665 $ 16,279 $ 644 $ (197) Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 210,317 $ 217,502 $ 12,504 $ 16,473 $ 489 $ (364) Prior service cost (credit) (1,513) (3,086) 927 1,276 44 — Total $ 208,804 $ 214,416 $ 13,431 $ 17,749 $ 533 $ (364) The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, 2020, 2019, and 2018. Puget Energy Qualified SERP Other (Dollars in Thousands) 2020 2019 2018 2020 2019 2018 2020 2019 2018 Components of net periodic benefit cost: Service cost $ 24,337 $ 22,656 $ 22,757 $ 756 $ 1,023 $ 847 $ 190 $ 61 $ 69 Interest cost 25,180 28,913 27,303 1,464 2,314 2,120 368 410 444 Expected return on plan assets (49,902) (50,249) (50,202) — — — (389) (393) (472) Amortization of prior service cost (credit) (1,980) (1,980) (1,980) 349 331 1,580 — — — Amortization of net loss (gain) 8,160 1,151 2,187 2,122 1,365 42 (82) (374) (335) Net periodic benefit cost $ 5,795 $ 491 $ 65 $ 4,691 $ 5,033 $ 4,589 $ 87 $ (296) $ (294) Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2020 2019 2018 2020 2019 2018 2020 2019 2018 Components of net periodic benefit cost: Service cost $ 24,337 $ 22,656 $ 22,757 $ 756 $ 1,023 $ 847 $ 190 $ 61 $ 69 Interest cost 25,180 28,913 27,303 1,464 2,314 2,120 368 410 444 Expected return on plan assets (49,910) (50,267) (50,240) — — — (389) (393) (472) Amortization of prior service cost (credit) (1,573) (1,573) (1,573) 349 333 44 — — — Amortization of net loss (gain) 19,043 12,877 14,917 2,385 1,733 2,069 (137) (562) (556) Net periodic benefit cost $ 17,077 $ 12,606 $ 13,164 $ 4,954 $ 5,403 $ 5,080 $ 32 $ (484) $ (515) The following tables summarize Puget Energy's and PSE's benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, 2020, and 2019: Puget Energy Qualified SERP Other (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 11,851 $ 541 $ 3,663 $ 6,756 $ 715 $ (900) Amortization of net (loss) gain (8,160) (1,151) (2,122) (1,365) 82 374 Settlements, mergers, sales, and closures — — (4,806) — — 2,892 Prior service cost (credit) — — — — 44 — Amortization of prior service (cost) credit 1,980 1,980 (349) (331) — — Total change in other comprehensive income for year $ 5,671 $ 1,370 $ (3,614) $ 5,060 $ 841 $ 2,366 Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 11,858 $ 559 $ 3,663 $ 6,756 $ 715 $ (900) Amortization of net (loss) gain (19,043) (12,877) (2,385) (1,733) 137 562 Settlements, mergers, sales, and closures — — (5,248) — — 3,832 Prior service cost (credit) — — — — 44 — Amortization of prior service (cost) credit 1,573 1,573 (349) (333) — — Total change in other comprehensive income for year $ (5,612) $ (10,745) $ (4,319) $ 4,690 $ 896 $ 3,494 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, 2021, are expected to be at least $18.0 million, $6.8 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 2020 2019 2018 2020 2019 2018 2020 2019 2018 Discount rate 2.70 % 3.35 % 4.40 % 2.70 % 3.35 % 4.40 % 2.70 % 3.35 % 4.40 % 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 Medical trend rate 1 — — — — — — N/A N/A 7.60 Benefit Cost Assumptions Discount rate 3.35 4.40 4.40 3.35 4.40 4.40 3.35 4.40 4.40 Return on plan assets 7.15 7.50 7.50 — — — 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 Medical trend rate 1 — — — — — — N/A N/A 7.60 ________________________ 1. As of December 31,2019, PSE terminated the previous group retiree medical plan and created an HRA. As a result, medical inflation is no longer applicable in accounting for the related benefit obligation. 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 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 loss of $69.4 million in 2020. This is primarily due to the decrease 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) 2021 2022 2023 2024 2025 2025-2029 Qualified Pension total benefits $ 46,500 $ 47,300 $ 48,900 $ 49,900 $ 51,200 $ 261,000 SERP Pension total benefits 6,763 1,901 3,773 6,552 8,041 16,217 Other Benefits total with Medicare Part D subsidy 816 968 936 904 876 3,931 Other Benefits total without Medicare Part D subsidy 997 968 936 904 876 3,931 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 15 25 30 Real estate — — 10 Absolute return 5 10 15 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, 2020, and 2019: Recurring Fair Value Measures Recurring Fair Value Measures December 31, 2020 December 31, 2019 (Dollars in Thousands) Level 1 Level 2 Other Total Level 1 Level 2 Other Total Assets: Mutual Funds $ — $ — $ — $ — $ 91,658 $ — $ — $ 91,658 Common Stock – Domestic 228,247 53 — 228,300 204,682 — — 204,682 – Foreign 19,216 — — 19,216 19,464 — — 19,464 Government Securities 73,006 9,148 — 82,154 34,916 — — 34,916 Corporate Securities – Domestic — 6,082 — 6,082 — — — — – Foreign — 3,699 — 3,699 — — — — Cash and cash equivalents 4,612 3,223 — 7,835 — 150 — 150 Investments measured at NAV - Collective Investment Funds — — 342,014 342,014 — — 278,379 278,379 - Partnership — — 107,137 107,137 — — 69,505 69,505 - Mutual Funds — — 82,103 82,103 — — 53,784 53,784 - Other — — 1,096 1,096 — — — — Net (payable) receivable — — (44,981) (44,981) — — 505 505 Total assets $ 325,081 $ 22,205 $ 487,369 $ 834,655 $ 350,720 $ 150 $ 402,173 $ 753,043 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, 2020 December 31, 2019 (Dollars in Thousands) Level 1 Level 2 Other Total Level 1 Level 2 Other Total Assets: Mutual fund $ 5,916 $ — $ — $ 5,916 $ 6,201 $ — $ — $ 6,201 Investments measured at NAV — — — — — — 88 88 Net (payable) receivable — — 2 2 — — — — Total assets $ 5,916 $ — $ 2 $ 5,918 $ 6,201 $ — $ 88 $ 6,289 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, 2020
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) 2020 2019 2018 Charged to operating expenses: Current: Federal $ 7,962 $ 9,424 $ 10,382 State 7 164 263 Deferred: Federal (6,414) 7,357 19,451 State 109 128 (4) Total income tax expense $ 1,664 $ 17,073 $ 30,092 Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2020 2019 2018 Charged to operating expenses: Current: Federal $ 10,607 $ 18,093 $ 19,283 State 383 570 438 Deferred: Federal 15,252 20,485 30,979 State — — — Total income tax expense $ 26,242 $ 39,148 $ 50,700 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) 2020 2019 2018 Income taxes at the statutory rate $ 38,720 $ 47,834 $ 55,800 Increase (decrease): Utility plant differences 1 $ (22,991) $ (23,025) $ (25,871) AFUDC, net (6,095) (4,462) (4,173) Executive compensation 2,440 2,596 4,439 Treasury grant amortization (8,935) (7,870) (4,861) Excess deferred tax amortization (3,038) — — Other–net 1,563 2,000 4,758 Total income tax expense $ 1,664 $ 17,073 $ 30,092 Effective tax rate 0.9 % 7.5 % 11.3 % Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2020 2019 2018 Income taxes at the statutory rate $ 63,110 $ 69,735 $ 77,251 Increase (decrease): Utility plant differences 1 $ (22,991) $ (23,025) $ (25,871) AFUDC, net (6,095) (4,462) (4,173) Executive compensation 2,440 2,596 4,439 Treasury grant amortization (8,935) (7,870) (4,861) Excess deferred tax amortization (3,038) — — Other–net 1,751 2,174 3,915 Total income tax expense $ 26,242 $ 39,148 $ 50,700 Effective tax rate 8.7 % 11.8 % 13.8 % _______________ 1. Utility plant differences include the reversal of excess deferred taxes using the average rate assumption method in the amount of $27.6 million and $27.6 million in 2020, and 2019, respectively. The Company’s net deferred tax liability at December 31, 2020, and 2019, is composed of amounts related to the following types of temporary differences: Puget Energy At December 31, (Dollars in Thousands) 2020 2019 Utility plant and equipment $ 1,923,933 $ 1,943,730 Other deferred tax liabilities 137,325 133,440 Subtotal deferred tax liabilities 2,061,258 2,077,170 Net operating loss carryforward (261,260) (238,869) Net regulatory liability for income taxes (953,274) (946,179) Production tax credit carryforward (35,995) (67,402) Subtotal deferred tax assets (1,250,529) (1,252,450) Total net deferred tax liabilities $ 810,729 $ 824,720 Puget Sound Energy At December 31, (Dollars in Thousands) 2020 2019 Utility plant and equipment $ 1,923,933 $ 1,943,730 Other, net deferred tax liabilities 53,431 47,774 Subtotal deferred tax liabilities 1,977,364 1,991,504 Net regulatory liability for income taxes (953,987) (946,936) Production tax credit carryforward (35,995) (67,405) Subtotal deferred tax assets (989,982) (1,014,341) Total net deferred tax liabilities $ 987,382 $ 977,163 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’s PTC carryforwards expire from 2033 through 2036. 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 PTC or 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, 2020, and 2019, 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 evaluated the treatment of protected excess deferred income taxes (EDIT) required under Washington Commission Order 08 for compliance with the IRS normalization rules. The Order requires ratemaking and accounting treatment for the EDIT that is different than the treatment afforded prior income tax rate changes. The Company has requested a private letter ruling from the IRS in which it asks the IRS to confirm that the treatment required in the Order complies with the normalization rules. The Company anticipates that the ruling will have no impact on its current or deferred income taxes. If the Company, receives an adverse ruling, it could result in an increase to the revenue requirement of $25.6 million. The Company expects a ruling during 2021. The Company has open tax years from 2017 through 2020. The Company classifies interest as interest expense and penalties as other expense in the financial statements.

Litigation

Litigation	12 Months Ended
	Dec. 31, 2020
Colstrip Unit 4 [Member]
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. In March 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. In July 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court in September 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and Talen Energy Corporation (Talen), agreed to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana no later than July 1, 2022. Depreciation rates were updated in the GRC effective December 19, 2017, where PSE's depreciation increased for Colstrip Units 1 and 2 to recover plant costs to the expected shutdown date. Additionally, PSE has accelerated the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027. The GRC also 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. 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 Transition 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 PTC's 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 December 10, 2019, PSE announced its intention to sell its interest in Colstrip Unit 4 to NorthWestern Energy for $1. Under this agreement, PSE would have retained its obligation to fund 25% of the environmental remediation and decommissioning costs associated with Unit 4 during PSE's operation. The proposed agreement was subject to approval by the Washington Commission and the Montana Public Service Commission. Additionally, PSE had agreed to enter into a power purchase agreement with NorthWestern Energy for 90 MW through 2025 to facilitate the transition, and sell a portion of its dedicated Colstrip transmission system, conditioned upon regulatory approval. On August 14, 2020, an amendment to the agreement was executed selling a portion of PSE’s interest in Colstrip Unit 4 to Talen, in addition to NorthWestern Energy. However, after evaluating the likelihood of the regulatory approval process in both Washington and Montana, on October 29, 2020, PSE, NorthWestern Energy, and Talen mutually agreed to terminate the proposed sales agreement and the proposed power purchase agreement and relieve all claims against one another arising out of or relating to the sale agreement. The termination of the proposed sale and proposed PPA resulted in the withdrawal of PSE's filing with the Washington Commission. Colstrip Unit 4 is classified as Electric Utility Plant on the balance sheet, see Note 6, "Utility Plant," to the consolidated financial statements in Item 8 of this report. Regional Haze Rule In January 2017, the EPA published revisions to the Regional Haze Rule. Among other things, these revisions delayed new Regional Haze review from 2018 to 2021, however the end date will remain 2028. In January 2018, the EPA announced that it was reconsidering certain aspects of these revisions and PSE is unable to predict the outcome. Challenges to the 2017 Regional Haze Revision Rule are pending in abeyance in the U.S. Court of Appeals for the D.C. Circuit, pending resolution of the EPA’s reconsideration of the rule. Clean Air Act 111(d)/EPA Affordable Clean Energy Rule In June 2014, the EPA issued a proposed Clean Power Plan (CPP) rule under Section 111(d) of the Clean Air Act designed to regulate GHG emissions from existing power plants. The proposed rule includes state-specific goals and guidelines for states to develop plans for meeting these goals. The EPA published a final rule in October 2015. In March 2017, then EPA Administrator, Scott Pruitt, signed a notice of withdrawal of the proposed CPP federal plan and model trading rules and, in October 2017, the EPA proposed to repeal the CPP rule. In August 2018, the EPA proposed the Affordable Clean Energy (ACE) rule, pursuant to Section 111(d) of the Clean Air Act, as a replacement to the CPP rule. The ACE rule, along with the repeal of the CPP rule, were finalized in June 2019, and establish emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired plants. On January 19, 2021 the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the ACE rule and remanded the record back to the Agency for further consideration consistent with its opinion, finding that misinterpreted the Clean Air Act. PSE is evaluating this vacatur to determine impact on operations. Washington Clean Air Rule The CAR was adopted in September 2016, in Washington State and attempts to reduce greenhouse gas emissions from “covered entities” located within Washington State. Included under the new rule are large manufacturers, petroleum producers and natural gas utilities, including PSE. The CAR sets a cap on emissions associated with covered entities, which decreases over time approximately 5.0% every three years. Entities must reduce their carbon emissions, or purchase emission reduction units (ERUs), as defined under the rule, from others. In September 2016, PSE, along with Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed a lawsuit in the U.S. District Court for the Eastern District of Washington challenging the CAR. In September 2016, the four companies filed a similar challenge to the CAR in Thurston County Superior Court. In March 2018, the Thurston County Superior Court invalidated the CAR. The Washington State Department of Ecology appealed the Superior Court decision in May 2018. As a result of the appeal, direct review to the Washington State Supreme Court was granted and oral argument was held on March 16, 2019. In January 2020, the Washington Supreme Court affirmed that CAR is not valid for “indirect emitters” meaning it does not apply to the sale of natural gas for use by customers. The court ruled, however, that the rule can be severed and is valid for direct emitters including electric utilities with permitted air emission sources, but remanded the case back to the Thurston County to determine which parts of the rule survive. The Department of Ecology and the four parties asked Thurston County to stay this case until the 2020 Washington State legislative session concluded and now the Department of Ecology plans to ask the court to extend the stay until the COVID-19 pandemic is over. Meanwhile, the four companies moved to voluntarily dismiss the federal court litigation without prejudice in March 2020.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies For the year ended December 31, 2020, approximately 15.3% of the Company’s energy output was obtained at an average cost of approximately $0.031 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) 2020 2019 2018 PUD contract costs $ 116,874 $ 87,135 $ 80,165 As of December 31, 2020, the Company purchased portions of the power output of the PUDs' projects as set forth in the following table: Company's Current Share of (Dollars in Thousands) Contract Percent of Megawatt Capacity Estimated 2021 Costs 2021 Debt Service Costs Interest included in 2021 Debt Service Costs Debt Outstanding Chelan County PUD: Rock Island Project 2031 25.0 % 156 $ 34,895 $ 11,314 $ 5,365 $ 91,674 Rocky Reach Project 2031 25.0 325 30,400 4,518 1,960 30,476 Douglas County PUD: Wells Project 1 2028 24.2 203 37,584 — — — Grant County PUD: Priest Rapids Development 2052 0.6 6 1,440 773 389 9,761 Wanapum Development 2052 0.6 7 1,440 773 389 9,761 Total 697 $ 105,759 $ 17,378 $ 8,103 $ 141,672 _______________ 1. In March 2017, PSE entered a new PPA with Douglas County PUD for Wells Project output that begins upon expiration of the existing contract on August 31, 2018, and continues through September 30, 2028. 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) 2021 2022 2023 2024 2025 Thereafter Total Columbia River projects $ 117,664 $ 101,421 $ 100,222 $ 99,473 $ 99,393 $ 499,808 $ 1,017,981 Electric portfolio contracts 299,705 332,444 349,119 356,976 277,250 1,343,699 2,959,193 Electric wholesale market transactions 117,444 21,660 11,540 11,692 11,616 11,616 185,568 Total $ 534,813 $ 455,525 $ 460,881 $ 468,141 $ 388,259 $ 1,855,123 $ 4,162,742 Total purchased power contracts provided the Company with approximately 13.2 million, 12.5 million and 14.1 million MWhs of firm energy at a cost of approximately $491.7 million, $550.6 million and $508.2 million for the years 2020, 2019, and 2018, respectively. Clearwater PPA In February 2021, PSE entered into a PPA with Clearwater Energy Resources LLC to purchase up to 350 MW of wind energy and renewable attributes over a 20 year term beginning in November 2022. The expected payment obligations for power purchases from this contract are summarized in the following table: (Dollars in Thousands) 2022 2023 2024 2025 2026 Thereafter Total Expected payment obligation $ 2,430 34,541 34,541 34,541 34,541 550,228 $ 690,822 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 to 24 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. The Company incurred demand charges for 2020 for firm transportation, storage and peaking services for its natural gas customers of $135.8 million. The Company incurred demand charges in 2020 for firm transportation and storage services for the natural gas supply for its combustion turbines in the amount of $51.2 million. 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 2021 2022 2023 2024 2025 Thereafter Total Natural gas wholesale market transactions $ 327,775 $ 210,736 $ 155,778 $ 116,016 $ 59,483 $ — $ 869,788 Firm transportation service 174,912 172,431 163,662 129,503 113,051 804,103 1,557,662 Firm storage service 8,899 8,899 2,270 67 67 56 20,258 Total $ 511,586 $ 392,066 $ 321,710 $ 245,586 $ 172,601 $ 804,159 $ 2,447,708 Service Contracts The following table summarizes the Company’s estimated obligations for service contracts through the terms of its existing contracts. Service Contract Obligations 2021 2022 2023 2024 2025 Thereafter Total Energy production service contracts $ 29,710 $ 30,423 $ 31,155 $ 31,921 $ 32,177 $ 105,579 $ 260,965 Automated meter reading system 45,489 46,436 47,498 47,505 48,229 49,077 284,234 Total $ 75,199 $ 76,859 $ 78,653 $ 79,426 $ 80,406 $ 154,656 $ 545,199 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, 2020
Related Party Transactions [Abstract]
Related Party Transactions	Related Party TransactionsThe Company identified no material related party transactions during the year ended December 31, 2020 and December 31, 2019.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2020
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, 2020
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, 2020, 2019, and 2018, 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, 2017 $ (24,282) $ (24,282) Other comprehensive income (loss) before reclassifications (48,870) (48,870) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 1,180 1,180 Reclassification of stranded taxes to retained earnings due to tax reform (5,230) (5,230) Net current-period other comprehensive income (loss) (52,920) (52,920) Balance at December 31, 2018 $ (77,202) $ (77,202) Other comprehensive income (loss) before reclassifications (7,337) (7,337) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 390 390 Net current-period other comprehensive income (loss) (6,947) (6,947) 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) 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, 2017 $ (121,867) $ (5,039) $ (126,906) Other comprehensive income (loss) before reclassifications (48,802) — (48,802) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 11,772 385 12,157 Reclassification of stranded taxes to retained earnings due to tax reform (26,233) (1,100) (27,333) Net current-period other comprehensive income (loss) (63,263) (715) (63,978) Balance at December 31, 2018 $ (185,130) $ (5,754) $ (190,884) Other comprehensive income (loss) before reclassifications (8,096) — (8,096) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 10,118 385 10,503 Net current-period other comprehensive income (loss) 2,022 385 2,407 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) Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2020, 2019, and 2018, 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 2020 2019 2018 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,631 $ 1,648 $ 1,937 Amortization of net gain (loss) (a) (10,200) (2,142) (3,431) Total before tax (8,569) (494) (1,494) Tax (expense) or benefit 1,799 104 314 Net of Tax (6,770) (390) (1,180) Total reclassification for the period Net of Tax $ (6,770) $ (390) $ (1,180) __________ (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 2020 2019 2018 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,224 $ 1,240 $ 1,529 Amortization of net gain (loss) (a) (21,291) (14,048) (16,430) Total before tax (20,067) (12,808) (14,901) Tax (expense) or benefit 4,214 2,690 3,129 Net of tax (15,853) (10,118) (11,772) Net unrealized gain (loss) on treasury interest rate swaps: Interest rate contracts Interest expense (487) (487) (487) Tax (expense) or benefit 102 102 102 Net of Tax (385) (385) (385) Total reclassification for the period Net of Tax $ (16,238) $ (10,503) $ (12,157) ____________ (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.

