Puget Energy (PSD) 10-K 25 Feb 22 2021 FY Annual report Financial data

Cover

Cover - USD ($)	12 Months Ended
	Dec. 31, 2021	Jun. 30, 2021
Document Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	1-16305
Entity Registrant Name	PUGET ENERGY INC /WA
Entity Incorporation, State or Country Code	WA
Entity Address, Address Line One	355 110th Ave NE
Entity Address, City or Town	Bellevue
Entity Address, State or Province	WA
Entity Address, Postal Zip Code	98004
City Area Code	(425)
Local Phone Number	454-6363
Entity Tax Identification Number	91-1969407
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Central Index Key	0001085392
Entity Public Float		$ 0
Entity Common Stock, Shares Outstanding	200
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
Amendment Flag	false
Subsidiaries [Member]
Document Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	1-4393
Entity Registrant Name	PUGET SOUND ENERGY, INC.
Entity Incorporation, State or Country Code	WA
Entity Address, Address Line One	355 110th Ave NE
Entity Address, City or Town	Bellevue
Entity Address, State or Province	WA
Entity Address, Postal Zip Code	98004
City Area Code	(425)
Local Phone Number	454-6363
Entity Tax Identification Number	91-0374630
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Central Index Key	0000081100
Entity Public Float		$ 0
Entity Common Stock, Shares Outstanding	85,903,791
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
Amendment Flag	false

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2021
Auditor [Line Items]
Auditor Location	Portland, Oregon
Auditor Name	PricewaterhouseCoopers LLP
Auditor Firm ID	238
Subsidiaries [Member]
Auditor [Line Items]
Auditor Location	Portland, Oregon
Auditor Name	PricewaterhouseCoopers LLP
Auditor Firm ID	238

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Electric	$ 2,671,623	$ 2,319,416	$ 2,497,041
Natural gas	1,067,418	980,913	875,371
Other	66,620	26,121	28,718
Total operating revenue	3,805,661	3,326,450	3,401,130
Purchased electricity	784,565	593,719	652,560
Electric generation fuel	282,254	199,107	282,864
Residential exchange	(82,225)	(80,294)	(79,187)
Purchased natural gas	398,553	362,872	290,976
Unrealized (gain) loss on derivative instruments, net	(13,785)	26,807	3,574
Utility operations and maintenance	629,864	597,048	596,676
Non-utility expense and other	58,281	43,425	47,907
Depreciation and amortization	704,783	647,755	656,323
Conservation amortization	103,147	99,585	96,571
Taxes other than income taxes	362,527	328,602	333,858
Total operating expenses	3,227,964	2,818,626	2,882,122
Operating income (loss)	577,697	507,824	519,008
Other income	57,483	58,759	59,905
Other Nonoperating Expense	(14,467)	(23,207)	(9,053)
AFUDC	16,743	14,827	14,559
Interest expense	(352,092)	(373,822)	(356,638)
Income (loss) before income taxes	285,364	184,381	227,781
Income tax (benefit) expense	24,515	1,664	17,073
Net income (loss)	260,849	182,717	210,708
Subsidiaries [Member]
Electric	2,671,623	2,319,416	2,497,041
Natural gas	1,067,418	980,913	875,371
Other	66,620	26,121	28,718
Total operating revenue	3,805,661	3,326,450	3,401,130
Purchased electricity	784,565	593,719	652,560
Electric generation fuel	282,254	199,107	282,864
Residential exchange	(82,225)	(80,294)	(79,187)
Purchased natural gas	398,553	362,872	290,976
Unrealized (gain) loss on derivative instruments, net	(13,785)	26,807	3,574
Utility operations and maintenance	629,864	597,048	596,676
Non-utility expense and other	56,242	42,266	44,403
Depreciation and amortization	704,372	647,546	656,220
Conservation amortization	103,147	99,585	96,571
Taxes other than income taxes	362,527	328,602	333,858
Total operating expenses	3,225,514	2,817,258	2,878,515
Operating income (loss)	580,147	509,192	522,615
Other income	46,523	46,923	47,766
Other Nonoperating Expense	(14,467)	(23,207)	(9,053)
AFUDC	16,743	14,827	14,559
Interest expense	(248,624)	(247,213)	(243,815)
Income (loss) before income taxes	380,322	300,522	332,072
Income tax (benefit) expense	44,259	26,242	39,148
Net income (loss)	$ 336,063	$ 274,280	$ 292,924

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Net Income (Loss) Attributable to Parent	$ 260,849	$ 182,717	$ 210,708
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	59,005	(2,288)	(6,947)
Other comprehensive income (loss)	59,005	(2,288)	(6,947)
Comprehensive income (loss)	319,854	180,429	203,761
Subsidiaries [Member]
Net Income (Loss) Attributable to Parent	336,063	274,280	292,924
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	67,431	7,136	2,022
Amortization of treasury interest rate swaps to earnings, net of tax	384	385	385
Other comprehensive income (loss)	67,815	7,521	2,407
Comprehensive income (loss)	$ 403,878	$ 281,801	$ 295,331