SUPPLEMENTAL QUARTERLY FINANCIA

SUPPLEMENTAL QUARTERLY FINANCIAL DATA	12 Months Ended
	Dec. 31, 2020
Quarterly Financial Information Disclosure [Abstract]
Supplemental Quarterly Financial Data	SUPPLEMENTAL QUARTERLY FINANCIAL DATA The following unaudited amounts, in the opinion of the Company, include all adjustments (consisting of normal recurring adjustments) necessary for a fair statement of the results of operations for the interim periods. Quarterly amounts vary during the year due to the seasonal nature of the utility business. Puget Energy 2020 Quarter (Unaudited; Dollars in Thousands) First Second Third Fourth Operating revenue $ 1,046,130 $ 651,679 $ 620,426 $ 1,008,215 Operating income 172,384 70,350 83,308 181,782 Net income (loss) 94,936 (23,233) 9,996 101,018 2019 Quarter (Unaudited; Dollars in Thousands) First Second Third Fourth Operating revenue $ 1,114,839 $ 670,930 $ 627,007 $ 988,354 Operating income 213,460 39,115 26,126 240,307 Net income (loss) 132,154 (32,952) (39,443) 150,949 Puget Sound Energy 2020 Quarter (Unaudited; Dollars in Thousands) First Second Third Fourth Operating revenue $ 1,046,130 $ 651,679 $ 620,426 $ 1,008,215 Operating income 172,656 71,192 84,192 181,152 Net income (loss) 111,321 15,037 33,062 114,860 2019 Quarter (Unaudited; Dollars in Thousands) First Second Third Fourth Operating revenue $ 1,114,839 $ 670,930 $ 627,007 $ 988,354 Operating income 214,159 39,780 26,721 241,955 Net income (loss) 147,302 (8,325) (15,257) 169,204

SCHEDULE I CONDENSED FINANCIAL

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY	12 Months Ended
	Dec. 31, 2020
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, 2020 2019 2018 Non-utility expense and other $ (1,579) $ (1,495) $ (1,345) Other income (deductions): Equity in earnings of subsidiary 277,654 294,724 320,122 Interest income 4,760 6,643 4,273 Interest expense (123,592) (111,716) (108,816) Income tax benefit (expense) 25,474 22,552 21,388 Net income (loss) $ 182,717 $ 210,708 $ 235,622 Comprehensive income (loss) $ 180,429 $ 203,761 $ 182,702 See accompanying notes to the condensed financial statements. Puget Energy Condensed Balance Sheets (Dollars in Thousands) December 31, 2020 2019 Assets: Investment in subsidiaries $ 4,279,501 $ 4,153,618 Other property and investments: Goodwill 1,656,513 1,656,513 Current assets: Cash 790 947 Receivables from affiliates 1 211,411 180,527 Total current assets 212,201 181,474 Long-term assets: Deferred income taxes 258,033 235,428 Other 1,520 2,056 Total long-term assets 259,553 237,484 Total assets $ 6,407,768 $ 6,229,089 Capitalization and liabilities: Common equity $ 4,139,882 $ 4,000,299 Long-term debt 1,714,744 1,752,644 Total capitalization 5,854,626 5,752,943 Current liabilities: Accounts payable and accrued taxes 3,683 208 Current maturities of long-term debt 524,000 450,000 Interest 25,459 25,938 Total current liabilities 553,142 476,146 Commitments and contingencies (Note 16) Total capitalization and liabilities $ 6,407,768 $ 6,229,089 _______________ 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, 2020 2019 2018 Operating activities: Net cash provided by (used in) operating activities $ 38,280 $ 68,724 $ 79,176 Investing activities: Investment in subsidiaries — (210,000) — (Increase) decrease in loan to subsidiary (31,043) (41,708) (59,864) Net cash provided by (used in) investing activities (31,043) (251,708) (59,864) Financing activities: Dividends paid (45,421) (64,220) (77,204) Investment from Parent 4,575 — — Issuance of long-term debts 644,690 246,200 209,300 Redemption of long-term debts (609,400) — (150,000) Issue costs and others (1,838) (116) (92) Net cash provided by (used in) by financing activities (7,394) 181,864 (17,996) Increase (decrease) in cash (157) (1,120) 1,316 Cash at beginning of year 947 2,067 751 Cash at end of year $ 790 $ 947 $ 2,067 See accompanying notes to the condensed financial statements.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2020
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, currently under construction. 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 3.5%, 3.4%, and 3.3% in 2020, 2019, and 2018, respectively; depreciable natural gas utility plant was 2.9%, 2.8%, and 2.8% in 2020, 2019, and 2018, respectively; and depreciable common utility plant was 7.3%, 7.3% and 7.1% in 2020, 2019, and 2018, respectively. The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability.
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 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 these items at the lower of cost or net realizable value method.
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 $240.8 million, $236.5 million and $239.3 million for 2020, 2019, and 2018, 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 3.0% cap of total revenue for decoupled rate schedules. Any excess revenue above 3.0% will be included in the following year's decoupled rate. The Company will be able to recognize revenue below the 3.0% cap of total revenue for decoupled rate schedules. For revenue deferrals exceeding the annual 3.0% 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. On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 general rate case (GRC) to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. The rate test which limits the amount of revenues PSE can collect in its annual filings increased from 3.0% to 5.0% for natural gas customers but will remain at 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 On January 1, 2020, the Company adopted Accounting Standards Update (ASU) 2016-13 Financial Instruments – Credit Losses (ASC 326) which replaces the incurred loss methodology with an expected loss methodology that is referred to as the current expected credit loss (CECL) methodology. The measurement of expected credit losses under the CECL methodology is applicable to financial assets measured at amortized cost, including trade receivables, loan receivables, and held-to-maturity debt securities. It also applies to off-balance sheet credit exposures not accounted for as insurance (loan commitments, standby letters of credit, financial guarantees, and other similar instruments) and net investments in leases recognized by a lessor in accordance with Topic 842 on leases. The only financial assets within the scope of ASU 2016-13 for the Company are trade receivables. The Company adopted ASU 2016-13 using the modified retrospective method. Results for reporting periods beginning after January 1, 2020 are presented under ASC 326 while prior period amounts continue to be reported in accordance with previously applicable GAAP. The Company did not record an adjustment to retained earnings as of January 1, 2020, for the cumulative effect of adopting ASU 2016-13, as the impact was immaterial. Management 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 for the year ended December 31, 2020: Puget Energy and (Dollars in Thousands) December 31, Allowance for credit losses: Beginning balance $ 8,294 Provision for credit loss expense 23,292 Receivables charged-off (11,506) Total ending allowance balance $ 20,080
Self Insurance	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. Under the December 5, 2017, Washington Commission order regarding PSE’s GRC, the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018. Additionally, costs may only be deferred if the outage meets the Institute of Electrical and Electronics Engineers (IEEE) outage criteria for system average interruption duration index and qualifying costs exceed $0.5 million per qualified storm.
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 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, 2020 and 2019, $39.8 million and $67.5 million of PTCs were estimated to be monetized through tax filings, respectively.
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 other deferred credits 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.
Consolidation, Variable Interest Entity, Policy	Variable Interest Entities On April 12, 2017, PSE entered into a 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 RECs 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 $4.2 million was recognized in purchased electricity on the Company's consolidated statements of income and included in accounts payable on the Company's consolidated balance sheet for the year ended December 31, 2020.

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue [Table Text Block]	The following table presents disaggregated revenue from contracts with customers, and other revenue by major source: Puget Energy and (Dollars in Thousands) Year Ended December 31, Revenue from Contracts with Customers: 2020 2019 2018 Electric retail $ 2,106,122 $ 2,132,522 $ 2,138,008 Natural gas retail 938,061 870,457 849,898 Other 178,208 308,111 234,187 Total revenue from contracts with customers 3,222,391 3,311,090 3,222,093 Alternative revenue programs 35,006 (18,634) (22,852) Other non-customer revenue 69,053 108,674 147,255 Total operating revenue $ 3,326,450 $ 3,401,130 $ 3,346,496

Regulation and Rates (Tables)

Regulation and Rates (Tables)	12 Months Ended
	Dec. 31, 2020
Regulatory Assets [Line Items]
Schedule of Net Regulatory Assets and Liabilities	The net regulatory assets and liabilities at December 31, 2020, and 2019, included the following: Puget Sound Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2020 2019 Storm damage costs electric 5 years $ 108,491 $ 121,894 Environmental remediation (a) 102,647 68,486 Decoupling deferrals and interest (b) Less than 2 years 88,504 43,509 PGA receivable 2 years 87,655 132,766 PCA mechanism N/A 82,801 41,745 Chelan PUD contract initiation 10.8 years 76,787 83,875 Deferred Washington Commission AFUDC 30 years 59,763 57,553 Lower Snake River 16.4 years 58,442 62,899 Baker Dam licensing operating and maintenance costs (c) 54,354 56,427 Get to zero depreciation expense deferral N/A 53,236 22,148 Unamortized loss on reacquired debt 1 to 47 years 37,991 40,177 Property tax tracker Less than 2 years 24,860 22,442 Advanced metering infrastructure (a) 22,652 14,845 Generation plant major maintenance, excluding Colstrip 3 to 10 years 10,494 12,744 Mint Farm ownership and operating costs 4.3 years 8,318 10,318 Energy conservation costs (a) 8,009 25,272 Snoqualmie licensing operating and maintenance costs (c) 7,435 7,442 Water heater rental property loss N/A 6,973 — Colstrip major maintenance (d) 4,335 2,929 Washington Commission electric vehicle N/A 3,641 1,430 Colstrip common property 3.4 years 2,472 3,188 White River relicensing and other costs 0.0 years — 6,399 Various other regulatory assets (a) 8,247 9,044 Total PSE regulatory assets $ 918,107 $ 847,532 Deferred income taxes (f) N/A (953,987) (946,936) Cost of removal (e) (508,707) (469,922) Repurposed production tax credits N/A (79,581) (24,823) Production tax credits (f) (47,094) (85,323) Treasury grants 3 years (43,164) (101,981) Decoupling liability Less than 2 years (16,448) (8,500) Green direct N/A (14,313) (2,421) Gain on Sale Shuffleton N/A (11,131) (12,483) Microsoft special contract regulatory liability N/A — (12,661) Various other regulatory liabilities (a) (10,796) (11,500) Total PSE regulatory liabilities (1,685,221) (1,676,550) PSE net regulatory assets (liabilities) $ (767,114) $ (829,018) __________________ (a) Amortization periods vary depending on timing of underlying transactions. (b) Decoupling deferrals and interest includes a 24 month GAAP reserve of $(8.0) million. (c) 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. (d) Amortization to be determined in a future rate filing. (e) The balance is dependent upon the cost of removal of underlying assets and the life of utility plant. (f) Amortize as PTCs are utilized by PSE on its tax return. (g) For additional information, see Note 14,"Income Taxes" to the consolidated financial statements included in Item 8 of this report. Puget Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2020 2019 Total PSE regulatory assets (a) $ 918,107 $ 847,532 Puget Energy acquisition adjustments: Regulatory assets related to power contracts 5 to 32 years 11,728 14,146 Total Puget Energy regulatory assets 929,835 861,678 Total PSE regulatory liabilities (a) (1,685,221) (1,676,550) Puget Energy acquisition adjustments: Deferred income taxes 713 757 Regulatory liabilities related to power contracts 5 to 32 years (95,774) (156,597) Various other regulatory liabilities Varies (1,264) (1,265) Total Puget Energy regulatory liabilities (1,781,546) (1,833,655) Puget Energy net regulatory asset (liabilities) $ (851,711) $ (971,977) ____________________ (a) Puget Energy’s regulatory assets and liabilities include purchase accounting adjustments under ASC 805.
Subsidiaries [Member] | Electricity [Member] | PCA Mechanism [Member]
Regulatory Assets [Line Items]
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
Subsidiaries [Member] | Natural Gas [Member] | Purchased Gas Adjustment [Member]
Regulatory Assets [Line Items]
Schedule of PGA Receivable Payable	The following table presents the PGA mechanism balances and activity at December 31, 2020 and December 31, 2019: (Dollars in Thousands) At December 31, At December 31, PGA receivable balance and activity 2020 2019 PGA receivable beginning balance $ 132,766 $ 9,921 Actual natural gas costs 314,792 406,162 Allowed PGA recovery (363,886) (289,876) Interest 3,983 6,559 PGA receivable ending balance $ 87,655 $ 132,766

Utility Plant (Tables)

Utility Plant (Tables)	12 Months Ended
	Dec. 31, 2020
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 December 31, December 31, (Dollars in Thousands) (Years) 2020 2019 2020 2019 Distribution plant 20-65 $ 7,028,731 $ 6,602,934 $ 8,592,720 $ 8,185,700 Production plant 12-90 3,096,092 3,066,792 3,767,014 3,743,493 Transmission plant 43-75 1,494,781 1,463,288 1,601,731 1,571,186 General plant 5-75 697,501 698,275 726,327 731,279 Intangible plant (including capitalized software) 1 3-50 779,767 735,826 770,317 726,383 Plant acquisition adjustment N/A 242,826 242,826 282,792 282,792 Underground storage 25-60 39,498 37,511 52,927 50,963 Liquefied natural gas storage 25-60 12,628 12,628 14,498 14,498 Plant held for future use N/A 45,929 46,233 46,081 46,385 Recoverable Cushion Gas N/A 8,655 8,655 8,655 8,655 Plant not classified N/A 384,794 316,923 384,794 316,923 Finance leases, net of accumulated amortization 2 N/A 881 1,488 881 1,488 Less: accumulated provision for depreciation (3,671,094) (3,236,240) (6,087,748) (5,682,606) Subtotal $ 10,160,989 $ 9,997,139 $ 10,160,989 $ 9,997,139 Construction work in progress 712,204 591,199 712,204 591,199 Net utility plant $ 10,873,193 $ 10,588,338 $ 10,873,193 $ 10,588,338 _______________________ 1. Intangible assets include capitalized software and franchise agreements with useful lives ranging between 3-10 years and 10-50 years, respectively. 2. At December 31, 2020, and 2019, accumulated amortization of capital leases at Puget Energy and PSE was $1.6 million and $1.0 million, respectively.
Schedule of Jointly Owned Utility Plants	These amounts are also included in the Utility Plant table above. 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% $ 328,967 $ — $ (118,546) Frederickson 1 Natural Gas 49.85 62,519 — (14,533) Jackson Prairie Natural Gas 33.34 38,843 1,725 (9,620) Tacoma LNG Natural Gas various — 439,264 — 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 % $ 587,424 $ — $ (377,003) Frederickson 1 Natural Gas 49.85 68,586 — (20,601) Jackson Prairie Natural Gas 33.34 52,927 1,725 (23,705) Tacoma LNG Natural Gas various — 207,700 —
Schedule of Asset Retirement Obligations	Puget Energy and Puget Sound Energy December 31, (Dollars in Thousands) 2020 2019 Asset retirement obligation at beginning of the period $ 181,353 $ 182,203 Relief of liability (9,647) (12,449) Revisions in estimated cash flows 38,677 5,922 Accretion expense 5,780 5,677 Asset retirement obligation at end of period 1 $ 216,163 $ 181,353 ___________________ 1. Asset retirement obligations include $7.4 million and $4.3 million for Puget LNG held only at Puget Energy as of December 31, 2020, and 2019, respectively.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2020
Long-term Debt, Unclassified [Abstract]
Schedule of Long-Term Debt Instruments	The following table presents outstanding long-term debt principal amounts and due dates as of 2020 and 2019: (Dollars in Thousands) December 31, Series Type Due 2020 2019 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 4.700% Senior Secured Note 2051 45,000 45,000 * Debt discount, issuance cost and other * (35,816) (37,718) Total PSE long-term debt $ 4,338,044 $ 4,336,142 Puget Energy: * Fair value adjustment of PSE long-term debt * $ (165,357) $ (173,865) * Revolving Credit Agreement 2023 14,700 24,100 * Term Loan Agreement 2 2021 — 174,000 * Term Loan Agreement 2022 210,000 210,000 6.000% Senior Secured Note 1 2021 — 500,000 5.625% Senior Secured Note 2022 450,000 450,000 3.650% Senior Secured Note 2025 400,000 400,000 4.100% Senior Secured Note 2030 650,000 — * Debt discount, issuance cost and other * (4,947) (52) Total Puget Energy long-term debt $ 5,892,440 $ 5,920,325 ___________________ * Not Applicable. 1. 6.000% Senior Secured Note in the amount of $500.0 million was classified on the Balance Sheet as short-term debt as of August 31, 2020. 2. Term Loan Agreement in the amount of $24.0 million was classified on the Balance Sheet as short-term debt as of October 1, 2020.
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) 2021 2022 2023 2024 2025 Thereafter Total Maturities of: PSE $ 2,412 $ — $ — $ — $ 17,000 $ 4,356,860 $ 4,376,272 Puget Energy 524,000 660,000 14,700 — 400,000 650,000 2,248,700 Total long-term debt $ 526,412 $ 660,000 $ 14,700 $ — $ 417,000 $ 5,006,860 $ 6,624,972