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Net unrealized gain (loss) from pension and postretirement plans, tax	$ 15,686	$ (609)	$ (1,846)
Subsidiaries [Member]
Net unrealized gain (loss) from pension and postretirement plans, tax	17,925	1,897	539
Amortization of Financing Cash Flow Hedge Contracts to Earnings Tax	$ 103	$ 102	$ 102

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Utility Plant [Abstract]
Electric plant	$ 9,729,643	$ 9,200,231
Natural gas plant	4,498,198	4,227,532
Common plant	1,155,567	1,116,524
Less: accumulated provision for depreciation	(4,031,458)	(3,671,094)
Net utility plant	11,351,950	10,873,193
Other property and investments:
Goodwill	1,656,513	1,656,513
Other property and investments	324,897	324,184
Total other property and investments	1,981,410	1,980,697
Current assets:
Cash and cash equivalents	56,946	52,307
Restricted cash	46,204	29,544
Accounts receivable, net of allowance for doubtful accounts	398,895	352,132
Unbilled revenue	271,606	221,871
Materials and supplies, at average cost	113,287	118,333
Fuel and natural gas inventory, at average cost	59,393	48,795
Unrealized gain on derivative instruments	128,210	33,015
Prepaid expenses and other	46,293	45,746
Power contract acquisition adjustment gain	17,274	14,874
Total current assets	1,138,108	916,617
Other long-term and regulatory assets:
Power cost adjustment mechanism	79,546	82,801
purchase gas adjustment, long-term	57,935	87,655
Regulatory assets related to power contracts	9,689	11,728
Other regulatory assets	815,058	747,651
Unrealized gain on derivative instruments	26,197	8,805
Operating lease right-of-use asset	184,957	172,167
Power contract acquisition adjustment gain	63,660	80,900
Other	163,374	80,751
Total other long-term and regulatory assets	1,400,416	1,272,458
Total assets	15,871,884	15,042,965
Common shareholder’s equity:
Common stock	0	0
Additional paid-in capital	3,523,532	3,313,532
Retained earnings	1,067,216	912,787
Accumulated other comprehensive income (loss), net of tax	(27,432)	(86,437)
Total common shareholder’s equity	4,563,316	4,139,882
Long-term debt:
First mortgage bonds and senior notes	4,662,000	4,212,000
Pollution control bonds	161,860	161,860
Long-term debt	1,583,300	1,724,700
Debt discount, issuance costs and other	(203,394)	(206,120)
Total long-term debt	6,203,766	5,892,440
Total capitalization	10,767,082	10,032,322
Current liabilities:
Accounts payable	444,384	342,404
Short-term debt	140,000	373,800
Current maturities of long-term debt	450,000	526,412
Accrued expenses:
Taxes	127,398	110,752
Salaries and wages	47,936	42,530
Interest	67,807	73,647
Unrealized loss on derivative instruments	63,309	31,441
Power contract acquisition adjustment loss	1,785	2,039
Operating lease liabilities	20,398	19,204
Other	62,406	73,385
Total current liabilities	1,425,423	1,595,614
Other Long-term and regulatory liabilities:
Deferred income taxes	912,484	810,729
Unrealized loss on derivative instruments	40,965	29,833
Regulatory liabilities	844,184	732,498
Regulatory liability for deferred income taxes	865,976	953,274
Regulatory liabilities related to power contracts	80,934	95,774
Power contract acquisition adjustment loss	7,904	9,689
Operating lease liabilities	172,510	160,980
Finance Lease, Liability, Noncurrent	105,303	320
Other deferred credits	649,119	621,932
Total long-term and regulatory liabilities	3,679,379	3,415,029
Commitments and contingencies (Note 16)
Total capitalization and liabilities	$ 15,871,884	$ 15,042,965
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	$ 11,535,976	$ 11,035,402
Natural gas plant	5,054,622	4,786,419
Common plant	1,177,598	1,139,120
Less: accumulated provision for depreciation	(6,416,246)	(6,087,748)
Net utility plant	11,351,950	10,873,193
Other property and investments:
Other property and investments	74,602	83,855
Total other property and investments	74,602	83,855
Current assets:
Cash and cash equivalents	50,043	51,177
Restricted cash	46,204	29,544
Accounts receivable, net of allowance for doubtful accounts	402,602	355,850
Unbilled revenue	271,606	221,871
Materials and supplies, at average cost	113,287	118,333
Fuel and natural gas inventory, at average cost	58,129	47,531
Unrealized gain on derivative instruments	128,210	33,015
Prepaid expenses and other	46,293	45,746
Total current assets	1,116,374	903,067
Other long-term and regulatory assets:
Power cost adjustment mechanism	79,546	82,801
purchase gas adjustment, long-term	57,935	87,655
Other regulatory assets	815,058	747,651
Unrealized gain on derivative instruments	26,197	8,805
Operating lease right-of-use asset	184,957	172,167
Other	162,391	79,231
Total other long-term and regulatory assets	1,326,084	1,178,310
Total assets	13,869,010	13,038,425
Common shareholder’s equity:
Common stock	859	859
Additional paid-in capital	3,485,105	3,485,105
Retained earnings	982,607	876,401
Accumulated other comprehensive income (loss), net of tax	(113,141)	(180,956)
Total common shareholder’s equity	4,355,430	4,181,409
Long-term debt:
First mortgage bonds and senior notes	4,662,000	4,212,000
Pollution control bonds	161,860	161,860
Debt discount, issuance costs and other	(39,141)	(35,816)
Total long-term debt	4,784,719	4,338,044
Total capitalization	9,140,149	8,519,453
Current liabilities:
Accounts payable	451,716	342,504
Short-term debt	140,000	373,800
Current maturities of long-term debt	0	2,412
Accrued expenses:
Taxes	133,406	107,254
Salaries and wages	47,936	42,530
Interest	51,832	48,189
Unrealized loss on derivative instruments	63,309	31,441
Operating lease liabilities	20,398	19,204
Other	62,406	73,385
Total current liabilities	971,003	1,040,719
Other Long-term and regulatory liabilities:
Deferred income taxes	1,084,203	987,382
Unrealized loss on derivative instruments	40,965	29,833
Regulatory liabilities	842,920	731,234
Regulatory liability for deferred income taxes	866,541	953,987
Operating lease liabilities	172,510	160,980
Finance Lease, Liability, Noncurrent	105,303	320
Other deferred credits	645,416	614,517
Total long-term and regulatory liabilities	3,757,858	3,478,253
Commitments and contingencies (Note 16)
Total capitalization and liabilities	$ 13,869,010	$ 13,038,425
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, 2021	Dec. 31, 2020
Assets
Construction work in progress	$ 870,204	$ 712,204
Current assets:
Allowance for doubtful accounts	$ 34,958	$ 20,080
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	$ 870,204	$ 712,204
Current assets:
Allowance for doubtful accounts	$ (34,958)	$ (20,080)
Common shareholder’s equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	150,000,000	150,000,000
Common stock, shares outstanding (in shares)	85,903,791	85,903,791