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
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) 2020 2019 Finance lease cost: Amortization of right-of-use asset $ 607 $ 562 Interest on lease liabilities 34 40 Total finance lease cost $ 641 $ 602 Operating lease cost 1 $ 21,983 $ 20,639 _______________ 1. Includes $1.0 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease or both of the years ended December 31, 2020 and December 31, 2019, 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) 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flow for operating leases $ 15,305 $ 14,104 Investing cash flow for operating leases 1 6,678 6,535 Operating cash flow for finance leases 34 40 Financing cash flow for finance leases 607 562 Non-cash disclosure upon commencement of new lease Right-of-use assets obtained in exchange for new operating lease liabilities $ 6,302 $ 5,976 Right-of-use assets obtained in exchange for new finance lease liabilities — 745 Non-cash disclosure upon modification of existing lease Modification of operating lease right-of-use assets $ — $ 14,712 _______________ 1 Includes $1.0 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for both of the years ended December 31, 2020 and December 31, 2019, respectively.
Balance Sheet of Leases	Supplemental balance sheet information related to leases was as follows: Puget Sound Energy (Dollars in Thousands) At December 31, At December 31, Operating Leases 2020 2019 Operating lease right-of-use asset $ 172,167 $ 183,048 Operating leases liabilities current 19,204 15,862 Operating lease liabilities long-term 160,980 174,327 Total Operating lease liabilities: $ 180,184 $ 190,189 Finance Leases Common Plant $ 881 $ 1,488 Other current liabilities 475 669 Other deferred credits 320 811 Total finance lease liabilities $ 795 $ 1,480 Weighted Average Remaining Lease Term Operating leases 18.97 Years 19.24 Years Finance leases 2.00 Years 2.76 Years Weighted Average Discount Rate Operating leases 3.59 % 3.59 % Finance leases 2.98 % 2.98 %
Finance Lease, Liability, Maturity	The following tables summarize the Company’s estimated future minimum lease payments as of December 31, 2020, and December 31, 2019, respectively: Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2021 $ 23,170 $ 508 2022 22,785 279 2023 22,345 98 2024 21,613 — 2025 18,249 — Thereafter 144,912 — Total lease payments $ 253,074 $ 885 Less imputed interest (72,890) (90) Total net present value $ 180,184 $ 795 Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2020 $ 22,500 $ 643 2021 22,527 508 2022 21,856 279 2023 21,415 98 2024 20,690 — Thereafter 160,410 — Total lease payments $ 269,398 $ 1,528 Less imputed interest (79,209) (48) Total net present value $ 190,189 $ 1,480
Lessee, Operating Lease, Liability, Maturity	The following tables summarize the Company’s estimated future minimum lease payments as of December 31, 2020, and December 31, 2019, respectively: Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2021 $ 23,170 $ 508 2022 22,785 279 2023 22,345 98 2024 21,613 — 2025 18,249 — Thereafter 144,912 — Total lease payments $ 253,074 $ 885 Less imputed interest (72,890) (90) Total net present value $ 180,184 $ 795 Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2020 $ 22,500 $ 643 2021 22,527 508 2022 21,856 279 2023 21,415 98 2024 20,690 — Thereafter 160,410 — Total lease payments $ 269,398 $ 1,528 Less imputed interest (79,209) (48) Total net present value $ 190,189 $ 1,480
Schedule of Operating Lease Expense		PSE adopted ASU 2016-02 in 2019 and elected the modified transition method practical expedient. Consequently, comparative period disclosures are presented in accordance with ASC 840. Operating lease expense, which includes both cancellable and non-cancellable leases, net of sublease receipts are presented in the following table. (Dollars in Thousands) Operating Lease Expense Year Ended December 31, 2018 $ 34,093
Subsidiaries [Member]
Lessee, Lease, Description [Line Items]
Assets and Liabilities, Lessee	Supplemental balance sheet information related to leases was as follows: Puget Sound Energy (Dollars in Thousands) At December 31, At December 31, Operating Leases 2020 2019 Operating lease right-of-use asset $ 172,167 $ 183,048 Operating leases liabilities current 19,204 15,862 Operating lease liabilities long-term 160,980 174,327 Total Operating lease liabilities: $ 180,184 $ 190,189 Finance Leases Common Plant $ 881 $ 1,488 Other current liabilities 475 669 Other deferred credits 320 811 Total finance lease liabilities $ 795 $ 1,480 Weighted Average Remaining Lease Term Operating leases 18.97 Years 19.24 Years Finance leases 2.00 Years 2.76 Years Weighted Average Discount Rate Operating leases 3.59 % 3.59 % Finance leases 2.98 % 2.98 %

Accounting for Derivative Ins_2

Accounting for Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2020
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 2020 2019 2020 2019 2020 2019 Electric portfolio derivatives * * $ 22,544 $ 19,933 $ 46,922 $ 17,504 Natural gas derivatives (MMBtus) 3 320 316 19,276 11,375 14,352 8,617 Total derivative contracts $ 41,820 $ 31,308 $ 61,274 $ 26,121 Current 33,015 23,626 31,441 13,428 Long-term 8,805 7,682 29,833 12,693 Total derivative contracts $ 41,820 $ 31,308 $ 61,274 $ 26,121 __________ 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 212.2 million One Million British Thermal Units (MMBtus) and purchased electricity of 6.6 million megawatt hours (MWhs) at December 31, 2020, and 229.3 million MMBtus and 10.4 million MWhs at December 31, 2019.
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, 2020 (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 $ 41,820 $ — $ 41,820 $ (21,696) $ — $ 20,124 Liabilities: Energy derivative contracts 61,274 — 61,274 (21,696) (9,343) 30,235 Puget Energy and December 31, 2019 (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 $ 31,308 $ — $ 31,308 $ (14,922) $ — $ 16,386 Liabilities Energy Derivative Contracts 26,121 — 26,121 (14,922) 2,000 13,199 __________ 1. All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of set-off. 2. Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments.
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 2020 2019 2018 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net $ 5,534 $ 16,970 $ 23,186 Realized Electric generation fuel 5,246 10,828 26,222 Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net (32,341) (20,544) 18,476 Realized Purchased electricity (14,958) 48,686 12,240 Total gain (loss) recognized in income on derivatives $ (36,519) $ 55,940 $ 80,124
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) 2020 2019 Contingent Feature Fair Value 1 Liability Posted Contingent Fair Value 1 Liability Posted Contingent Credit rating 2 $ 26,966 $ — $ 26,966 $ 6,110 $ — $ 6,110 Requested credit for adequate assurance 6,576 — — 5,253 — — Forward value of contract 3 9,343 20,903 N/A — 14,827 N/A Total $ 42,885 $ 20,903 $ 26,966 $ 11,363 $ 14,827 $ 6,110 _______________ 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, 2020
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, 2020 December 31, 2019 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Financial liabilities: Long-term debt (fixed-rate), net of discount 1 2 $ 5,667,740 $ 7,755,946 $ 5,512,225 $ 7,004,316 Long-term debt (variable-rate), net of discount 2 224,700 224,700 408,100 408,100 Total $ 5,892,440 $ 7,980,646 $ 5,920,325 $ 7,412,416 Puget Sound Energy December 31, 2020 December 31, 2019 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Financial liabilities: Long-term debt (fixed-rate), net of discount 2 2 $ 4,338,044 $ 6,086,358 $ 4,336,142 $ 5,571,818 Total $ 4,338,044 $ 6,086,358 $ 4,336,142 $ 5,571,818 _______________ 1. The carrying value includes debt issuances costs of $22.7 million and $24.1 million for December 31, 2020, and 2019, respectively, which are not included in fair value. 2. The carrying value includes debt issuances costs of $22.9 million and $24.4 million for December 31, 2020, and 2019, 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) 2020 2019 2018 (Dollars in Thousands) Electric Natural Gas Total Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ (3,379) $ 1,282 $ (2,097) $ 1,362 $ 1,673 $ 3,035 $ 1,098 $ 1,923 $ 3,021 Changes during period Realized and unrealized energy derivatives: Included in earnings 1 (23,559) — (23,559) 3,558 — 3,558 34,604 — 34,604 Included in regulatory assets / liabilities — (1,049) (1,049) — 3,151 3,151 — 6,075 6,075 Settlements 2 3,220 (1,368) 1,852 (11,265) (4,708) (15,973) (33,067) (7,197) (40,264) Transferred into Level 3 — — — 4,390 (398) 3,992 (1,987) — (1,987) Transferred out Level 3 — — — (1,424) 1,564 $ 140 714 872 $ 1,586 Balance at end of period $ (23,718) $ (1,135) $ (24,853) $ (3,379) $ 1,282 $ (2,097) $ 1,362 $ 1,673 $ 3,035 __________________ 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 $(21.3) million, $(3.2) million and $1.1 million for the years ended December 31, 2020, 2019, and 2018, respectively. 2. The Company had no purchases, sales or issuances 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, 2020: Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Electricity $ 597 $ 24,315 Discounted cash flow Power Prices (per MWh) $ 22.82 $ 41.66 $ 31.54 Natural Gas $ 137 $ 1,272 Discounted cash flow Natural Gas Prices (per MMBtu) $ 1.89 $ 3.42 $ 2.47 _______________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. Below are significant unobservable inputs used in estimating the impaired long-term power purchase contracts' fair value in 2020, there were no such impairments in 2019: Puget Energy Valuation Date Contract Unobservable Input Low High Average March 31, 2020 Rocky Reach Power prices (per MWh) $ 10.23 $ 38.84 $ 24.43 Power contract costs per quarter (in thousands) 6,308 7,085 6,468
Schedule of Impaired Intangible Assets [Table Text Block]	Puget Energy (Dollars in Thousands) Valuation Date Contract Name Carrying Value Fair Value Write Down March 31, 2020 Rocky Reach $ 147,168 $ 94,603 $ 52,565 Total 2020 Impairments $ 52,565
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, 2020 December 31, 2019 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric Derivative Instruments $ 21,947 $ 597 $ 22,544 $ 19,282 $ 651 $ 19,933 Gas Derivative Instruments 19,139 137 19,276 9,852 1,523 11,375 Total derivative assets $ 41,086 $ 734 $ 41,820 $ 29,134 $ 2,174 $ 31,308 Liabilities: Electric Derivative Instruments $ 22,607 $ 24,315 $ 46,922 $ 13,474 $ 4,030 $ 17,504 Gas Derivative Instruments 13,080 1,272 14,352 8,376 241 8,617 Total derivative liabilities $ 35,687 $ 25,587 $ 61,274 $ 21,850 $ 4,271 $ 26,121

Retirement Benefits (Tables)

Retirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020, and 2019: Puget Energy and Qualified SERP Other (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Change in benefit obligation: Benefit obligation at beginning of period $ 774,305 $ 677,643 $ 63,000 $ 55,708 $ 11,627 $ 10,636 Amendments — — — — 44 9,049 Service cost 24,337 22,656 756 1,023 190 61 Interest cost 25,180 28,913 1,464 2,314 368 410 Curtailment Loss / (Gain) — — — — — (7,486) Actuarial loss (gain) 69,413 84,272 3,663 6,756 604 (287) Benefits paid (42,775) (36,740) (22,141) (2,801) (906) (982) Medicare part D subsidy received — — — — 187 226 Administrative expense (1,077) (2,439) — — — — Benefit obligation at end of period $ 849,383 $ 774,305 $ 46,742 $ 63,000 $ 12,114 $ 11,627
Schedule of Changes in Fair Value of Plan Assets	Puget Energy and Qualified SERP Other (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Change in plan assets: Fair value of plan assets at beginning of period $ 753,042 $ 640,242 $ — $ — $ 6,289 $ 5,960 Actual return on plan assets 107,409 133,939 — — 278 1,006 Employer contribution 18,000 18,000 22,141 2,801 257 305 Benefits paid (42,775) (36,740) (22,141) (2,801) (906) (982) Administrative expense (1,021) (2,399) — — — — Fair value of plan assets at end of period $ 834,655 $ 753,042 $ — $ — $ 5,918 $ 6,289 Funded status at end of period $ (14,728) $ (21,263) $ (46,742) $ (63,000) $ (6,196) $ (5,338)
Schedule of Amounts Recognized in Balance Sheet and Accumulated Other Comprehensive Income	Puget Energy and Qualified SERP Other (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Amounts recognized in Consolidated Balance Sheet consist of: Noncurrent assets $ — $ — $ — $ — $ — $ — Current liabilities — — (6,763) (22,604) (293) (308) Noncurrent liabilities (14,728) (21,263) (39,979) (40,396) (5,903) (5,030) Net assets (liabilities) $ (14,728) $ (21,263) $ (46,742) $ (63,000) $ (6,196) $ (5,338)
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) 2020 2019 2020 2019 2020 2019 Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets: Projected benefit obligation $ 849,383 $ 774,305 $ 46,742 $ 63,000 $ 12,114 $ 11,627 Accumulated benefit obligation 837,455 762,838 44,033 59,988 12,070 11,604 Fair value of plan assets 834,655 753,042 — — 5,918 6,289
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, 2020, 2019, and 2018. Puget Energy Qualified SERP Other (Dollars in Thousands) 2020 2019 2018 2020 2019 2018 2020 2019 2018 Components of net periodic benefit cost: Service cost $ 24,337 $ 22,656 $ 22,757 $ 756 $ 1,023 $ 847 $ 190 $ 61 $ 69 Interest cost 25,180 28,913 27,303 1,464 2,314 2,120 368 410 444 Expected return on plan assets (49,902) (50,249) (50,202) — — — (389) (393) (472) Amortization of prior service cost (credit) (1,980) (1,980) (1,980) 349 331 1,580 — — — Amortization of net loss (gain) 8,160 1,151 2,187 2,122 1,365 42 (82) (374) (335) Net periodic benefit cost $ 5,795 $ 491 $ 65 $ 4,691 $ 5,033 $ 4,589 $ 87 $ (296) $ (294)
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, 2020, and 2019: Puget Energy Qualified SERP Other (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 11,851 $ 541 $ 3,663 $ 6,756 $ 715 $ (900) Amortization of net (loss) gain (8,160) (1,151) (2,122) (1,365) 82 374 Settlements, mergers, sales, and closures — — (4,806) — — 2,892 Prior service cost (credit) — — — — 44 — Amortization of prior service (cost) credit 1,980 1,980 (349) (331) — — Total change in other comprehensive income for year $ 5,671 $ 1,370 $ (3,614) $ 5,060 $ 841 $ 2,366
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 2020 2019 2018 2020 2019 2018 2020 2019 2018 Discount rate 2.70 % 3.35 % 4.40 % 2.70 % 3.35 % 4.40 % 2.70 % 3.35 % 4.40 % 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 Medical trend rate 1 — — — — — — N/A N/A 7.60 Benefit Cost Assumptions Discount rate 3.35 4.40 4.40 3.35 4.40 4.40 3.35 4.40 4.40 Return on plan assets 7.15 7.50 7.50 — — — 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 Medical trend rate 1 — — — — — — N/A N/A 7.60
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) 2021 2022 2023 2024 2025 2025-2029 Qualified Pension total benefits $ 46,500 $ 47,300 $ 48,900 $ 49,900 $ 51,200 $ 261,000 SERP Pension total benefits 6,763 1,901 3,773 6,552 8,041 16,217 Other Benefits total with Medicare Part D subsidy 816 968 936 904 876 3,931 Other Benefits total without Medicare Part D subsidy 997 968 936 904 876 3,931
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 15 25 30 Real estate — — 10 Absolute return 5 10 15 Cash — — 5 The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, 2020, and 2019: Recurring Fair Value Measures Recurring Fair Value Measures December 31, 2020 December 31, 2019 (Dollars in Thousands) Level 1 Level 2 Other Total Level 1 Level 2 Other Total Assets: Mutual Funds $ — $ — $ — $ — $ 91,658 $ — $ — $ 91,658 Common Stock – Domestic 228,247 53 — 228,300 204,682 — — 204,682 – Foreign 19,216 — — 19,216 19,464 — — 19,464 Government Securities 73,006 9,148 — 82,154 34,916 — — 34,916 Corporate Securities – Domestic — 6,082 — 6,082 — — — — – Foreign — 3,699 — 3,699 — — — — Cash and cash equivalents 4,612 3,223 — 7,835 — 150 — 150 Investments measured at NAV - Collective Investment Funds — — 342,014 342,014 — — 278,379 278,379 - Partnership — — 107,137 107,137 — — 69,505 69,505 - Mutual Funds — — 82,103 82,103 — — 53,784 53,784 - Other — — 1,096 1,096 — — — — Net (payable) receivable — — (44,981) (44,981) — — 505 505 Total assets $ 325,081 $ 22,205 $ 487,369 $ 834,655 $ 350,720 $ 150 $ 402,173 $ 753,043
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, 2020 December 31, 2019 (Dollars in Thousands) Level 1 Level 2 Other Total Level 1 Level 2 Other Total Assets: Mutual fund $ 5,916 $ — $ — $ 5,916 $ 6,201 $ — $ — $ 6,201 Investments measured at NAV — — — — — — 88 88 Net (payable) receivable — — 2 2 — — — — Total assets $ 5,916 $ — $ 2 $ 5,918 $ 6,201 $ — $ 88 $ 6,289 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.
Parent Company [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Schedule of Amounts Recognized in Balance Sheet and 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, 2020, and 2019: Puget Energy Qualified SERP Other (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 98,010 $ 94,319 $ 11,738 $ 15,003 $ 600 $ (197) Prior service cost (credit) (1,904) (3,884) 927 1,276 44 — Total $ 96,106 $ 90,435 $ 12,665 $ 16,279 $ 644 $ (197)
Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Schedule of Amounts Recognized in Balance Sheet and Accumulated Other Comprehensive Income	Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 210,317 $ 217,502 $ 12,504 $ 16,473 $ 489 $ (364) Prior service cost (credit) (1,513) (3,086) 927 1,276 44 — Total $ 208,804 $ 214,416 $ 13,431 $ 17,749 $ 533 $ (364)
Schedule of Net Benefit Costs	Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2020 2019 2018 2020 2019 2018 2020 2019 2018 Components of net periodic benefit cost: Service cost $ 24,337 $ 22,656 $ 22,757 $ 756 $ 1,023 $ 847 $ 190 $ 61 $ 69 Interest cost 25,180 28,913 27,303 1,464 2,314 2,120 368 410 444 Expected return on plan assets (49,910) (50,267) (50,240) — — — (389) (393) (472) Amortization of prior service cost (credit) (1,573) (1,573) (1,573) 349 333 44 — — — Amortization of net loss (gain) 19,043 12,877 14,917 2,385 1,733 2,069 (137) (562) (556) Net periodic benefit cost $ 17,077 $ 12,606 $ 13,164 $ 4,954 $ 5,403 $ 5,080 $ 32 $ (484) $ (515)
Schedule of Amounts Recognized in Other Comprehensive Income (Loss)	Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 11,858 $ 559 $ 3,663 $ 6,756 $ 715 $ (900) Amortization of net (loss) gain (19,043) (12,877) (2,385) (1,733) 137 562 Settlements, mergers, sales, and closures — — (5,248) — — 3,832 Prior service cost (credit) — — — — 44 — Amortization of prior service (cost) credit 1,573 1,573 (349) (333) — — Total change in other comprehensive income for year $ (5,612) $ (10,745) $ (4,319) $ 4,690 $ 896 $ 3,494

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
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) 2020 2019 2018 Charged to operating expenses: Current: Federal $ 7,962 $ 9,424 $ 10,382 State 7 164 263 Deferred: Federal (6,414) 7,357 19,451 State 109 128 (4) Total income tax expense $ 1,664 $ 17,073 $ 30,092
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) 2020 2019 2018 Income taxes at the statutory rate $ 38,720 $ 47,834 $ 55,800 Increase (decrease): Utility plant differences 1 $ (22,991) $ (23,025) $ (25,871) AFUDC, net (6,095) (4,462) (4,173) Executive compensation 2,440 2,596 4,439 Treasury grant amortization (8,935) (7,870) (4,861) Excess deferred tax amortization (3,038) — — Other–net 1,563 2,000 4,758 Total income tax expense $ 1,664 $ 17,073 $ 30,092 Effective tax rate 0.9 % 7.5 % 11.3 % Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2020 2019 2018 Income taxes at the statutory rate $ 63,110 $ 69,735 $ 77,251 Increase (decrease): Utility plant differences 1 $ (22,991) $ (23,025) $ (25,871) AFUDC, net (6,095) (4,462) (4,173) Executive compensation 2,440 2,596 4,439 Treasury grant amortization (8,935) (7,870) (4,861) Excess deferred tax amortization (3,038) — — Other–net 1,751 2,174 3,915 Total income tax expense $ 26,242 $ 39,148 $ 50,700 Effective tax rate 8.7 % 11.8 % 13.8 % _______________ 1. Utility plant differences include the reversal of excess deferred taxes using the average rate assumption method in the amount of $27.6 million and $27.6 million in 2020, and 2019, respectively.
Schedule of Deferred Tax Assets and Liabilities	The Company’s net deferred tax liability at December 31, 2020, and 2019, is composed of amounts related to the following types of temporary differences: Puget Energy At December 31, (Dollars in Thousands) 2020 2019 Utility plant and equipment $ 1,923,933 $ 1,943,730 Other deferred tax liabilities 137,325 133,440 Subtotal deferred tax liabilities 2,061,258 2,077,170 Net operating loss carryforward (261,260) (238,869) Net regulatory liability for income taxes (953,274) (946,179) Production tax credit carryforward (35,995) (67,402) Subtotal deferred tax assets (1,250,529) (1,252,450) Total net deferred tax liabilities $ 810,729 $ 824,720 Puget Sound Energy At December 31, (Dollars in Thousands) 2020 2019 Utility plant and equipment $ 1,923,933 $ 1,943,730 Other, net deferred tax liabilities 53,431 47,774 Subtotal deferred tax liabilities 1,977,364 1,991,504 Net regulatory liability for income taxes (953,987) (946,936) Production tax credit carryforward (35,995) (67,405) Subtotal deferred tax assets (989,982) (1,014,341) Total net deferred tax liabilities $ 987,382 $ 977,163
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) 2020 2019 2018 Charged to operating expenses: Current: Federal $ 10,607 $ 18,093 $ 19,283 State 383 570 438 Deferred: Federal 15,252 20,485 30,979 State — — — Total income tax expense $ 26,242 $ 39,148 $ 50,700

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2020
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) 2020 2019 2018 PUD contract costs $ 116,874 $ 87,135 $ 80,165 As of December 31, 2020, the Company purchased portions of the power output of the PUDs' projects as set forth in the following table: Company's Current Share of (Dollars in Thousands) Contract Percent of Megawatt Capacity Estimated 2021 Costs 2021 Debt Service Costs Interest included in 2021 Debt Service Costs Debt Outstanding Chelan County PUD: Rock Island Project 2031 25.0 % 156 $ 34,895 $ 11,314 $ 5,365 $ 91,674 Rocky Reach Project 2031 25.0 325 30,400 4,518 1,960 30,476 Douglas County PUD: Wells Project 1 2028 24.2 203 37,584 — — — Grant County PUD: Priest Rapids Development 2052 0.6 6 1,440 773 389 9,761 Wanapum Development 2052 0.6 7 1,440 773 389 9,761 Total 697 $ 105,759 $ 17,378 $ 8,103 $ 141,672 _______________ 1. In March 2017, PSE entered a new PPA with Douglas County PUD for Wells Project output that begins upon expiration of the existing contract on August 31, 2018, and continues through September 30, 2028.
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 2021 2022 2023 2024 2025 Thereafter Total Energy production service contracts $ 29,710 $ 30,423 $ 31,155 $ 31,921 $ 32,177 $ 105,579 $ 260,965 Automated meter reading system 45,489 46,436 47,498 47,505 48,229 49,077 284,234 Total $ 75,199 $ 76,859 $ 78,653 $ 79,426 $ 80,406 $ 154,656 $ 545,199
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) 2021 2022 2023 2024 2025 Thereafter Total Columbia River projects $ 117,664 $ 101,421 $ 100,222 $ 99,473 $ 99,393 $ 499,808 $ 1,017,981 Electric portfolio contracts 299,705 332,444 349,119 356,976 277,250 1,343,699 2,959,193 Electric wholesale market transactions 117,444 21,660 11,540 11,692 11,616 11,616 185,568 Total $ 534,813 $ 455,525 $ 460,881 $ 468,141 $ 388,259 $ 1,855,123 $ 4,162,742
Electricity, US Regulated [Member]
Long-term Purchase Commitment [Line Items]
Schedule of Long-term Purchase Commitments	In February 2021, PSE entered into a PPA with Clearwater Energy Resources LLC to purchase up to 350 MW of wind energy and renewable attributes over a 20 year term beginning in November 2022. The expected payment obligations for power purchases from this contract are summarized in the following table: (Dollars in Thousands) 2022 2023 2024 2025 2026 Thereafter Total Expected payment obligation $ 2,430 34,541 34,541 34,541 34,541 550,228 $ 690,822
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 2021 2022 2023 2024 2025 Thereafter Total Natural gas wholesale market transactions $ 327,775 $ 210,736 $ 155,778 $ 116,016 $ 59,483 $ — $ 869,788 Firm transportation service 174,912 172,431 163,662 129,503 113,051 804,103 1,557,662 Firm storage service 8,899 8,899 2,270 67 67 56 20,258 Total $ 511,586 $ 392,066 $ 321,710 $ 245,586 $ 172,601 $ 804,159 $ 2,447,708

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020, 2019, and 2018, 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, 2017 $ (24,282) $ (24,282) Other comprehensive income (loss) before reclassifications (48,870) (48,870) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 1,180 1,180 Reclassification of stranded taxes to retained earnings due to tax reform (5,230) (5,230) Net current-period other comprehensive income (loss) (52,920) (52,920) Balance at December 31, 2018 $ (77,202) $ (77,202) Other comprehensive income (loss) before reclassifications (7,337) (7,337) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 390 390 Net current-period other comprehensive income (loss) (6,947) (6,947) 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)
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2020, 2019, and 2018, 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 2020 2019 2018 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,631 $ 1,648 $ 1,937 Amortization of net gain (loss) (a) (10,200) (2,142) (3,431) Total before tax (8,569) (494) (1,494) Tax (expense) or benefit 1,799 104 314 Net of Tax (6,770) (390) (1,180) Total reclassification for the period Net of Tax $ (6,770) $ (390) $ (1,180) __________ (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, 2017 $ (121,867) $ (5,039) $ (126,906) Other comprehensive income (loss) before reclassifications (48,802) — (48,802) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 11,772 385 12,157 Reclassification of stranded taxes to retained earnings due to tax reform (26,233) (1,100) (27,333) Net current-period other comprehensive income (loss) (63,263) (715) (63,978) Balance at December 31, 2018 $ (185,130) $ (5,754) $ (190,884) Other comprehensive income (loss) before reclassifications (8,096) — (8,096) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 10,118 385 10,503 Net current-period other comprehensive income (loss) 2,022 385 2,407 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)
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 2020 2019 2018 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,224 $ 1,240 $ 1,529 Amortization of net gain (loss) (a) (21,291) (14,048) (16,430) Total before tax (20,067) (12,808) (14,901) Tax (expense) or benefit 4,214 2,690 3,129 Net of tax (15,853) (10,118) (11,772) Net unrealized gain (loss) on treasury interest rate swaps: Interest rate contracts Interest expense (487) (487) (487) Tax (expense) or benefit 102 102 102 Net of Tax (385) (385) (385) Total reclassification for the period Net of Tax $ (16,238) $ (10,503) $ (12,157) ____________ (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.

SUPPLEMENTAL QUARTERLY FINANC_2

SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Tables)	12 Months Ended
	Dec. 31, 2020
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information	Puget Energy 2020 Quarter (Unaudited; Dollars in Thousands) First Second Third Fourth Operating revenue $ 1,046,130 $ 651,679 $ 620,426 $ 1,008,215 Operating income 172,384 70,350 83,308 181,782 Net income (loss) 94,936 (23,233) 9,996 101,018 2019 Quarter (Unaudited; Dollars in Thousands) First Second Third Fourth Operating revenue $ 1,114,839 $ 670,930 $ 627,007 $ 988,354 Operating income 213,460 39,115 26,126 240,307 Net income (loss) 132,154 (32,952) (39,443) 150,949 Puget Sound Energy 2020 Quarter (Unaudited; Dollars in Thousands) First Second Third Fourth Operating revenue $ 1,046,130 $ 651,679 $ 620,426 $ 1,008,215 Operating income 172,656 71,192 84,192 181,152 Net income (loss) 111,321 15,037 33,062 114,860 2019 Quarter (Unaudited; Dollars in Thousands) First Second Third Fourth Operating revenue $ 1,114,839 $ 670,930 $ 627,007 $ 988,354 Operating income 214,159 39,780 26,721 241,955 Net income (loss) 147,302 (8,325) (15,257) 169,204

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details) $ in Thousands	Dec. 19, 2017	Dec. 18, 2017	Dec. 31, 2020USD ($)mi²	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Jan. 01, 2018USD ($)	Jan. 01, 2017USD ($)
Accounting Policies
Excise taxes collected			$ 240,800	$ 236,500	$ 239,300
Allowance for doubtful accounts			20,080	8,294
Monetized production tax credits			$ 39,800	$ 67,500
PTC, Operation Period			10 years
Electric Transmission
Accounting Policies
Annual depreciation provision			3.50%	3.40%	3.30%
Gas Transmission Equipment
Accounting Policies
Annual depreciation provision			2.90%	2.80%	2.80%
Common Plant
Accounting Policies
Annual depreciation provision			7.30%	7.30%	7.10%
Subsidiaries [Member]
Accounting Policies
Area of service territory (sqmi) | mi²			6,000
Allowance for doubtful accounts			$ 20,080	$ 8,294
Public Utilities, Rate Case, Deferred Storm Costs Threshold						$ 10,000	$ 8,000
Variable Interest Entity, Measure of Activity, Expense			$ 4,200
Contract Length, PPA			20 years
Puget LNG [Member]
Accounting Policies
Jointly Owned Non-Utility Plant Share			57.00%
Construction in Progress, Gross			$ 231,600	199,900
Operating Costs and Expenses			$ 600	1,200	$ 2,000
Tacoma LNG [Member]
Accounting Policies
Jointly Owned Non-Utility Plant Share			43.00%
Construction in Progress, Gross			$ 207,700	$ 162,800
Decoupling Mechanism [Member] | Electricity, US Regulated [Member] | Subsidiaries [Member] | Maximum
Accounting Policies
Public Utilities, Approved Rate Increase (Decrease), Percentage	3.00%
Decoupling Mechanism [Member] | Natural Gas, US Regulated [Member] | Subsidiaries [Member] | Maximum
Accounting Policies
Public Utilities, Approved Rate Increase (Decrease), Percentage	5.00%	3.00%

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - AFUDC (Details)	Dec. 19, 2017	Dec. 31, 2020
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]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities	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, 2020	Dec. 31, 2019
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Allowance for Credit Losses, Beginning Balance		$ 8,294
Provision for Credit Loss	$ 23,292
Receivables Charged-Off	(11,506)
Allowance for Credit Loss, Ending Balance	$ 20,080

Revenue (Details)

Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenue from Contract with Customer, Including Assessed Tax	$ 3,222,391	$ 3,311,090	$ 3,222,093
Regulated Operating Revenue, Other	26,121	28,718	39,829
Revenues	3,326,450	3,401,130	3,346,496
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction	15,359
Puget LNG [Member]
Revenue, Remaining Performance Obligation, Amount	195,566
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
Electricity, US Regulated [Member]
Revenue from Contract with Customer, Including Assessed Tax	$ 2,106,122	2,132,522	2,138,008
Natural Gas, US Regulated [Member]
Revenue from Contract with Customer, Including Assessed Tax	938,061	870,457	849,898
Other Revenue From Contracts with Customers [Member]
Revenue from Contract with Customer, Including Assessed Tax	178,208	308,111	234,187
Decoupling over-collection [Member]
Regulated Operating Revenue, Other	35,006	(18,634)	(22,852)
Other Non-606 Revenue [Member]
Regulated Operating Revenue, Other	$ 69,053	$ 108,674	$ 147,255

Regulation and Rates Net regula

Regulation and Rates Net regulatory assets and liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Regulatory Assets [Line Items]
Regulatory Assets	$ 929,835	$ 861,678
Regulatory Liabilities	1,781,546	1,833,655
Deferred income tax charge
Regulatory Assets [Line Items]
Regulatory Liabilities	$ 713	757
Regulatory liabilities related to power contracts
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Min	5 years
Net Regulatory Assets, Remaining Amortization Period, Max	32 years
Regulatory Liabilities	$ 95,774	156,597
Various other regulatory liabilities
Regulatory Assets [Line Items]
Regulatory Liabilities	1,264	1,265
Net Regulatory Assets
Regulatory Assets [Line Items]
Net Regulatory Assets	(851,711)	(971,977)
Requlatory Assets Related to Power Contracts
Regulatory Assets [Line Items]
Regulatory Assets	$ 11,728	14,146
Net Regulatory Assets, Remaining Amortization Period, Min	5 years
Net Regulatory Assets, Remaining Amortization Period, Max	32 years
Subsidiaries [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities Reclassified from Accumulated Depreciation	$ 508,700	469,900
Subsidiaries [Member] | Deferred income tax charge
Regulatory Assets [Line Items]
Regulatory Liabilities	953,987	946,936
Subsidiaries [Member] | Cost of removal
Regulatory Assets [Line Items]
Regulatory Liabilities	$ 508,707	469,922
Subsidiaries [Member] | Treasury grants
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period	3 years
Regulatory Liabilities	$ 43,164	101,981
Subsidiaries [Member] | Production tax credits [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	47,094	85,323
Subsidiaries [Member] | Gain on Sale Shuffleton [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	11,131	12,483
Subsidiaries [Member] | Microsoft special contract [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	0	12,661
Subsidiaries [Member] | Repurposed production tax credits [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	$ 79,581	24,823
Subsidiaries [Member] | Deferred decoupling revenue, net [Member]
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period	2 years
Regulatory Liabilities	$ 16,448	8,500
Subsidiaries [Member] | Various other regulatory liabilities
Regulatory Assets [Line Items]
Regulatory Liabilities	10,796	11,500
Subsidiaries [Member] | Liabilities, Total
Regulatory Assets [Line Items]
Regulatory Liabilities	1,685,221	1,676,550
Subsidiaries [Member] | Net Regulatory Assets
Regulatory Assets [Line Items]
Net Regulatory Assets	(767,114)	(829,018)
Subsidiaries [Member] | Green Direct
Regulatory Assets [Line Items]
Regulatory Liabilities	14,313	2,421
Subsidiaries [Member] | Storm Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 108,491	121,894
Net Regulatory Assets, Remaining Amortization Period	5 years
Subsidiaries [Member] | Chelan PUD contract initiation
Regulatory Assets [Line Items]
Regulatory Assets	$ 76,787	83,875
Net Regulatory Assets, Remaining Amortization Period	10 years 9 months 18 days
Subsidiaries [Member] | Environmental remediation
Regulatory Assets [Line Items]
Regulatory Assets	$ 102,647	68,486
Subsidiaries [Member] | Lower Snake River
Regulatory Assets [Line Items]
Regulatory Assets	$ 58,442	62,899
Net Regulatory Assets, Remaining Amortization Period	16 years 4 months 24 days
Subsidiaries [Member] | Deferred decoupling revenue, net [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 88,504	43,509
Net Regulatory Assets, Remaining Amortization Period	2 years
Subsidiaries [Member] | Baker Dam Licensing Operating Maintenance Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 54,354	56,427
Hydro license term	50 years
Subsidiaries [Member] | Deferred Washington Commission AFUDC
Regulatory Assets [Line Items]
Regulatory Assets	$ 59,763	57,553
Net Regulatory Assets, Remaining Amortization Period	30 years
Subsidiaries [Member] | Property tax tracker
Regulatory Assets [Line Items]
Regulatory Assets	$ 24,860	22,442
Net Regulatory Assets, Remaining Amortization Period	2 years
Subsidiaries [Member] | Unamortized loss on reacquired debt
Regulatory Assets [Line Items]
Regulatory Assets	$ 37,991	40,177
Net Regulatory Assets, Remaining Amortization Period, Min	1 year
Net Regulatory Assets, Remaining Amortization Period, Max	47 years
Subsidiaries [Member] | Energy Conservation Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 8,009	25,272
Subsidiaries [Member] | GTZ depreciation expense deferral [Member]
Regulatory Assets [Line Items]
Regulatory Assets	53,236	22,148
Subsidiaries [Member] | Advanced metering infrastructure [Member]
Regulatory Assets [Line Items]
Regulatory Assets	22,652	14,845
Subsidiaries [Member] | Generation plant major maintenance [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 10,494	12,744
Net Regulatory Assets, Remaining Amortization Period, Min	3 years
Net Regulatory Assets, Remaining Amortization Period, Max	10 years
Subsidiaries [Member] | PGA deferral of unrealized losses on derivative instruments
Regulatory Assets [Line Items]
Regulatory Assets	$ 6,973	0
Subsidiaries [Member] | White River relicensing and other costs
Regulatory Assets [Line Items]
Regulatory Assets	$ 0	6,399
Net Regulatory Assets, Remaining Amortization Period	0 years
Subsidiaries [Member] | Mint Farm ownership and operating costs
Regulatory Assets [Line Items]
Regulatory Assets	$ 8,318	10,318
Net Regulatory Assets, Remaining Amortization Period	4 years 3 months 18 days
Subsidiaries [Member] | PGA receivable [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 87,655	132,766
Net Regulatory Assets, Remaining Amortization Period	2 years
Subsidiaries [Member] | Snoqualmie Licensing Operating Maintenance Costs
Regulatory Assets [Line Items]
Regulatory Assets	$ 7,435	7,442
Hydro license term	40 years
Subsidiaries [Member] | Colstrip major maintenance [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 4,335	2,929
Subsidiaries [Member] | PCA Mechanism [Member]
Regulatory Assets [Line Items]
Regulatory Assets	82,801	41,745
Subsidiaries [Member] | Colstrip common property
Regulatory Assets [Line Items]
Regulatory Assets	$ 2,472	3,188
Net Regulatory Assets, Remaining Amortization Period	3 years 4 months 24 days
Subsidiaries [Member] | Various other regulatory assets
Regulatory Assets [Line Items]
Regulatory Assets	$ 8,247	9,044
Subsidiaries [Member] | Assets, Total
Regulatory Assets [Line Items]
Regulatory Assets	918,107	847,532
Subsidiaries [Member] | WUTC Electric Vehicle
Regulatory Assets [Line Items]
Regulatory Assets	$ 3,641	$ 1,430