CONSOLIDATED STATEMENTS OF COMM

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Subsidiaries [Member]	Subsidiaries [Member]Common Stock	Subsidiaries [Member]Additional Paid-in Capital	Subsidiaries [Member]Retained Earnings	Subsidiaries [Member]Accumulated Other Comprehensive Income (Loss)
Balance at Dec. 31, 2018	$ 3,860,758		$ 3,308,957	$ 629,003	$ (77,202)	$ 3,707,924	$ 859	$ 3,275,105	$ 622,844	$ (190,884)
Balance (in shares) at Dec. 31, 2018		200					85,903,791
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	210,708			210,708		292,924			292,924
Dividends, Common Stock	(64,220)			(64,220)		(164,575)			(164,575)
Other comprehensive income (loss)	(6,947)				(6,947)	2,407				2,407
Proceeds from Contributions from Parent	0					210,000		210,000
Balance at Dec. 31, 2019	4,000,299		3,308,957	775,491	(84,149)	4,048,680	$ 859	3,485,105	751,193	(188,477)
Balance (in shares) at Dec. 31, 2019		200					85,903,791
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	182,717			182,717		274,280			274,280
Dividends, Common Stock	(45,421)			(45,421)		(149,072)			(149,072)
Other comprehensive income (loss)	(2,288)				(2,288)	7,521				7,521
Proceeds from Contributions from Parent	4,575		4,575			0
Balance at Dec. 31, 2020	$ 4,139,882		3,313,532	912,787	(86,437)	$ 4,181,409	$ 859	3,485,105	876,401	(180,956)
Balance (in shares) at Dec. 31, 2020	200	200				85,903,791	85,903,791
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 260,849			260,849		$ 336,063			336,063
Dividends, Common Stock	(106,420)			(106,420)		(229,857)			(229,857)
Other comprehensive income (loss)	59,005				59,005	67,815				67,815
Proceeds from Contributions from Parent	210,000		210,000			0
Balance at Dec. 31, 2021	$ 4,563,316		$ 3,523,532	$ 1,067,216	$ (27,432)	$ 4,355,430	$ 859	$ 3,485,105	$ 982,607	$ (113,141)
Balance (in shares) at Dec. 31, 2021	200	200				85,903,791	85,903,791

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net Income (Loss) Attributable to Parent	$ 260,849	$ 182,717	$ 210,708
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	704,783	647,755	656,323
Conservation amortization	103,147	99,585	96,571
Deferred Income Taxes and Tax Credits	(1,228)	(6,287)	7,475
Unrealized Gain (Loss) on Derivatives	(13,785)	26,807	3,574
Gain (Loss) on Extinguishment of Debt	0	13,546	0
Afudc Equity	(27,806)	(23,223)	(15,802)
Production tax credits	(45,562)	(39,761)	(68,622)
Other non-cash	(9,284)		(4,639)
Other non-cash		9,069
Payment for Pension Benefits	18,000	18,000	18,000
Increase (Decrease) in Other Regulatory Assets	126,625	152,417	79,233
increase (decrease) in purchased gas	(29,720)	(45,111)	132,766
Increase (Decrease) in Other Operating Assets	24,761	3,171	16,098
Change in certain current assets and liabilities:
Increase (Decrease) in Accounts and Other Receivables	96,498	32,994	(3,058)
Increase (Decrease) in Materials and Supplies	(5,046)	2,649	6,018
Increase Decrease In Fuel And Gas Inventories	10,598	(3,287)	(1,268)
increase (decrease) in purchased gas adjustment, short-term	0	0	(9,921)
Increase (Decrease) in Prepaid Expense and Other Assets	997	18,242	1,103
Increase (Decrease) in Accounts Payable	84,775	16,516	(116,311)
Increase (Decrease) in Income Taxes Payable	16,646	10,773	(18,133)
Increase (Decrease) in Other Accounts Payable and Accrued Liabilities	(3,224)	(30,854)	15,163
Net Cash Provided by (Used in) Operating Activities, Total	826,598	727,568	527,336
Net Cash Provided by (Used in) Investing Activities
Construction expenditures excluding equity allowance for funds used during construction	922,144	908,136	959,387
Payments for (Proceeds from) Other Investing Activities	(1,367)	(5,340)	(6,908)
Net Cash Provided by (Used in) Investing Activities, Total	(920,777)	(902,796)	(952,479)
Net Cash Provided by (Used in) Financing Activities
Proceeds from (Repayments of) Short-term Debt	(233,800)	197,800	(203,297)
Payments of Dividends	106,420	45,421	64,220
Proceeds from Contributions from Parent	210,000	4,575	0
Proceeds from Issuance of Long-term Debt	961,538	644,690	689,351
Repayments of Long-term Debt	502,410	450,000	0
Repayments of Debt	234,000	159,400	0
Proceeds from (Payments for) Other Financing Activities	20,570	(1,311)	13,893
Net Cash Provided by (Used in) Financing Activities, Total	115,478	190,933	435,727
Net increase (decrease) in cash, cash equivalents, and restricted cash	21,299	15,705	10,584
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Beginning Balance	81,851	66,146	55,562
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Ending Balance	103,150	81,851	66,146
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	329,894	336,441	328,703
Income Taxes Paid, Net	22,647	4,974	10,616
Non-cash financing and investing activities:
Capital Expenditures Incurred but Not yet Paid	89,958	58,304	58,329
Recognition of new right-of-use assets, Finance Lease	105,176	0	0
Subsidiaries [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net Income (Loss) Attributable to Parent	336,063	274,280	292,924
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	704,372	647,546	656,220
Conservation amortization	103,147	99,585	96,571
Deferred Income Taxes and Tax Credits	(8,652)	15,271	20,474
Unrealized Gain (Loss) on Derivatives	(13,785)	26,807	3,574
Afudc Equity	(27,806)	(23,223)	(15,802)
Production tax credits	(45,562)	(39,761)	(68,622)
Other non-cash	(19,761)	(1,575)	(15,154)
Payment for Pension Benefits	18,000	18,000	18,000
Increase (Decrease) in Other Regulatory Assets	126,625	152,417	79,173
increase (decrease) in purchased gas	(29,720)	(45,111)	132,766
Increase (Decrease) in Other Operating Assets	14,097	(8,764)	8,967
Change in certain current assets and liabilities:
Increase (Decrease) in Accounts and Other Receivables	96,487	33,835	(7,650)
Increase (Decrease) in Materials and Supplies	(5,046)	2,649	6,018
Increase Decrease In Fuel And Gas Inventories	10,598	(3,287)	(1,210)
increase (decrease) in purchased gas adjustment, short-term	0	0	(9,921)
Increase (Decrease) in Prepaid Expense and Other Assets	997	18,242	1,103
Increase (Decrease) in Accounts Payable	92,007	16,549	(116,370)
Increase (Decrease) in Income Taxes Payable	26,152	7,277	(18,016)
Increase (Decrease) in Other Accounts Payable and Accrued Liabilities	6,256	(29,965)	15,371
Net Cash Provided by (Used in) Operating Activities, Total	920,393	824,810	623,924
Net Cash Provided by (Used in) Investing Activities
Construction expenditures excluding equity allowance for funds used during construction	908,273	876,437	919,271
Payments for (Proceeds from) Other Investing Activities	(1,367)	(5,340)	(6,908)
Net Cash Provided by (Used in) Investing Activities, Total	(906,906)	(871,097)	(912,363)
Net Cash Provided by (Used in) Financing Activities
Proceeds from (Repayments of) Short-term Debt	(233,800)	197,800	(203,297)
Payments of Dividends	229,857	149,072	164,575
Proceeds from Contributions from Parent	0	0	210,000
Proceeds from Issuance of Long-term Debt	446,063	0	443,151
Repayments of Long-term Debt	2,410	0	0
Proceeds from (Payments for) Other Financing Activities	22,043	13,389	14,558
Net Cash Provided by (Used in) Financing Activities, Total	2,039	62,117	299,837
Net increase (decrease) in cash, cash equivalents, and restricted cash	15,526	15,830	11,398
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Beginning Balance	80,721	64,891	53,493
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Ending Balance	96,247	80,721	64,891
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	223,484	228,420	219,665
Income Taxes Paid, Net	38,442	11,521	19,269
Non-cash financing and investing activities:
Capital Expenditures Incurred but Not yet Paid	89,958	58,304	58,329
Recognition of new right-of-use assets, Finance Lease	105,176	0	0
Colstrip Units 1 – 4 Common Facilities
Non-cash financing and investing activities:
Increase (Decrease) in Regulatory Assets and Liabilities	$ 0	$ 0	$ 4,163