Power Cost Only Rate Case (Deta

Power Cost Only Rate Case (Details) - Subsidiaries [Member] - Electricity, US Regulated [Member] - PCORC [Member] - USD ($) $ in Millions	Feb. 02, 2021	Dec. 09, 2020
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 78.5
Public Utilities, Requested Rate Increase (Decrease), Percentage		3.70%
Subsequent Event [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 88
Public Utilities, Requested Rate Increase (Decrease), Percentage	4.10%

General Rate Case Filing (Detai

General Rate Case Filing (Details) - Subsidiaries [Member] - USD ($) $ in Millions	Sep. 30, 2020	Jul. 31, 2020	Jul. 08, 2020	Jan. 15, 2020	Jun. 20, 2019	Dec. 19, 2017
Regulatory Assets [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities						7.60%
General Rate Case [Member]
Regulatory Assets [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities				7.48%	7.62%
Public Utilities, Requested Return on Equity, Percentage				9.50%	9.80%
Annual Revenue Requirement	$ 25.6
Fiscal Period Duration					4 years
General Rate Case [Member] | Maximum
Regulatory Assets [Line Items]
Public Utilities, Approved Return on Equity, Percentage			9.40%
Public Utilities, Approved Equity Capital Structure, Percentage			48.50%
Public Utilities, Approved Debt Capital Structure, Net of Tax, Percentage			6.80%
General Rate Case, Electric [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage				6.90%
General Rate Case, Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage				7.90%
Electricity, US Regulated [Member] | General Rate Case [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 27.7	$ 0.9
Public Utilities, Requested Rate Increase (Decrease), Percentage					6.90%
Public Utilities, Requested Rate Increase (Decrease), Amount				$ (1.5)
Public Utilities, Approved Rate Increase (Decrease), Percentage		1.30%	0.05%
Public Utilities, Approved Debt Capital Structure, Percentage			7.39%
Public Utilities, Interim Rate Increase (Decrease), Amount		$ 59.6	$ 29.5
Public Utilities, Interim Rate Increase (Decrease), Percentage		2.90%	1.60%
Public Utilities Attrition Adjustment Increase Decrease Amount			$ 23.9
PublicUtilitiesIncremenalRateIncreaseDecreaseAmount		$ 30.1
Natural Gas, US Regulated [Member] | General Rate Case [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 0.2	$ 1.3
Public Utilities, Requested Rate Increase (Decrease), Percentage					7.90%
Public Utilities, Approved Rate Increase (Decrease), Percentage		0.02%	0.15%
Public Utilities, Interim Rate Increase (Decrease), Amount		$ 42.9	$ 36.5
Public Utilities, Interim Rate Increase (Decrease), Percentage		5.60%	4.00%
Public Utilities Attrition Adjustment Increase Decrease Amount			$ 16.2
PublicUtilitiesIncremenalRateIncreaseDecreaseAmount		$ 6.4

Expedited Rate Filing Rate Adju

Expedited Rate Filing Rate Adjustment (Details) - USD ($)	Mar. 01, 2019	Jan. 30, 2019	Nov. 07, 2018	May 01, 2018	Dec. 19, 2017	Dec. 31, 2020	May 01, 2020	Dec. 31, 2019	Dec. 31, 2018
Regulatory Assets [Line Items]
Income tax (benefit) expense						$ 1,664,000		$ 17,073,000	$ 30,092,000
Subsidiaries [Member]
Regulatory Assets [Line Items]
Income tax (benefit) expense				$ 34,600,000		$ 26,242,000		$ 39,148,000	$ 50,700,000
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities					7.60%
Subsidiaries [Member] | Expedited Rate Filing (ERF) [Member]
Regulatory Assets [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities			7.49%		7.60%
Fiscal Period Duration							1 year
Subsidiaries [Member] | Natural Gas, US Regulated [Member] | Expedited Rate Filing (ERF) [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 6,100,000		$ 21,700,000
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 25,900,000	$ 21,500,000
Public Utilities, Requested Rate Increase (Decrease), Percentage			2.70%
Subsidiaries [Member] | Electricity, US Regulated [Member] | Expedited Rate Filing (ERF) [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 18,900,000
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 0
Public Utilities, Requested Rate Increase (Decrease), Percentage			0.90%

Washington Commission Tax Defer

Washington Commission Tax Deferral Filing (Details) - USD ($) $ in Thousands	Jun. 20, 2019	May 01, 2018	Nov. 30, 2022	Jul. 19, 2021	Dec. 31, 2020	Dec. 31, 2019	Apr. 30, 2019	Dec. 31, 2018	Jul. 19, 2023	Jul. 08, 2020	Apr. 30, 2020
Regulatory Assets [Line Items]
Income tax (benefit) expense					$ 1,664	$ 17,073		$ 30,092
Subsidiaries [Member]
Regulatory Assets [Line Items]
Income tax (benefit) expense		$ 34,600			$ 26,242	$ 39,148		$ 50,700
Subsidiaries [Member] | General Rate Case [Member]
Regulatory Assets [Line Items]
Protected Excess Deferred Income Tax										$ 70,800
Unprotected Excess Deferred Income Tax										$ 38,900
Fiscal Period Duration	4 years
Subsidiaries [Member] | Forecast [Member]
Regulatory Assets [Line Items]
Fiscal Period Duration			20 years
Subsidiaries [Member] | Forecast [Member] | General Rate Case [Member]
Regulatory Assets [Line Items]
Fiscal Period Duration				12 months					36 months
Subsidiaries [Member] | Electricity, US Regulated [Member] | Tax Cuts and Jobs Act [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage							(3.40%)
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount							$ (72,900)
Contract with Customer, Refund Liability											$ 100
Subsidiaries [Member] | Natural Gas, US Regulated [Member] | Tax Cuts and Jobs Act [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage							(2.70%)
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount							$ (23,600)

Decoupling Filings (Details)

Decoupling Filings (Details) - USD ($) $ in Millions	Aug. 31, 2020	Aug. 30, 2020	Nov. 01, 2019	Oct. 31, 2019	Dec. 19, 2017	Dec. 18, 2017	Dec. 31, 2020	Dec. 31, 2019
Decoupling Mechanism [Member]
Regulatory Assets [Line Items]
Deferred Revenue, Revenue Recognized							$ 0
Subsidiaries [Member] | Decoupling Mechanism [Member]
Regulatory Assets [Line Items]
Fiscal Period Duration	2 years	1 year
Subsidiaries [Member] | Purchased Gas Adjustment [Member]
Regulatory Assets [Line Items]
Fiscal Period Duration	3 years		2 years	1 year
Subsidiaries [Member] | Electricity, US Regulated [Member] | Decoupling Mechanism [Member]
Regulatory Assets [Line Items]
Contract with Customer, Liability, Revenue Recognized							(8)	$ 0.8
PublicUtilitiesIncremenalRateIncreaseDecreaseAmount							$ 4.3
Subsidiaries [Member] | Electricity, US Regulated [Member] | Maximum | Decoupling Mechanism [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage					3.00%
Subsidiaries [Member] | Natural Gas, US Regulated [Member] | Maximum | Decoupling Mechanism [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage					5.00%	3.00%

Schedule of Power Cost Adjustme

Schedule of Power Cost Adjustment Mechanism (Details) - Subsidiaries [Member] $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Regulatory Assets [Line Items]
Annual Power Cost Variability, Interest	$ 2	$ 1
Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount	75.4	67.2
Customer's share | Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount	$ 43.3	36
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		$ 31.2
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	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2020	Dec. 31, 2019
Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount			$ 75.4	$ 67.2
Under-collection | Companys share
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount				31.2
Under-collection | Customer's share
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount			$ 43.3	36
Under-collection | Customer's share plus interest [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount	$ 41.7	$ 4.7		37
Maximum Power | Customer's share plus interest [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount				$ 20

Purchased Gas Adjustment Mechan

Purchased Gas Adjustment Mechanism (Details) - USD ($) $ in Thousands	Nov. 01, 2020	Aug. 31, 2020	Nov. 01, 2019	Oct. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	May 01, 2020	Dec. 31, 2018
Regulatory Assets [Line Items]
Other regulatory assets					$ 747,651	$ 673,021
Subsidiaries [Member]
Regulatory Assets [Line Items]
Other regulatory assets					747,651	673,021
PGA payable					87,655	132,766		$ 9,921
Subsidiaries [Member] | Purchased Gas Adjustment [Member]
Regulatory Assets [Line Items]
Other regulatory assets							$ 4,900
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 32,600		$ 17,800
Annual revenue	37,400		100,600
Out of Cycle PGA	$ 69,400		54,000
Under collected commodity balances			114,400
Commodity Costs			10,800
Refund to Customers, remaining balance			4,100
Refund to Customers			$ 54,700
Purchased natural gas costs					314,792	406,162
Purchased natural gas costs, recoverable					(363,886)	(289,876)
Purchased natural gas adjustment, interest					$ 3,983	$ 6,559
Fiscal Period Duration		3 years	2 years	1 year

Narrative (Details)

Narrative (Details) - USD ($)	Apr. 06, 2020	Apr. 10, 2019	Dec. 19, 2017	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Jul. 21, 2020	Jan. 01, 2018	Jan. 01, 2017
Regulatory Assets [Line Items]
Depreciation and amortization				$ 647,755,000	$ 656,323,000	$ 666,432,000
Accrual for Environmental Loss Contingencies				35,700,000
Natural Gas, US Regulated [Member]
Regulatory Assets [Line Items]
Environmental Remediation Expense				43,700,000
Environmental Expense and Liabilities				50,900,000	54,800,000
Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Environmental Remediation Expense				48,000,000
Environmental Expense and Liabilities				51,800,000	13,700,000
Subsidiaries [Member]
Regulatory Assets [Line Items]
Depreciation and amortization				647,546,000	656,220,000	$ 666,324,000
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities			7.60%
Customer Bill Assistance	$ 1,000
Liabilities, Other than Long-term Debt, Noncurrent	$ 11,000,000						$ 4,500,000
Storm Damage Costs Incurred During Period				21,800,000	39,300,000
Public Utilities, Rate Case, Deferred Storm Costs Threshold								$ 10,000,000	$ 8,000,000
Public Utilities, Rate Case, Deferred Storm Qualifying Costs								$ 500,000
Subsidiaries [Member] | Storm that occurred in 2018 [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Deferred During Period					28,500,000
Subsidiaries [Member] | Storm that occurred in 2019 [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Deferred During Period				11,200,000
Subsidiaries [Member] | Storm that occurred in 2017 [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Deferred During Period					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				$ 2,800,000	$ 21,700,000
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities		6.89%

Dividend Payment Restrictions (

Dividend Payment Restrictions (Details)	12 Months Ended
	Dec. 31, 2020USD ($)
Parent [Line Items]
Retained Earnings, Unappropriated	$ 1,100,000,000
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio, Threshold For Dividend Payment	2
EBITDA Interest Expense Ratio	3.4
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	44.00%
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	5.2
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, 2020	Dec. 31, 2019
Public Utility, Property, Plant and Equipment
Accumulated amortization of capital leases	$ 1,600	$ 1,000
Utility Plant
Distribution plant	7,028,731	6,602,934
Production plant	3,096,092	3,066,792
Transmission plant	1,494,781	1,463,288
General plant	697,501	698,275
Intangible plant (including capitalized software)1	779,767	735,826
Plant acquisition adjustment	242,826	242,826
Underground storage	39,498	37,511
Liquefied natural gas storage	12,628	12,628
Plant held for future use	45,929	46,233
Recoverable Cushion Gas	8,655	8,655
Plant not classified	384,794	316,923
Finance leases, net of accumulated amortization2	881	1,488
Less: accumulated provision for depreciation	(3,671,094)	(3,236,240)
Subtotal	10,160,989	9,997,139
Construction work in progress	712,204	591,199
Net utility plant	$ 10,873,193	10,588,338
Minimum
Public Utility, Property, Plant and Equipment
Distribution plant, Estimated Useful Life	20 years
Production plant, Estimated Useful Life	12 years
Transmission plant, Estimated Useful Life	43 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	60 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	$ 8,592,720	8,185,700
Production plant	3,767,014	3,743,493
Transmission plant	1,601,731	1,571,186
General plant	726,327	731,279
Intangible plant (including capitalized software)1	770,317	726,383
Plant acquisition adjustment	282,792	282,792
Underground storage	52,927	50,963
Liquefied natural gas storage	14,498	14,498
Plant held for future use	46,081	46,385
Recoverable Cushion Gas	8,655	8,655
Plant not classified	384,794	316,923
Finance leases, net of accumulated amortization2	881	1,488
Less: accumulated provision for depreciation	(6,087,748)	(5,682,606)
Subtotal	10,160,989	9,997,139
Construction work in progress	712,204	591,199
Net utility plant	$ 10,873,193	$ 10,588,338

Utility Plant - Jointly Owned U

Utility Plant - Jointly Owned Utility Plant (Details) $ in Thousands	Dec. 31, 2020USD ($)
Colstrip Units 3 & 4
Jointly Owned Utility Plant Interests
Plant in Service at Cost	$ 328,967
Construction Work in Progress	0
Accumulated Depreciation	(118,546)
Frederickson 1
Jointly Owned Utility Plant Interests
Plant in Service at Cost	62,519
Construction Work in Progress	0
Accumulated Depreciation	(14,533)
Jackson Prairie [Member]
Jointly Owned Utility Plant Interests
Plant in Service at Cost	38,843
Construction Work in Progress	1,725
Accumulated Depreciation	(9,620)
Tacoma LNG [Member]
Jointly Owned Utility Plant Interests
Plant in Service at Cost	0
Construction Work in Progress	439,264
Accumulated Depreciation	0
Subsidiaries [Member] | Colstrip Units 1 and 2 [Member]
Jointly Owned Utility Plant Interests
Regulatory Assets, Unrecovered plant balance	$ 126,500
Subsidiaries [Member] | Colstrip Units 3 & 4
Jointly Owned Utility Plant Interests
Company’s Ownership Share	25.00%
Plant in Service at Cost	$ 587,424
Construction Work in Progress	0
Accumulated Depreciation	$ (377,003)
Subsidiaries [Member] | Frederickson 1
Jointly Owned Utility Plant Interests
Company’s Ownership Share	49.85%
Plant in Service at Cost	$ 68,586
Construction Work in Progress	0
Accumulated Depreciation	$ (20,601)
Subsidiaries [Member] | Jackson Prairie [Member]
Jointly Owned Utility Plant Interests
Company’s Ownership Share	33.34%
Plant in Service at Cost	$ 52,927
Construction Work in Progress	1,725
Accumulated Depreciation	(23,705)
Subsidiaries [Member] | Tacoma LNG [Member]
Jointly Owned Utility Plant Interests
Plant in Service at Cost	0
Construction Work in Progress	207,700
Accumulated Depreciation	$ 0

Utility Plant - Schedule of Ass

Utility Plant - Schedule of Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Tacoma LNG [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Decommissioning Liability, Noncurrent	$ 3,300	$ 3,000
Subsidiaries [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of the period	181,353	182,203
Relief of liability	(9,647)	(12,449)
Revisions in estimated cash flows	38,677	5,922
Accretion expense	5,780	5,677
Asset Retirement Obligation, Ending Balance	216,163	181,353
Decommissioning Liability, Noncurrent	9,600	12,400
Subsidiaries [Member] | Colstrip Units 1 and 2 [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Decommissioning Liability, Noncurrent	29,700	4,200
Regulatory Assets, Unrecovered plant balance	126,500
Environmental Remediation, Current Period Addition	39,000
Puget LNG [Member] | Tacoma LNG [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Decommissioning Liability, Noncurrent	$ 7,400	$ 4,300

Utility Plant - Narrative (Deta

Utility Plant - Narrative (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Tacoma LNG [Member]
Jointly Owned Utility Plant Interests
Decommissioning Liability, Noncurrent	$ 3,300	$ 3,000
Subsidiaries [Member]
Jointly Owned Utility Plant Interests
Decommissioning Liability, Noncurrent	9,600	12,400
Subsidiaries [Member] | Colstrip Units 1 and 2 [Member]
Jointly Owned Utility Plant Interests
Decommissioning Liability, Noncurrent	29,700	4,200
Subsidiaries [Member] | Colstrip Units 3 and 4 [Member]
Jointly Owned Utility Plant Interests
Decommissioning Liability, Noncurrent	2,000	500
Puget LNG [Member] | Tacoma LNG [Member]
Jointly Owned Utility Plant Interests
Decommissioning Liability, Noncurrent	$ 7,400	$ 4,300

Long-Term Debt (Schedule of Lon

Long-Term Debt (Schedule of Long-Term Debt Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Sep. 26, 2019	Oct. 01, 2018	Mar. 05, 2018	Oct. 10, 2017
Debt Instrument [Line Items]
Total PSE long-term debt	$ 6,624,972
Long Term Debt, Reconciliation, Fair Value Adjustment	(165,357)	$ (173,865)
Long-term Debt, term loan			$ 210,000	$ 100,000
Long-term Line of Credit, Noncurrent	14,700	24,100
Unamortized discount on senior notes	(4,947)	(52)
Long-term Debt, Excluding Current Maturities	5,892,440	5,920,325
Current maturities of long-term debt	526,412	452,412
Short-term debt	373,800	176,000
Long-term Debt, Term			3 years
$174M Term Loan Due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt, term loan	0	174,000
Current maturities of long-term debt	24,000
$210M Term Loan Due 2022
Debt Instrument [Line Items]
Long-term Debt, term loan	210,000	210,000
6.000% Senior Secured Note Due 2021 | Senior Secured Note
Debt Instrument [Line Items]
Current maturities of long-term debt	$ 500,000
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%
Total PSE long-term debt	$ 450,000	450,000
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	6.00%
Total PSE long-term debt	$ 0	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	0
Subsidiaries [Member]
Debt Instrument [Line Items]
Total PSE long-term debt	4,376,272
Unamortized discount on senior notes	(35,816)	(37,718)
Long-term Debt, Excluding Current Maturities	4,338,044	4,336,142
Current maturities of long-term debt	2,412	2,412
Short-term debt	$ 373,800	176,000
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	4.00%
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	7.00%
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