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2021
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. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that are incurred by PSE and allocated to Puget LNG are related party transactions by nature. In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any ASC 805, “Business Combinations” (ASC 805) purchase accounting adjustments. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. Utility Plant Puget Energy and PSE capitalize, at original cost, additions to utility plant, including renewals and betterments. Costs include indirect costs such as engineering, supervision, certain taxes, pension and other employee benefits and an allowance for funds used during construction (AFUDC). Replacements of minor items of property are included in maintenance expense. When the utility plant is retired and removed from service, the original cost of the property is charged to accumulated depreciation and costs associated with removal of the property, less salvage, are charged to the cost of removal regulatory liability. Planned Major Maintenance Planned major maintenance is an activity that typically occurs when PSE overhauls or substantially upgrades various systems and equipment on a scheduled basis. Costs related to planned major maintenance are deferred and amortized to the next scheduled major maintenance. This accounting method also follows the Washington Utilities and Transportation Commission (Washington Commission) regulatory treatment related to these generating facilities. Other Property and Investments For PSE, the costs of other property and investments (i.e., non-utility) are stated at historical cost. Expenditures for refurbishment and improvements that significantly add to productive capacity or extend useful life of an asset are capitalized. Replacements of minor items are expensed on a current basis. Gains and losses on assets sold or retired, which were previously recorded in utility plant, are apportioned between regulatory assets/liabilities and earnings. However, gains and losses on assets sold or retired, not previously recorded in utility plant, are reflected in earnings. Depreciation and Amortization The Company provides for depreciation and amortization on a straight-line basis. Amortization is recorded for intangibles such as regulatory assets and liabilities, computer software and franchises. The annual depreciation provision stated as a percent of a depreciable electric utility plant was 3.4%, 3.5%, and 3.4% in 2021, 2020, and 2019, respectively; depreciable natural gas utility plant was 2.8%, 2.9%, and 2.8% in 2021, 2020, and 2019, respectively; and depreciable common utility plant was 6.8%, 7.3% and 7.3% in 2021, 2020, and 2019, 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 On February 1, 2022, the Tacoma LNG facility at the Port of Tacoma completed commissioning and is expected to commence commercial operations in the first quarter of 2022. In December 2019, the Puget Sound Clean Air Agency (PSCAA) issued the air quality permit for the facility, and the Pollution Hearings Control Board of Washington State upheld the approval following extended litigation. When in-service, the Tacoma LNG facility will provide peak-shaving services to PSE’s natural gas customers, and provide LNG as fuel to transportation customers, particularly in the marine market at a lower cost due to the facility's scale. Pursuant to an order by the Washington Commission, PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility. The remaining 57.0% of common capital and operating costs of the Tacoma LNG facility will be allocated to Puget LNG. Per this allocation of costs, $244.7 million and $231.6 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, 2021, and December 31, 2020, respectively. Additionally, $1.3 million, $0.6 million, and $1.2 million of operating costs are reported in the Puget Energy "Non-utility expense and other" financial statement line item in 2021, 2020, and 2019, respectively. Additionally, $239.6 million and $207.7 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, 2021, and December 31, 2020, 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 $268.5 million, $240.8 million and $236.5 million for 2021, 2020, and 2019, respectively. The Company reports the collection of such taxes on a gross basis in operation revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income. PSE's electric and natural gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, natural gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. The mechanism mitigates volatility in revenue and gross margin erosion due to weather and energy efficiency. Any differences in revenue are deferred to a regulatory asset for under recovery or regulatory liability for over recovery under alternative revenue recognition standard. Revenue is recognized under this program when deemed collectible within 24 months based on alternative revenue recognition guidance. Decoupled rate increases are effective May 1 of each year subject to a soft rate cap of total revenue for decoupled rate schedules, where rate cap is applied to under-collected revenue and any over-collected revenues are passed back to customers at 100%. Any excess under-recovered revenue above the rate cap will be included in the following year's decoupled rate and the Company will only be able to recognize revenue below the rate cap of total revenue for decoupled rate schedules. For revenue deferrals exceeding the annual rate cap of total revenue for decoupled rate schedules, the Company will assess the excess amount to determine its ability to be collected within 24 months per GAAP rules. The soft rate cap test, which limits the amount of revenues PSE can collect in its annual filings, is 5.0% for natural gas customers and 3.0% for electric customers. The Company will not record any decoupling revenue that is expected to take longer than 24 months to collect following the end of the annual period in which the revenues would have otherwise been recognized. Once determined to be collectible within 24 months, any previously non-recognized amounts will be recognized. Revenues associated with energy costs under the power cost adjustment (PCA) mechanism and purchased gas adjustment (PGA) mechanism are excluded from the decoupling mechanism. Allowance for Credit Losses 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 at December 31, 2021, and 2020: Puget Energy and (Dollars in Thousands) Year Ended December 31, Allowance for credit losses: 2021 2020 Beginning balance $ 20,080 8,294 Provision for credit loss expense 1 27,204 23,292 Receivables charged-off (12,326) (11,506) Total ending allowance balance $ 34,958 $ 20,080 1 $2.8 million and $0.0 million of provision were deferred as cost specific to COVID-19 in 2021 and 2020, respectively. Self-Insurance PSE is self-insured for storm damage and certain environmental contamination associated with current operations occurring on PSE-owned property. In addition, PSE is required to meet a deductible for a portion of the risk associated with comprehensive liability, workers’ compensation claims and catastrophic property losses other than those which are storm related. The cumulative annual cost threshold for deferral of storms under the mechanism is $10.0 million. Additionally, costs may only be deferred if the outage meets the Institute of Electrical and Electronics Engineers (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, 2021 and 2020, $45.6 million and $39.8 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 finance lease liabilities in our consolidated balance sheets. ROU assets represent the right to use an underlying asset for the lease term, and consist of the amount of the initial measurement of the lease liability, any lease payments made to the lessor at or before the commencement date, minus any lease incentives received, and any initial direct costs incurred by the lessee. Lease liabilities represent our obligation to make lease payments arising from the lease and are measured at present value of the lease payments not yet paid, discounted using the discount rate for the lease, determined based on PSE's incremental borrowing rate, at commencement. As most of PSE's leases do not provide an implicit interest rate, PSE uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. For fleet, IT and wind farm leases, this rate is applied using a portfolio approach. The lease terms may include options to extend or terminate the lease when it is reasonably certain that PSE will exercise that option. On the statement of income, operating leases are generally accounted for under a straight-line expense model, while finance leases, which were previously referred to as capital leases, are generally accounted for under a financing model. Consistent with the previous lease guidance, however, the standard allows rate-regulated utilities to recognize expense consistent with the timing of recovery in rates. PSE has lease agreements with lease and non-lease components. Non-lease components comprise common area maintenance and utilities, and are accounted for separately from lease components. Variable Interest Entities On April 12, 2017, PSE entered into a PPA with Skookumchuck Wind Energy Project, LLC (Skookumchuck) in which Skookumchuck would develop a wind generation facility and, once completed, sell bundled energy and associated attributes, namely renewable energy credits to PSE over a term of 20 years. Skookumchuck commenced commercial operation in November 2020. PSE has no equity investment in Skookumchuck but is Skookumchuck’s only customer. Based on the terms of the contract, PSE will receive all of the output of the facility, subject to curtailment rights. PSE has concluded that it is not the primary beneficiary of this VIE since it does not control the commercial and operating activities of the facility. Additionally, PSE does not have the obligation to absorb losses or receive benefits. Therefore, PSE will not consolidate the VIE. Purchased energy of $19.0 million was recognized in purchased electricity on the Company's consolidated statements of income for the year ended December 31, 2021 and $2.7 million is included in accounts payable on the Company's consolidated balance sheet