Long-Term Debt (Narrative) (Det

Long-Term Debt (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Jun. 18, 2020	Sep. 26, 2019	Aug. 02, 2019	Oct. 01, 2018
Debt Instrument [Line Items]
Long-term Debt, term loan					$ 210,000		$ 100,000
Total PSE long-term debt	$ 6,624,972
Long-term Line of Credit, Noncurrent	14,700	$ 24,100
Long-term debt	6,624,972
Line of Credit Facility, Remaining Borrowing Capacity						$ 550,000
Line of Credit Facility, Maximum Borrowing Capacity	$ 1,300,000
Clean Air Rule, Emissions Cap, Percentage	(5.00%)
Gain (Loss) on Extinguishment of Debt	$ (13,546)	0	$ 0
Repayments of Debt	159,400	0	$ 0
Long-term Debt, Term					3 years
$174M Term Loan Due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt, term loan	0	174,000
Senior Secured Note | 6.500% Senior Secured Note Due 2020
Debt Instrument [Line Items]
Stated interest rate percent				6.50%
Extinguishment of Debt, Amount	463,200
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net				$ 300
Debt Instrument, Increase, Accrued Interest	400
Gain (Loss) on Extinguishment of Debt	13,500
Long-term debt, Principal				$ 450,000
Term Loan Expansion [Member] | $174M Term Loan Due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt, term loan							$ 24,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Repayments of Debt	31,600
term-loan
Debt Instrument [Line Items]
Repayments of Debt	150,000
Subsidiaries [Member]
Debt Instrument [Line Items]
Total PSE long-term debt	4,376,272
Long-term debt	4,376,272
Line of Credit Facility, Maximum Borrowing Capacity	1,400,000					$ 1,000,000
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%

Long-Term Debt (Schedule of Mat

Long-Term Debt (Schedule of Maturities of Long-Term Debt) (Details) $ in Thousands	Dec. 31, 2020USD ($)
Maturities of Long-term Debt [Abstract]
2021	$ 526,412
2022	660,000
2023	14,700
2024	0
2025	417,000
Thereafter	5,006,860
Total long-term debt	6,624,972
Subsidiaries [Member]
Maturities of Long-term Debt [Abstract]
2021	2,412
2022	0
2023	0
2024	0
2025	17,000
Thereafter	4,356,860
Total long-term debt	4,376,272
Parent Company [Member]
Maturities of Long-term Debt [Abstract]
2021	524,000
2022	660,000
2023	14,700
2024	0
2025	400,000
Thereafter	650,000
Total long-term debt	$ 2,248,700

Liquidity Facilities and Othe_2

Liquidity Facilities and Other Financing Arrangements (Details) - USD ($) $ in Thousands	Sep. 25, 2019	Feb. 10, 2012	Dec. 31, 2020	Dec. 31, 2019	Aug. 02, 2019	Oct. 10, 2017
Short-term Debt [Line Items]
Short-term debt			$ 373,800	$ 176,000
Line of Credit Facility, Maximum Borrowing Capacity			1,300,000
Line of Credit Facility, Expiration Period	1 year
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			$ 373,800	$ 176,000
Weighted-average interest rate on short-term debt (percent)			2.00%	3.40%
Line of Credit Facility, Current Same-Day Borrowing Capacity			$ 75,000
Line of Credit Facility, Maximum Borrowing Capacity			$ 1,400,000		$ 1,000,000
Maximum capitalization percentage			65.00%
Derivative, Basis Spread on Variable Rate			1.25%
Line of Credit, Unused Capacity, Commitment Fee Percentage			0.175%
Line of Credit Facility, Expiration Period	1 year
Subsidiaries [Member] | Working Capital Needs
Short-term Debt [Line Items]
Current borrowing capacity of line of credit						$ 800,000
Subsidiaries [Member] | Energy Hedging Activities [Member]
Short-term Debt [Line Items]
Outstanding amount for line of credit			$ 1,000
Subsidiaries [Member] | Letter of Credit | Working Capital Needs
Short-term Debt [Line Items]
Current borrowing capacity of line of credit			2,700
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)			25.00%
Debt instrument variable rate basis			one-month LIBOR
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			$ 14,700

Leases (Details)

Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Lease, Remaining Lease Term	49 years
Lease Extension Term	25 years
Subsidiaries [Member]
Lessee, Lease, Description [Line Items]
Right-of-Use, Modification, Operating	$ 0	$ 14,712

Leases (Schedule of Operating L

Leases (Schedule of Operating Lease Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Operating Leased Assets [Line Items]
Finance Lease, Right-of-Use Asset, Amortization	$ 607	$ 562
Finance Lease, Interest Expense	34	40
Finance Lease, Cost	641	602
Operating Lease, Cost	21,983	$ 20,639
Subsidiaries [Member] | Land [Member]
Operating Leased Assets [Line Items]
Operating Lease, Cost	$ 1,000

Leases (Cash paid) (Details)

Leases (Cash paid) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Operating Lease, Payments	$ 15,305	$ 14,104
Operating Lease, Payments, Use	6,678	6,535
Finance Lease, Interest Payment on Liability	34	40
Finance Lease, Principal Payments	607	562
Subsidiaries [Member]
Lessee, Lease, Description [Line Items]
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	6,302	5,976
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	0	745
Right-of-Use, Modification, Operating	0	$ 14,712
Subsidiaries [Member] | Land [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Payments, Use	$ 1,000

Leases (Balance Sheet) (Details

Leases (Balance Sheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Operating lease right-of-use asset	$ 172,167	$ 183,048
Operating lease liabilities	19,204	15,862
Operating lease liabilities	160,980	174,327
Operating Lease, Liability	180,184	190,189
Finance Lease, Right-of-Use Asset	881	1,488
Finance Lease, Liability, Current	475	669
Finance Lease, Liability, Noncurrent	320	811
Finance Lease, Liability	$ 795	$ 1,480
Operating Lease, Weighted Average Remaining Lease Term	18 years 11 months 19 days	19 years 2 months 26 days
Finance Lease, Weighted Average Remaining Lease Term	2 years	2 years 9 months 3 days
Operating Lease, Weighted Average Discount Rate, Percent	3.59%	3.59%
Finance Lease, Weighted Average Discount Rate, Percent	2.98%	2.98%

Leases (Remaining Cash Payments

Leases (Remaining Cash Payments) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months	$ 23,170
Lessee, Operating Lease, Liability, Payments, Due Year Two	22,785
Lessee, Operating Lease, Liability, Payments, Due Year Three	22,345
Lessee, Operating Lease, Liability, Payments, Due Year Four	21,613
Lessee, Operating Lease, Liability, Payments, Due Year Five	18,249
Lessee, Operating Lease, Liability, Payments, Due after Year Five	144,912
Lessee, Operating Lease, Liability, Payments, Due	253,074
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(72,890)	$ (79,209)
Operating Lease, Liability	180,184	190,189
Finance Lease, Liability, Payments, Due Next Twelve Months	508
Finance Lease, Liability, Payments, Due Year Two	279
Finance Lease, Liability, Payments, Due Year Three	98
Finance Lease, Liability, Payments, Due Year Four	0
Finance Lease, Liability, Payments, Due Year Five	0
Finance Lease, Liability, Payments, Due after Year Five	0
Finance Lease, Liability, Payment, Due	885
Finance Lease, Liability, Undiscounted Excess Amount	(90)	(48)
Finance Lease, Liability	$ 795	$ 1,480

Leases (Schedule of Future Mini

Leases (Schedule of Future Minimum Lease Payments for Non-cancellable Leases) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Operating
2019		$ 22,500
2020		22,527
2021		21,856
2022		21,415
2023		20,690
Thereafter		160,410
Total minimum lease payments		269,398
Less imputed interest	$ (72,890)	(79,209)
Operating Lease, Liability	180,184	190,189
Capital
2019		643
2020		508
2021		279
2022		98
2023		0
Thereafter		0
Total minimum lease payments		1,528
Less imputed interest	(90)	(48)
Finance Lease, Liability	$ 795	$ 1,480

Leases (ASC 840) (Details)

Leases (ASC 840) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Operating Lease Expense	$ 34,093

Accounting for Derivative Ins_3

Accounting for Derivative Instruments and Hedging Activities (Schedule of Derivative Assets and Liabilities) (Details) $ in Thousands, MWh in Millions, MMBTU in Millions	Dec. 31, 2020USD ($)MMBTUMWh	Dec. 31, 2019USD ($)MMBTUMWh
Derivative [Line Items]
Assets, Current	$ 33,015	$ 23,626
Assets, Long-term	8,805	7,682
Liabilities, Current	31,441	13,428
Liabilities, Long-term	29,833	12,693
Not Designated as Hedging Instrument
Derivative [Line Items]
Total derivative assets	41,820	31,308
Total derivative liabilities	61,274	26,121
Not Designated as Hedging Instrument | Parent Company [Member]
Derivative [Line Items]
Assets, Current	33,015	23,626
Assets, Long-term	8,805	7,682
Liabilities, Current	31,441	13,428
Liabilities, Long-term	$ 29,833	$ 12,693
Not Designated as Hedging Instrument | Electric Generation Fuel
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	212.2	229.3
Not Designated as Hedging Instrument | Purchased Electricity
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MWh	6.6	10.4
Not Designated as Hedging Instrument | Natural Gas Portfolio
Derivative [Line Items]
Total derivative assets	$ 19,276	$ 11,375
Total derivative liabilities	14,352	8,617
Not Designated as Hedging Instrument | Electric Portfolio
Derivative [Line Items]
Total derivative assets	22,544	19,933
Total derivative liabilities	$ 46,922	$ 17,504
Not Designated as Hedging Instrument | Gas Derivatives
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	320	316

Accounting for Derivative Ins_4

Accounting for Derivative Instruments and Hedging Activities (Offsetting) (Details) - Commodity Contract [Member] - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Derivative Asset, Fair Value, Amount Offset Against Collateral [Abstract]
Derivative Asset, Fair Value, Gross Asset	$ 41,820	$ 31,308
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	0
Derivative Asset	41,820	31,308
Derivative, Collateral, Obligation to Return Securities	21,696	14,922
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	20,124	16,386
Derivative Liability, Fair Value, Amount Offset Against Collateral [Abstract]
Derivative Liability, Fair Value, Gross Liability	61,274	26,121
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	0
Derivative Liability	61,274	26,121
Derivative, Collateral, Right to Reclaim Securities	21,696	14,922
Derivative, Collateral, Right to Reclaim Cash	9,343	(2,000)
Derivative Liability, Fair Value, Amount Offset Against Collateral	$ 30,235	$ 13,199

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments, net	$ (26,807)	$ (3,574)	$ 41,662
Credit Rating
Derivative Instruments, (Loss) Gain [Line Items]
Posted Collateral	17,900
Natural Gas Portfolio
Derivative Instruments, (Loss) Gain [Line Items]
Posted Collateral	3,000
Natural Gas Portfolio | Credit Rating
Derivative Instruments, (Loss) Gain [Line Items]
Posted Collateral	1,000
Not Designated as Hedging Instrument
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments, net	(36,519)	55,940	80,124
Not Designated as Hedging Instrument | Energy Related Derivative | Unrealized (Gain) Loss on Derivative Instruments, Net
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments, net	5,534	16,970	23,186
Not Designated as Hedging Instrument | Commodity Contract [Member] | Electric Generation Fuel
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments, net	5,246	10,828	26,222
Not Designated as Hedging Instrument | Commodity Contract [Member] | Purchased Electricity
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments, net	(14,958)	48,686	12,240
Not Designated as Hedging Instrument | Electric | Unrealized (Gain) Loss on Derivative Instruments, Net
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments, net	$ (32,341)	$ (20,544)	$ 18,476

Accounting for Derivative Ins_6

Accounting for Derivative Instruments and Hedging Activities (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Natural Gas Portfolio
Derivative [Line Items]
Posted Collateral	$ 3,000
Electric Portfolio
Derivative [Line Items]
Posted Collateral	$ 20,903	$ 14,827
External Credit Rating, Investment Grade [Member] | Electric Portfolio
Derivative [Line Items]
Percentage of derivatives with credit risk exposure	98.60%
External Credit Rating, Non Investment Grade [Member] | Electric Portfolio
Derivative [Line Items]
Percentage of derivatives with credit risk exposure	1.40%
Credit Rating
Derivative [Line Items]
Posted Collateral	$ 17,900
Credit Rating | Natural Gas Portfolio
Derivative [Line Items]
Posted Collateral	1,000
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) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Electric Portfolio
Derivative [Line Items]
Fair Value Liability	$ 42,885	$ 11,363
Posted Collateral	20,903	14,827
Contingent Collateral	26,966	6,110
Forward Value of Contract [Member] | Electric Portfolio
Derivative [Line Items]
Fair Value Liability	9,343	0
Posted Collateral	20,903	14,827
Requested Credit for Adequate Assurance | Electric Portfolio
Derivative [Line Items]
Fair Value Liability	6,576	5,253
Posted Collateral	0	0
Contingent Collateral	0	0
Credit Rating
Derivative [Line Items]
Posted Collateral	17,900
Credit Rating | Electric Portfolio
Derivative [Line Items]
Fair Value Liability	26,966	6,110
Posted Collateral	0	0
Contingent Collateral	$ 26,966	$ 6,110

Fair Value Measurements - Debt

Fair Value Measurements - Debt at Carrying and Fair Value (Details) - USD ($)	Dec. 31, 2020	Dec. 31, 2019
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	$ 4,338,044,000	$ 4,336,142,000
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	22,900,000	24,400,000
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	4,338,044,000	4,336,142,000
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	6,086,358,000	5,571,818,000
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	6,086,358,000	5,571,818,000
Parent Company [Member] | 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	52,700,000	51,500,000
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	5,892,440,000	5,920,325,000
Parent Company [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	22,700,000	24,100,000
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	5,667,740,000	5,512,225,000
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure	224,700,000	408,100,000
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	7,980,646,000	7,412,416,000
Parent Company [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	7,755,946,000	7,004,316,000
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure	$ 224,700,000	$ 408,100,000

Fair Value Measurements - Sched

Fair Value Measurements - Schedule of Assets and Liabilities (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	$ 41,820	$ 31,308
Derivative Liability	61,274	26,121
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	41,086	29,134
Derivative Liability	35,687	21,850
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	734	2,174
Derivative Liability	25,587	4,271
Electric Portfolio
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	22,544	19,933
Derivative Liability	46,922	17,504
Electric Portfolio | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	21,947	19,282
Derivative Liability	22,607	13,474
Electric Portfolio | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	597	651
Derivative Liability	24,315	4,030
Natural Gas Portfolio
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	19,276	11,375
Derivative Liability	14,352	8,617
Natural Gas Portfolio | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	19,139	9,852
Derivative Liability	13,080	8,376
Natural Gas Portfolio | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	137	1,523
Derivative Liability	$ 1,272	$ 241

Fair Value Measurements - Unobs

Fair Value Measurements - Unobservable Input Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
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	$ (2,097)	$ 3,035	$ 3,021
Included in earnings	(23,559)	3,558	34,604
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities)	(1,049)	3,151	6,075
Settlements	1,852	(15,973)	(40,264)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3	0	3,992	(1,987)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3	0	140	1,586
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Ending Balance	(24,853)	(2,097)	3,035
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	(3,379)	1,362	1,098
Included in earnings	(23,559)	3,558	34,604
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities)	0	0	0
Settlements	3,220	(11,265)	(33,067)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3	0	4,390	(1,987)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3	0	(1,424)	714
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Ending Balance	(23,718)	(3,379)	1,362
Unrealized gain (loss) on derivative instruments, net	(21,300)	(3,200)	1,100
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	1,282	1,673	1,923
Included in earnings	0	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities)	(1,049)	3,151	6,075
Settlements	(1,368)	(4,708)	(7,197)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3	0	(398)	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3	0	1,564	872
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Ending Balance	$ (1,135)	$ 1,282	$ 1,673

Fair Value Measurements - Forwa

Fair Value Measurements - Forward Price Ranges (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)$ / MWh$ / MMBTU	Dec. 31, 2019USD ($)
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	10.00%
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value	$ 5,500
Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	41,820	$ 31,308
Derivative Liability	61,274	26,121
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	734	2,174
Derivative Liability	25,587	4,271
Natural Gas Portfolio | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	19,276	11,375
Derivative Liability	14,352	8,617
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	137	1,523
Derivative Liability	$ 1,272	241
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	1.89
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	3.42
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	2.47
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	$ 137
Derivative Liability	1,272
Electric Portfolio | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	22,544	19,933
Derivative Liability	46,922	17,504
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	597	651
Derivative Liability	$ 24,315	$ 4,030
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	22.82
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	41.66
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	31.54
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	$ 597
Derivative Liability	$ 24,315

Fair Value Measurements - Valua

Fair Value Measurements - Valuations (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2019
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Impairment of Intangible Assets (Excluding Goodwill)		$ 52,565
Wells Project [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-Lived Intangible Assets, Net	$ 147,168
Impairment of Intangible Assets (Excluding Goodwill)	52,565
Wells Project [Member] | Carrying Amount
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure	$ 94,603

Fair Value Measurements - Uno_2

Fair Value Measurements - Unobservable Input (Details) - Wells Project [Member] - Income Approach Valuation Technique	3 Months Ended
	Mar. 31, 2019USD ($)$ / MWh
Minimum
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Power prices (per MWh) | $ / MWh	10.23
Fair Value Inputs, Power Contract Costs | $	$ 6,308
Maximum
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Power prices (per MWh) | $ / MWh	38.84
Fair Value Inputs, Power Contract Costs | $	$ 7,085
Weighted Average
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Power prices (per MWh) | $ / MWh	24.43
Fair Value Inputs, Power Contract Costs | $	$ 6,468