New Accounting Pronouncements

New Accounting Pronouncements	12 Months Ended
	Dec. 31, 2021
Accounting Standards Update and Change in Accounting Principle [Abstract]
New Accounting Pronouncements	New Accounting Pronouncements Recently Adopted Accounting Guidance Reference Rate Reform In March 2020, the FASB issued ASU 2020-04, "Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting ”. ASU 2020-04 provides temporary optional expedients and exceptions to the current guidance on contract modifications to ease the financial reporting burdens related to the expected market transition from London Interbank Offered Rate (LIBOR) and other interbank offered rates to alternative reference rates. The Company has term loans, credit agreements, and promissory notes that reference LIBOR. As of December 31, 2021, 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 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. Credit 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 2018, the FASB issued ASU 2018-13, "Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement" . The amendments in this update modify the disclosure requirements on fair value measurements in Topic 820, Fair Value Measurement, based on the concepts in the Concepts Statement, including the consideration of costs and benefits. The amendments are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The Company adopted this update as of January 1, 2020, and it impacted Note 11, "Fair Value Measurements". As the amendment contemplates changes in disclosures only, it did not have a material impact on the Company's results of operations, cash flows, or consolidated balance sheets. Goodwill In 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.

Revenue (Notes)

Revenue (Notes)	12 Months Ended
	Dec. 31, 2021
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: 2021 2020 2019 Electric retail $ 2,348,356 $ 2,106,122 $ 2,132,522 Natural gas retail 1,036,411 938,061 870,457 Other 349,365 178,208 308,111 Total revenue from contracts with customers 3,734,132 3,222,391 3,311,090 Alternative revenue programs (31,510) 35,006 (18,634) Other non-customer revenue 103,039 69,053 108,674 Total operating revenue $ 3,805,661 $ 3,326,450 $ 3,401,130 Revenue at PSE is recognized when performance obligations under the terms of a contract or tariff with our customers are satisfied. Performance obligations are satisfied generally through performance of PSE's obligation over time or with transfer of control of electric power, natural gas, and other revenue from contracts with customers. Revenue is measured as the amount of consideration expected to be received in exchange for transferring goods and services. Electric and Natural Gas Retail Revenue Electric and natural gas retail revenue consists of tariff-based sales of electricity and natural gas to PSE's customers. For tariff contracts, PSE has elected the portfolio approach practical expedient model to apply the revenue from contracts with customers to groups of contracts. The Company determined that the portfolio approach will not differ from considering each contract or performance obligation separately. Electric and natural gas tariff contracts include the performance obligation of standing ready to perform electric and natural gas services. The electricity and natural gas the customer chooses to consume is considered an option and is recognized over time using the output method when the customer simultaneously consumes the electricity or natural gas. PSE has elected the right to invoice practical expedient for unbilled retail revenue. The obligation of standing ready to perform electric service and the consumption of electricity and natural gas at market value implies a right to consideration for performance completed to date. The Company believes that tariff prices approved by the Washington Commission represent stand-alone selling prices for the performance obligations under ASC 606. PSE collects Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes and presents the taxes on a gross basis, as PSE is the taxpayer for those excise and municipal taxes. Other Revenue from Contracts with Customers Other revenue from contracts with customers is primarily comprised of electric transmission, natural gas transportation, biogas, and wholesale revenue sold on an intra-month basis. Electric Transmission and Natural Gas Transportation Transmission and transportation tariff contracts include the performance obligation to transmit and transport electricity or natural gas. Transfer of control and recognition of revenue occurs over time as the customer simultaneously receives the transmission and transportation services. Measurement of satisfaction of this performance obligation is determined using the output method. Similar to retail revenue, the Company utilizes the right to invoice practical expedient as PSE’s right to consideration is tied directly to the value of power and natural gas transmitted and transported each month. The price is based on the tariff rates that were approved by the Washington Commission or the FERC and, therefore, corresponds directly to the value to the customer for performance completed to date. Biogas Biogas is a renewable natural gas fuel that PSE purchases and sells along with the renewable green attributes derived from the renewable natural gas. Biogas contracts include the performance obligations of biogas and renewable credit delivery upon PSE receiving produced biogas from its supplier. Transfer of control and recognition of revenue occurs at a point in time as biogas is considered a storable commodity and may not be consumed as it is delivered. Wholesale Wholesale revenue at PSE includes sales of electric power and non-core natural gas to other utilities or marketers. Wholesale revenue contracts include the performance obligation of physical electric power or natural gas. There are typically no added fixed or variable amounts on top of the established rate for power or natural gas and contracts always have a stated, fixed quantity of power or natural gas delivered. Transfer of control and recognition of revenue occurs at a point in time when the customer takes physical possession of electric power or natural gas. Non-core gas consists of natural gas supply in excess of natural gas used for generation, sold to third parties to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. PSE reports non-core gas sold net of costs as PSE does not take control of the natural gas but is merely an agent within the market that connects a seller to a purchaser. PWI Land Sale On August 13, 2021, Puget Western, Inc. (PWI) a wholly-owned subsidiary of PSE sold a parcel of land that resulted in $23.2 million of other revenue from contracts with customers. PWI purchases, develops, and sells land holdings throughout PSE’s service territory; thus, the sale was reported as non-utility revenue of $23.2 million and non-utility expense of $12.9 million. Other Revenue In accordance with ASC 606, PSE separately presents revenue not collected from contracts with customers that falls under other accounting guidance. Transaction Price Allocated to Remaining Performance Obligations In December 2020, PLNG entered into a contract with one customer where PLNG is selling LNG over a 10-year delivery period beginning no later than 2024. The contract requires the customer to purchase a minimum annual quantity even if the customer does not take delivery. The price of the LNG includes a fixed charge, a fuel charge that includes both a market index and fixed margin component and other variable consideration. The fixed transaction price is allocated to the remaining performance obligations which is determined by the fixed charge components multiplied by the outstanding minimum annual quantity. Based on management’s best estimate of commencement, the Company expects to recognize this revenue over the following time periods: Puget Energy (Dollars in Thousands) 2024 2025 2026 2027 2028 Thereafter Total Remaining Performance Obligations $ 15,359 19,710 19,454 19,454 19,454 102,135 $ 195,566