Employee Investment Plans - Nar

Employee Investment Plans - Narrative (Details) - Subsidiaries [Member] - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Contribution Plan Disclosure [Line Items]
Employer discretionary contribution amount	$ 22,100,000	$ 21,700,000	$ 20,700,000
Employer matching contribution, percent	4.50%
Maximum annual contribution per employee, percent	6.00%
employer contribution [Member]
Defined Contribution Plan Disclosure [Line Items]
Employer matching contribution, percent	4.00%
Collective Bargaining Arrangement Member [Member] | employer contribution [Member]
Defined Contribution Plan Disclosure [Line Items]
Employer matching contribution, percent	4.00%
Cash Balance Formula | Collective Bargaining Arrangement Member [Member]
Defined Contribution Plan Disclosure [Line Items]
Employer matching contribution, percent	100.00%
Maximum annual contribution per employee, percent	6.00%
Employer additional contribution of base pay, percentage	1.00%
Final Average Earnings Formula | Collective Bargaining Arrangement Member [Member]
Defined Contribution Plan Disclosure [Line Items]
Employer matching contribution, percent	55.00%
Maximum annual contribution per employee, percent	6.00%
Second 3 Percent
Defined Contribution Plan Disclosure [Line Items]
Employer matching contribution, percent	50.00%
Maximum annual contribution per employee, percent	3.00%
First 3 Percent
Defined Contribution Plan Disclosure [Line Items]
Employer matching contribution, percent	100.00%
Maximum annual contribution per employee, percent	3.00%

Retirement Benefits - Change in

Retirement Benefits - Change in Net Benefit Obligation and Fair Value (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Other Pension Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	$ 11,627	$ 10,636
Amendments	44	9,049
Service cost	190	61
Interest cost	368	410
Curtailment Loss / (Gain)	0	(7,486)
Actuarial loss (gain)	(604)	287
Benefits paid	906	982
Medicare part D subsidy received	187	226
Administrative expense	0	0
Benefit obligation at end of period	12,114	11,627
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of period	6,289	5,960
Actual return on plan assets	278	1,006
Employer contribution	257	305
Benefits paid	(906)	(982)
Administrative expense	0	0
Fair value of plan assets at end of period	5,918	6,289
Funded status at end of period	(6,196)	(5,338)
Nonqualified Plan | Pension Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	63,000	55,708
Amendments	0	0
Service cost	756	1,023
Interest cost	1,464	2,314
Curtailment Loss / (Gain)	0	0
Actuarial loss (gain)	(3,663)	(6,756)
Benefits paid	22,141	2,801
Medicare part D subsidy received	0	0
Administrative expense	0	0
Benefit obligation at end of period	46,742	63,000
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	22,141	2,801
Benefits paid	(22,141)	(2,801)
Administrative expense	0	0
Fair value of plan assets at end of period	0	0
Funded status at end of period	(46,742)	(63,000)
Qualified Plan | Pension Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	774,305	677,643
Amendments	0	0
Service cost	24,337	22,656
Interest cost	25,180	28,913
Curtailment Loss / (Gain)	0	0
Actuarial loss (gain)	(69,413)	(84,272)
Benefits paid	42,775	36,740
Medicare part D subsidy received	0	0
Administrative expense	(1,077)	(2,439)
Benefit obligation at end of period	849,383	774,305
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of period	753,042	640,242
Actual return on plan assets	107,409	133,939
Employer contribution	18,000	18,000
Benefits paid	(42,775)	(36,740)
Administrative expense	(1,021)	(2,399)
Fair value of plan assets at end of period	834,655	753,042
Funded status at end of period	$ (14,728)	$ (21,263)

Retirement Benefits - Amounts R

Retirement Benefits - Amounts Recognized (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Other Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 12,114	$ 11,627	$ 10,636
Accumulated benefit obligation	12,070	11,604
Fair value of plan assets	5,918	6,289	5,960
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets	0	0
Current liabilities	(293)	(308)
Noncurrent liabilities	(5,903)	(5,030)
Net assets (liabilities)	(6,196)	(5,338)
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	600	(197)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax	44	0
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total	644	(197)
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	489	(364)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax	44	0
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total	533	(364)
Nonqualified Plan | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	46,742	63,000	55,708
Accumulated benefit obligation	44,033	59,988
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	(6,763)	(22,604)
Noncurrent liabilities	(39,979)	(40,396)
Net assets (liabilities)	(46,742)	(63,000)
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	11,738	15,003
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax	927	1,276
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total	12,665	16,279
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	12,504	16,473
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax	927	1,276
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total	13,431	17,749
Qualified Plan | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	849,383	774,305	677,643
Accumulated benefit obligation	837,455	762,838
Fair value of plan assets	834,655	753,042	$ 640,242
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets	0	0
Current liabilities	0	0
Noncurrent liabilities	(14,728)	(21,263)
Net assets (liabilities)	(14,728)	(21,263)
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	98,010	94,319
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax	(1,904)	(3,884)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total	96,106	90,435
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	210,317	217,502
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax	(1,513)	(3,086)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total	$ 208,804	$ 214,416

Retirement Benefits - Net Perio

Retirement Benefits - Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Other Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	$ 190	$ 61
Interest cost	368	410
Parent Company [Member] | Other Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	190	61	$ 69
Interest cost	368	410	444
Expected return on plan assets	(389)	(393)	(472)
Amortization of prior service cost (credit)	0	0	0
Amortization of net loss (gain)	(82)	(374)	(335)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	87	(296)	(294)
Subsidiaries [Member] | Other Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	190	61	69
Interest cost	368	410	444
Expected return on plan assets	(389)	(393)	(472)
Amortization of prior service cost (credit)	0	0	0
Amortization of net loss (gain)	(137)	(562)	(556)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	32	(484)	(515)
Nonqualified Plan | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	756	1,023
Interest cost	1,464	2,314
Nonqualified Plan | Parent Company [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	756	1,023	847
Interest cost	1,464	2,314	2,120
Expected return on plan assets	0	0	0
Amortization of prior service cost (credit)	349	331	1,580
Amortization of net loss (gain)	2,122	1,365	42
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	4,691	5,033	4,589
Nonqualified Plan | Subsidiaries [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	756	1,023	847
Interest cost	1,464	2,314	2,120
Expected return on plan assets	0	0	0
Amortization of prior service cost (credit)	349	333	44
Amortization of net loss (gain)	2,385	1,733	2,069
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	4,954	5,403	5,080
Qualified Plan | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	24,337	22,656
Interest cost	25,180	28,913
Qualified Plan | Parent Company [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	24,337	22,656	22,757
Interest cost	25,180	28,913	27,303
Expected return on plan assets	(49,902)	(50,249)	(50,202)
Amortization of prior service cost (credit)	(1,980)	(1,980)	(1,980)
Amortization of net loss (gain)	8,160	1,151	2,187
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	5,795	491	65
Qualified Plan | Subsidiaries [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	24,337	22,656	22,757
Interest cost	25,180	28,913	27,303
Expected return on plan assets	(49,910)	(50,267)	(50,240)
Amortization of prior service cost (credit)	(1,573)	(1,573)	(1,573)
Amortization of net loss (gain)	19,043	12,877	14,917
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	$ 17,077	$ 12,606	$ 13,164

Retirement Benefits - Benefit O

Retirement Benefits - Benefit Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
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	1.00%
Subsidiaries [Member] | employer contribution [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer matching contribution, percent	4.00%
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	4.00%
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	4.00%
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	4.00%
Other Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss (gain)	$ (715)	$ 900
Amortization of net (loss) gain	82	374
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	0	2,892
Prior service cost (credit)	44	0
Amortization of prior service (cost) credit	0	0
Total change in other comprehensive income for year	841	2,366
Other Pension Plan [Member] | Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss (gain)	(715)	900
Amortization of net (loss) gain	137	562
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	0	3,832
Prior service cost (credit)	44	0
Amortization of prior service (cost) credit	0	0
Total change in other comprehensive income for year	896	3,494
Qualified Plan | Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss (gain)	(11,851)	(541)
Amortization of net (loss) gain	(8,160)	(1,151)
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	(1,980)	(1,980)
Total change in other comprehensive income for year	5,671	1,370
Qualified Plan | Pension Plan [Member] | Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss (gain)	(11,858)	(559)
Amortization of net (loss) gain	(19,043)	(12,877)
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	(1,573)	(1,573)
Total change in other comprehensive income for year	(5,612)	(10,745)
Nonqualified Plan | Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss (gain)	(3,663)	(6,756)
Amortization of net (loss) gain	(2,122)	(1,365)
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	4,806	0
Prior service cost (credit)	0	0
Amortization of prior service (cost) credit	349	331
Total change in other comprehensive income for year	(3,614)	5,060
Nonqualified Plan | Pension Plan [Member] | Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss (gain)	(3,663)	(6,756)
Amortization of net (loss) gain	(2,385)	(1,733)
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	5,248	0
Prior service cost (credit)	0	0
Amortization of prior service (cost) credit	349	333
Total change in other comprehensive income for year	$ (4,319)	$ 4,690

Retirement Benefits - Textuals

Retirement Benefits - Textuals (Details) - Forecast [Member] - Subsidiaries [Member] - Pension Plan [Member] $ in Millions	Dec. 31, 2021USD ($)
Qualified Plan
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Estimated Future Employer Contributions in Current Fiscal Year	$ 18
Nonqualified Plan
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Estimated Future Employer Contributions in Current Fiscal Year	6.8
Other 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, 2020	Dec. 31, 2019	Dec. 31, 2018
Other Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	2.70%	3.35%	4.40%
Rate of compensation increase	4.50%	4.50%	4.50%
Medical trend rate1			7.60%
Benefit Cost Assumptions
Discount rate	3.35%	4.40%	4.40%
Return on plan assets	7.00%	7.00%	7.00%
Rate of compensation increase	4.50%	4.50%	4.50%
Medical trend rate1			7.60%
Nonqualified Plan | Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	2.70%	3.35%	4.40%
Rate of compensation increase	4.50%	4.50%	4.50%
Medical trend rate1	0.00%	0.00%	0.00%
Benefit Cost Assumptions
Discount rate	3.35%	4.40%	4.40%
Return on plan assets	0.00%	0.00%	0.00%
Rate of compensation increase	4.50%	4.50%	4.50%
Medical trend rate1	0.00%	0.00%	0.00%
Qualified Plan | Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	2.70%	3.35%	4.40%
Rate of compensation increase	4.50%	4.50%	4.50%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Weighted-Average Interest Crediting Rate	4.00%	4.00%	4.00%
Medical trend rate1	0.00%	0.00%	0.00%
Benefit Cost Assumptions
Discount rate	3.35%	4.40%	4.40%
Return on plan assets	7.15%	7.50%	7.50%
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	4.00%	4.00%	4.00%
Medical trend rate1	0.00%	0.00%	0.00%

Retirement Benefits - Future Be

Retirement Benefits - Future Benefit Payments (Details) $ in Thousands	Dec. 31, 2020USD ($)
Other Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2020	$ 816
2021	968
2022	936
2023	904
2024	876
2025-2029	3,931
2020, without Medicare Part D subsidy	997
2021, without Medicare Part D subsidy	968
2022, without Medicare Part D subsidy	936
2023, without Medicare Part D subsidy	904
2024, without Medicare Part D subsidy	876
2025-2029, without Medicare Part D subsidy	3,931
Qualified Plan | Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2020	46,500
2021	47,300
2022	48,900
2023	49,900
2024	51,200
2025-2029	261,000
Nonqualified Plan | Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2020	6,763
2021	1,901
2022	3,773
2023	6,552
2024	8,041
2025-2029	$ 16,217

Retirement Benefits - Plan Asse

Retirement Benefits - Plan Asset Allocation (Details)	Dec. 31, 2020
Domestic Large Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	31.00%
Domestic Small Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	9.00%
Foreign Equity Funds [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	25.00%
Fixed Income Securities [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	25.00%
Real Estate Funds [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	0.00%
Absolute Return Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	10.00%
Cash and cash equivalents
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	0.00%
Minimum | Domestic Large Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	25.00%
Minimum | Foreign Equity Funds [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	10.00%
Minimum | Fixed Income Securities [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	15.00%
Minimum | Absolute Return Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	5.00%
Maximum | Domestic Large Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	40.00%
Maximum | Domestic Small Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	15.00%
Maximum | Foreign Equity Funds [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	30.00%
Maximum | Fixed Income Securities [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	30.00%
Maximum | Real Estate Funds [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	10.00%
Maximum | Absolute Return Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	15.00%
Maximum | Cash and cash equivalents
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	5.00%

Retirement Benefits - Recurring

Retirement Benefits - Recurring Fair Value Measures (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Other Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 5,918	$ 6,289	$ 5,960
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	5,916	6,201
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
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	2	88
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	834,655	753,043
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	5,918	6,289
Mutual 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	91,658
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	5,916	6,201
Mutual 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
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	0	0
Mutual 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	0	0
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 | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	91,658
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	5,916	6,201
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	73,006	34,916
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	9,148	0
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	82,154	34,916
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	4,612	0
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	3,223	150
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	7,835	150
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	325,081	350,720
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	22,205	150
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	487,369	402,173
Investments Measured At NAV | 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
Investments Measured At NAV | 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
Investments Measured At NAV | 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	88
Investments Measured At NAV | 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	88
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	(44,981)	505
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	2	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	(44,981)	505
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	2	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	107,137	69,505
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	107,137	69,505
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	342,014	278,379
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	342,014	278,379
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	1,096	0
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	1,096	0
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	82,103	53,784
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	82,103	53,784
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	3,699	0
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	3,699	0
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	6,082	0
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	6,082	0
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	228,247	204,682
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	53	0
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	228,300	204,682
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	19,216	19,464
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	$ 19,216	$ 19,464

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	May 01, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosures [Line Items]
Current Federal Tax Expense (Benefit)		$ 7,962	$ 9,424	$ 10,382
Current State and Local Tax Expense (Benefit)		7	164	263
Deferred Federal Income Tax Expense (Benefit)		(6,414)	7,357	19,451
Deferred State and Local Income Tax Expense (Benefit)		109	128	(4)
Total income tax expense		1,664	17,073	30,092
Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Current Federal Tax Expense (Benefit)		10,607	18,093	19,283
Current State and Local Tax Expense (Benefit)		383	570	438
Deferred Federal Income Tax Expense (Benefit)		15,252	20,485	30,979
Deferred State and Local Income Tax Expense (Benefit)		0	0	0
Total income tax expense	$ 34,600	$ 26,242	$ 39,148	$ 50,700

Income Taxes - Deferred Income

Income Taxes - Deferred Income Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Deferred Tax Liabilities, Gross
Deferred Tax Liabilities, Property, Plant and Equipment	$ 1,923,933	$ 1,943,730
Deferred Tax Liabilities, Other	137,325	133,440
Deferred Tax Liabilities, Gross, Total	2,061,258	2,077,170
Deferred Tax Assets, Gross
Deferred Tax Assets, Operating Loss Carryforwards	(261,260)	(238,869)
Deferred Tax Assets, Net Regulatory Liability for Income Taxes	(953,274)	(946,179)
Deferred Tax Assets, Tax Credit Carryforwards, Production	(35,995)	(67,402)
Deferred Tax Assets, Gross	(1,250,529)	(1,252,450)
Deferred Tax Liabilities, Net, Total	810,729	824,720
Subsidiaries [Member]
Deferred Tax Liabilities, Gross
Deferred Tax Liabilities, Property, Plant and Equipment	1,923,933	1,943,730
Deferred Tax Liabilities, Other	53,431	47,774
Deferred Tax Liabilities, Gross, Total	1,977,364	1,991,504
Deferred Tax Assets, Gross
Deferred Tax Assets, Net Regulatory Liability for Income Taxes	(953,987)	(946,936)
Deferred Tax Assets, Tax Credit Carryforwards, Production	(35,995)	(67,405)
Deferred Tax Assets, Gross	(989,982)	(1,014,341)
Deferred Tax Liabilities, Net, Total	$ 987,382	$ 977,163

Income Taxes - Balance Sheet Lo

Income Taxes - Balance Sheet Location (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosures [Line Items]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	$ (3,038)	$ 0	$ 0
Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	(3,038)	0	$ 0
ARAM [Member]
Income Tax Disclosures [Line Items]
Deferred Other Tax Expense (Benefit)	$ 27,600	$ 27,600

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	May 01, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating Loss Carryforwards [Line Items]
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount		$ 38,720	$ 47,834	$ 55,800
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depreciation and Amortization, Amount		(22,991)	(23,025)	(25,871)
Income Tax Reconciliation, AFUDC (net)		(6,095)	(4,462)	(4,173)
Income Tax Reconciliation, Executive Compensation		2,440	2,596	4,439
Income Tax Reconciliation, Treasury Grant		(8,935)	(7,870)	(4,861)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		(3,038)	0	0
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount		1,563	2,000	4,758
Total income tax expense		$ 1,664	$ 17,073	$ 30,092
Effective Income Tax Rate Reconciliation, Percent		0.90%	7500.00%	11300.00%
Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount		$ 63,110	$ 69,735	$ 77,251
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depreciation and Amortization, Amount		(22,991)	(23,025)	(25,871)
Income Tax Reconciliation, AFUDC (net)		(6,095)	(4,462)	(4,173)
Income Tax Reconciliation, Executive Compensation		2,440	2,596	4,439
Income Tax Reconciliation, Treasury Grant		(8,935)	(7,870)	(4,861)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		(3,038)	0	0
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount		1,751	2,174	3,915
Total income tax expense	$ 34,600	$ 26,242	$ 39,148	$ 50,700
Effective Income Tax Rate Reconciliation, Percent		8.70%	11800.00%	13800.00%

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$ 25.6
ARAM [Member]
Operating Loss Carryforwards [Line Items]
Deferred Other Tax Expense (Benefit)	$ 27.6	$ 27.6

Litigation (Details)

Litigation (Details)	12 Months Ended
	Dec. 31, 2020unit	Dec. 10, 2019USD ($)MW
Jointly Owned Utility Plant Interests
Clean Air Rule, Emissions Cap, Percentage	(5.00%)
Clean Air Rule, Emissions Cap, Years	3 years
Subsidiaries [Member] | Colstrip Unit 4 [Member]
Jointly Owned Utility Plant Interests
Company’s Ownership Share	25.00%
Colstrip 4 Sale Amount | $		$ 1
Colstrip PPA | MW		90
Subsidiaries [Member] | Colstrip Units 1 & 2
Jointly Owned Utility Plant Interests
Company’s Ownership Share	50.00%
Number of Units | unit	2

Commitments and Contingencies_2

Commitments and Contingencies (Details)	1 Months Ended	12 Months Ended
	Nov. 30, 2022	Dec. 31, 2020USD ($)MWhContractsMW	May 01, 2020	Dec. 31, 2019USD ($)MWh	Dec. 31, 2018USD ($)MWh	Feb. 01, 2021USD ($)
Long-term Purchase Commitment [Line Items]
Long-term Line of Credit, Noncurrent		$ 14,700,000		$ 24,100,000
Average cost of Company's energy output (US$ per kWh)		$ 0.031
Number of Public Utility Districts with long term purchase agreements | Contracts		3
Contract expenses		$ 116,874,000		$ 87,135,000	$ 80,165,000
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased		15.30%
Long-term Contract for Purchase of Electric Power, Capacity | MW		697
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost		$ 105,759,000
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required		17,378,000
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges		8,103,000
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding		141,672,000
Payment Obligations for Power Purchases
2021		534,813,000
2022		455,525,000
2023		460,881,000
2024		468,141,000
2025		388,259,000
Thereafter		1,855,123,000
Total		$ 4,162,742,000
Total energy obtained during period under purchased power contracts (MWh) | MWh		13.2		12.5	14.1
Cost incurred during period to provide energy under purchased power contracts		$ 491,700,000		$ 550,600,000	$ 508,200,000
Daily take obligation under long-term service contract (percent)		100.00%
Daily delivery obligation under long-term service contract (percent)		100.00%
Natural Gas [Member]
Payment Obligations for Power Purchases
2021		$ 327,775,000
2022		210,736,000
2023		155,778,000
2024		116,016,000
2025		59,483,000
Thereafter		0
Total		869,788,000
Colombia River Projects [Member]
Payment Obligations for Power Purchases
2021		117,664,000
2022		101,421,000
2023		100,222,000
2024		99,473,000
2025		99,393,000
Thereafter		499,808,000
Non-Utility Generators [Member]
Payment Obligations for Power Purchases
Total		185,568,000
Firm Transportation Service [Member]
Payment Obligations for Power Purchases
2021		174,912,000
2022		172,431,000
2023		163,662,000
2024		129,503,000
2025		113,051,000
Thereafter		804,103,000
Total		1,557,662,000
Firm Storage and Peaking Service [Member]
Payment Obligations for Power Purchases
2021		8,899,000
2022		8,899,000
2023		2,270,000
2024		67,000
2025		67,000
Thereafter		56,000
Total		20,258,000
Long-term Purchase Commitment, Demand Charges		135,800,000
Combustion turbines
Payment Obligations for Power Purchases
Long-term Purchase Commitment, Demand Charges		51,200,000
Energy production service contracts
Payment Obligations for Power Purchases
2021		29,710,000
2022		30,423,000
2023		31,155,000
2024		31,921,000
2025		32,177,000
Thereafter		105,579,000
Total		260,965,000
Automated meter reading system
Payment Obligations for Power Purchases
2021		45,489,000
2022		46,436,000
2023		47,498,000
2024		47,505,000
2025		48,229,000
Thereafter		49,077,000
Total		284,234,000
Service contract obligations
Payment Obligations for Power Purchases
2021		75,199,000
2022		76,859,000
2023		78,653,000
2024		79,426,000
2025		80,406,000
Thereafter		154,656,000
Total		545,199,000
Colombia River Projects [Member]
Payment Obligations for Power Purchases
Total		1,017,981,000
Other Utilities [Member]
Payment Obligations for Power Purchases
Total		2,959,193,000
Electric Portfolio
Payment Obligations for Power Purchases
2021		299,705,000
2022		332,444,000
2023		349,119,000
2024		356,976,000
2025		277,250,000
Thereafter		1,343,699,000
Firm natural gas supply
Payment Obligations for Power Purchases
2021		511,586,000
2022		392,066,000
2023		321,710,000
2024		245,586,000
2025		172,601,000
Thereafter		804,159,000
Total		$ 2,447,708,000
Minimum | Combustion turbines
Payment Obligations for Power Purchases
Remaining terms under contract		1
Maximum | Combustion turbines
Payment Obligations for Power Purchases
Remaining terms under contract		24
Rock Island Project
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased		25.00%
Long-term Contract for Purchase of Electric Power, Capacity | MW		156
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost		$ 34,895,000
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required		11,314,000
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges		5,365,000
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding		$ 91,674,000
Rocky Reach Project
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased		25.00%
Long-term Contract for Purchase of Electric Power, Capacity | MW		325
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost		$ 30,400,000
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required		4,518,000
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges		1,960,000
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding		$ 30,476,000
Wells Project [Member]
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased		24.20%
Long-term Contract for Purchase of Electric Power, Capacity | MW		203
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost		$ 37,584,000
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		0.60%
Long-term Contract for Purchase of Electric Power, Capacity | MW		6
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost		$ 1,440,000
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required		773,000
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges		389,000
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding		$ 9,761,000
Wanapum Development
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased		0.60%
Long-term Contract for Purchase of Electric Power, Capacity | MW		7
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost		$ 1,440,000
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required		773,000
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges		389,000
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding		9,761,000
Electricity, US Regulated [Member]
Payment Obligations for Power Purchases
2021		117,444,000
2022		21,660,000
2023		11,540,000
2024		11,692,000
2025		11,616,000
Thereafter		$ 11,616,000
Subsidiaries [Member] | Forecast [Member]
Payment Obligations for Power Purchases
Fiscal Period Duration	20 years
Subsidiaries [Member] | Electricity [Member] | Subsequent Event [Member]
Payment Obligations for Power Purchases
2021						$ 2,430,000
2022						34,541,000
2023						34,541,000
2024						34,541,000
2025						34,541,000
Thereafter						550,228,000
Total						$ 690,822,000
Subsidiaries [Member] | Expedited Rate Filing (ERF) [Member]
Payment Obligations for Power Purchases
Fiscal Period Duration			1 year

Segment Information (Details)

Segment Information (Details)	12 Months Ended
	Dec. 31, 2020mi²segment
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, 2020	Dec. 31, 2019	Dec. 31, 2018
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	$ (84,149)
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	0	$ 0	$ 5,230
Accumulated other comprehensive income (loss), net of tax	(86,437)	(84,149)
Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(188,477)
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	0	0	(27,333)
Accumulated other comprehensive income (loss), net of tax	(180,956)	(188,477)
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	(84,149)	(77,202)	(24,282)
Other comprehensive income (loss) before reclassifications	(9,058)	(7,337)	(48,870)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	6,770	390	1,180
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings			(5,230)
Net current-period other comprehensive income (loss)	(2,288)	(6,947)	(52,920)
Accumulated other comprehensive income (loss), net of tax	(86,437)	(84,149)	(77,202)
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	(183,108)	(185,130)	(121,867)
Other comprehensive income (loss) before reclassifications	(8,717)	(8,096)	(48,802)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	15,853	10,118	11,772
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings			(26,233)
Net current-period other comprehensive income (loss)	7,136	2,022	(63,263)
Accumulated other comprehensive income (loss), net of tax	(175,972)	(183,108)	(185,130)
Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(84,149)	(77,202)	(24,282)
Other comprehensive income (loss) before reclassifications	(9,058)	(7,337)	(48,870)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	6,770	390	1,180
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings			(5,230)
Net current-period other comprehensive income (loss)	(2,288)	(6,947)	(52,920)
Accumulated other comprehensive income (loss), net of tax	(86,437)	(84,149)	(77,202)
Comprehensive Income [Member] | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(188,477)	(190,884)	(126,906)
Other comprehensive income (loss) before reclassifications	(8,717)	(8,096)	(48,802)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	16,238	10,503	12,157
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings			(27,333)
Net current-period other comprehensive income (loss)	7,521	2,407	(63,978)
Accumulated other comprehensive income (loss), net of tax	(180,956)	(188,477)	(190,884)
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	(5,369)	(5,754)	(5,039)
Other comprehensive income (loss) before reclassifications		0	0
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	385	385	385
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings			(1,100)
Net current-period other comprehensive income (loss)	385	385	(715)
Accumulated other comprehensive income (loss), net of tax	$ (4,984)	$ (5,369)	$ (5,754)

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Reclassification out of Accumulated Other Comprehensive Income | Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Comprehensive income (loss)	$ (6,770)	$ (390)	$ (1,180)
Reclassification out of Accumulated Other Comprehensive Income | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Comprehensive income (loss)	(16,238)	(10,503)	(12,157)
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	1,631	1,648	1,937
Amortization of net (loss) gain	(10,200)	(2,142)	(3,431)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax	(8,569)	(494)	(1,494)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax	1,799	104	314
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, after Tax	(6,770)	(390)	(1,180)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Noncontrolling Interest [Member] | Interest Rate Swap [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax	(487)	(487)	(487)
Reclassification of net unrealized loss on energy derivative instruments during the period, tax	102	102	102
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	(385)	(385)	(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	1,224	1,240	1,529
Amortization of net (loss) gain	(21,291)	(14,048)	(16,430)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax	(20,067)	(12,808)	(14,901)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax	4,214	2,690	3,129
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, after Tax	$ (15,853)	$ (10,118)	$ (11,772)

SUPPLEMENTAL QUARTERLY FINANC_3

SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Quarterly Financial Information [Line Items]
Operating revenue									$ 3,326,450,000	$ 3,401,130,000	$ 3,346,496,000
Operating Income (Loss)									507,824,000	519,008,000	554,058,000
Net Income (Loss) Attributable to Parent									182,717,000	210,708,000	235,622,000
Parent Company [Member]
Quarterly Financial Information [Line Items]
Operating revenue	$ 1,008,215,000	$ 620,426,000	$ 651,679,000	$ 1,046,130,000	$ 988,354,000	$ 627,007,000	$ 670,930,000	$ 1,114,839,000
Operating Income (Loss)	181,782,000	83,308,000	70,350,000	172,384,000	240,307,000	26,126,000	39,115,000	213,460,000
Net Income (Loss) Attributable to Parent	101,018,000	9,996,000	(23,233,000)	94,936,000	150,949,000	(39,443,000)	(32,952,000)	132,154,000	182,717,000	210,708,000	235,622,000
Subsidiaries [Member]
Quarterly Financial Information [Line Items]
Operating revenue	1,008,215,000	620,426,000	651,679,000	1,046,130,000	988,354,000	627,007,000	670,930,000	1,114,839,000	3,326,450,000	3,401,130,000	3,346,496,000
Operating Income (Loss)	181,152,000	84,192,000	71,192,000	172,656,000	241,955,000	26,721,000	39,780,000	214,159,000	509,192,000	522,615,000	557,136,000
Net Income (Loss) Attributable to Parent	$ 114,860,000	$ 33,062,000	$ 15,037,000	$ 111,321,000	$ 169,204,000	$ (15,257,000)	$ (8,325,000)	$ 147,302,000	$ 274,280,000	$ 292,924,000	$ 317,162,000

SCHEDULE I CONDENSED FINANCIA_2

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Statements of Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Financial Statements, Captions [Line Items]
Nonutility Expense And Other									$ (43,425)	$ (47,907)	$ (54,519)
Interest expense									(373,822)	(356,638)	(343,795)
Income Tax Expense (Benefit)									(1,664)	(17,073)	(30,092)
Net income (loss)									182,717	210,708	235,622
Comprehensive income (loss)									180,429	203,761	182,702
Condensed Cash Flow Statements, Captions [Line Items]
Net Cash Provided by (Used in) Operating Activities									727,568	527,336	904,181
Payments for (Proceeds from) Other Investing Activities									(5,340)	(6,908)	(2,097)
Net Cash Provided by (Used in) Investing Activities									(902,796)	(952,479)	(1,070,573)
Payments of Dividends									45,421	64,220	77,204
Proceeds from Contributions from Parent									4,575	0	0
Proceeds from Issuance of Long-term Debt									644,690	689,351	804,050
Repayments of Long-term Debt									450,000	0	600,000
Net Cash Provided by (Used in) Financing Activities									190,933	435,727	185,193
Net increase (decrease) in cash, cash equivalents, and restricted cash									15,705	10,584	18,801
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 81,851				$ 66,146				81,851	66,146	55,562	$ 36,761
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Nonutility Expense And Other									(1,579)	(1,495)	(1,345)
Equity In Net Income (Loss) Of Subsidiaries									277,654	294,724	320,122
Investment Income, Interest									4,760	6,643	4,273
Interest expense									(123,592)	(111,716)	(108,816)
Income Tax Expense (Benefit)									25,474	22,552	21,388
Net income (loss)	101,018	$ 9,996	$ (23,233)	$ 94,936	150,949	$ (39,443)	$ (32,952)	$ 132,154	182,717	210,708	235,622
Comprehensive income (loss)									180,429	203,761	182,702
Condensed Cash Flow Statements, Captions [Line Items]
Net Cash Provided by (Used in) Operating Activities									38,280	68,724	79,176
Adjustments to Additional Paid in Capital, Other									0	210,000	0
Payments for (Proceeds from) Loans Receivable from Subsidiary									31,043	41,708	59,864
Net Cash Provided by (Used in) Investing Activities									(31,043)	(251,708)	(59,864)
Payments of Dividends									45,421	64,220	77,204
Proceeds from Contributions from Parent									(4,575)	0	0
Proceeds from Issuance of Long-term Debt									644,690	246,200	209,300
Repayments of Long-term Debt									609,400	0	150,000
Issue costs and others									1,838	116	92
Net Cash Provided by (Used in) Financing Activities									(7,394)	181,864	(17,996)
Net increase (decrease) in cash, cash equivalents, and restricted cash									(157)	(1,120)	1,316
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 790				$ 947				$ 790	$ 947	$ 2,067	$ 751

SCHEDULE I CONDENSED FINANCIA_3

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Other Property And Investments [Abstract]
Goodwill	$ 1,656,513	$ 1,656,513
Current assets:
Cash and Cash Equivalents, at Carrying Value	52,307	45,259
Total current assets	916,617	835,119
Assets, Noncurrent [Abstract]
Other	80,751	92,980
Total assets	15,042,965	14,659,863
Capitalization, Long-term Debt and Equity [Abstract]
Stockholders' Equity Attributable to Parent	4,139,882	4,000,299	$ 3,860,758	$ 3,750,030
Long-term debt	1,724,700	1,758,100
Total capitalization	10,032,322	9,920,624
Current liabilities:
Accounts payable	342,404	325,913
Current maturities of long-term debt	526,412	452,412
Interest	73,647	74,855
Unrealized loss on derivative instruments	31,441	13,428
Total current liabilities	1,595,614	1,318,767
Liabilities, Noncurrent [Abstract]
Unrealized loss on derivative instruments	29,833	12,693
Total capitalization and liabilities	15,042,965	14,659,863
Parent Company [Member]
Assets
Investments in subsidiaries	4,279,501	4,153,618
Other Property And Investments [Abstract]
Goodwill	1,656,513	1,656,513
Current assets:
Cash and Cash Equivalents, at Carrying Value	790	947
Receivables from affiliates	211,411	180,527
Total current assets	212,201	181,474
Assets, Noncurrent [Abstract]
Deferred Tax Assets, Net of Valuation Allowance, Noncurrent	258,033	235,428
Other	1,520	2,056
Assets, Noncurrent, Total	259,553	237,484
Total assets	6,407,768	6,229,089
Capitalization, Long-term Debt and Equity [Abstract]
Stockholders' Equity Attributable to Parent	4,139,882	4,000,299
Long-term debt	1,714,744	1,752,644
Total capitalization	5,854,626	5,752,943
Current liabilities:
Accounts payable	3,683	208
Current maturities of long-term debt	524,000	450,000
Interest	25,459	25,938
Total current liabilities	553,142	476,146
Liabilities, Noncurrent [Abstract]
Total capitalization and liabilities	$ 6,407,768	$ 6,229,089

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, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net Cash Provided by (Used in) Operating Activities	$ 727,568	$ 527,336	$ 904,181
Net Cash Provided by (Used in) Investing Activities
Payments for (Proceeds from) Other Investing Activities	(5,340)	(6,908)	(2,097)
Net Cash Provided by (Used in) Investing Activities	(902,796)	(952,479)	(1,070,573)
Net Cash Provided by (Used in) Financing Activities
Payments of Dividends	45,421	64,220	77,204
Proceeds from Issuance of Long-term Debt	644,690	689,351	804,050
Repayments of Long-term Debt	450,000	0	600,000
Net Cash Provided by (Used in) Financing Activities	190,933	435,727	185,193
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect	15,705	10,584	18,801
Cash, cash equivalents, and restricted cash at end of period	52,307	45,259
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	81,851	66,146	55,562	$ 36,761
Parent Company [Member]
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net Cash Provided by (Used in) Operating Activities	38,280	68,724	79,176
Net Cash Provided by (Used in) Investing Activities
Adjustments to Additional Paid in Capital, Other	0	(210,000)	0
Net Cash Provided by (Used in) Investing Activities	(31,043)	(251,708)	(59,864)
Net Cash Provided by (Used in) Financing Activities
Payments of Dividends	45,421	64,220	77,204
Proceeds from Issuance of Long-term Debt	644,690	246,200	209,300
Repayments of Long-term Debt	609,400	0	150,000
Net Cash Provided by (Used in) Financing Activities	(7,394)	181,864	(17,996)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect	(157)	(1,120)	1,316
Cash, cash equivalents, and restricted cash at end of period	790	947
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 790	$ 947	$ 2,067	$ 751

SCHEDULE I CONDENSED FINANCIA_5

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY Notes (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Net Income (Loss) Attributable to Parent									$ 182,717,000	$ 210,708,000	$ 235,622,000
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									180,429,000	203,761,000	182,702,000
Net Cash Provided by (Used in) Operating Activities									727,568,000	527,336,000	904,181,000
Net Cash Provided by (Used in) Investing Activities									(902,796,000)	(952,479,000)	(1,070,573,000)
Business Combination Adjustment, ASC 805									3,400,000	2,900,000	4,700,000
Parent Company [Member]
Net Income (Loss) Attributable to Parent	$ 101,018,000	$ 9,996,000	$ (23,233,000)	$ 94,936,000	$ 150,949,000	$ (39,443,000)	$ (32,952,000)	$ 132,154,000	182,717,000	210,708,000	235,622,000
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									180,429,000	203,761,000	182,702,000
Net Cash Provided by (Used in) Operating Activities									38,280,000	68,724,000	79,176,000
Net Cash Provided by (Used in) Investing Activities									(31,043,000)	(251,708,000)	(59,864,000)
Subsidiaries [Member]
Net Income (Loss) Attributable to Parent	$ 114,860,000	$ 33,062,000	$ 15,037,000	$ 111,321,000	$ 169,204,000	$ (15,257,000)	$ (8,325,000)	$ 147,302,000	274,280,000	292,924,000	317,162,000
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									281,801,000	295,331,000	253,184,000
Net Cash Provided by (Used in) Operating Activities									824,810,000	623,924,000	995,904,000
Net Cash Provided by (Used in) Investing Activities									$ (871,097,000)	$ (912,363,000)	$ (1,008,409,000)

SCHEDULE II VALUATION AND QUALI

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, 2020	Dec. 31, 2019	Dec. 31, 2018
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount, Beginning Balance	$ 8,294	$ 8,408	$ 8,901
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Cost and Expense	23,292	17,633	24,846
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	11,506	17,747	25,339
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount, Ending Balance	$ 20,080	$ 8,294	$ 8,408