Regulation and Rates

Regulation and Rates	12 Months Ended
	Dec. 31, 2021
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, 2021, and 2020, are included the following tables: Puget Sound Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2021 2020 Environmental remediation (a) $ 127,977 $ 102,647 Storm damage costs electric 4 years 127,789 108,491 PCA mechanism N/A 79,546 82,801 Decoupling deferrals and interest (b) Less than 2 years 79,125 88,504 Chelan PUD contract initiation 9.8 years 69,699 76,787 Deferred Washington Commission AFUDC 30 years 62,244 59,763 PGA receivable 2 years 57,935 87,655 Baker Dam licensing operating and maintenance costs (c) 54,525 54,354 Lower Snake River 15.4 years 53,757 58,442 Get to zero depreciation expense deferral N/A 50,220 53,236 Unamortized loss on reacquired debt 1 to 46 years 35,805 37,991 Property tax tracker Less than 2 years 25,896 24,860 Advanced metering infrastructure (a) 23,037 22,652 Low Income Program Costs N/A 21,755 — Private Letter Ruling EDIT 1 year 18,850 — Generation plant major maintenance, excluding Colstrip 1 to 8 years 12,094 10,494 Snoqualmie licensing operating and maintenance costs (c) 7,446 7,435 Mint Farm ownership and operating costs 3.3 years 6,318 8,318 Washington Commission electric vehicle N/A 6,109 3,641 Water heater rental property loss N/A 5,725 6,973 Colstrip major maintenance (d) 4,035 4,335 Washington Commission COVID-19 N/A 3,657 — Energy conservation costs (a) 3,573 8,009 Various other regulatory assets (a) 15,422 10,719 Total PSE regulatory assets $ 952,539 $ 918,107 Deferred income taxes (e) N/A (866,541) (953,987) Cost of removal (f) (563,129) (508,707) Repurposed production tax credits N/A (134,270) (79,581) PGA unrealized gain N/A (60,728) (4,925) Decoupling liability Less than 2 years (36,506) (16,448) Treasury grants 2 years (22,476) (43,164) Green direct N/A (13,194) (14,313) Gain on Sale Shuffleton N/A (4,892) (11,131) Production tax credits (g) — (47,094) Various other regulatory liabilities (a) (7,725) (5,871) Total PSE regulatory liabilities (1,709,461) (1,685,221) PSE net regulatory assets (liabilities) $ (756,922) $ (767,114) __________________ (a) Amortization periods vary depending on timing of underlying transactions. (b) Decoupling deferrals and interest includes a 24 month GAAP reserve of $3.0 million and $8.0 million for December 31, 2021 and 2020, respectively. (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) For additional information, see Note 14,"Income Taxes" to the consolidated financial statements included in Item 8 of this report. (f) The balance is dependent upon the cost of removal of underlying assets and the life of utility plant. (g) Amortize as PTCs are utilized on PSE's tax return. Puget Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2021 2020 Total PSE regulatory assets (a) $ 952,539 $ 918,107 Puget Energy acquisition adjustments: Regulatory assets related to power contracts 4 to 31 years 9,689 11,728 Total Puget Energy regulatory assets 962,228 929,835 Total PSE regulatory liabilities (a) (1,709,461) (1,685,221) Puget Energy acquisition adjustments: Deferred income taxes 565 713 Regulatory liabilities related to power contracts 4 to 31 years (80,934) (95,774) Various other regulatory liabilities Varies (1,264) (1,264) Total Puget Energy regulatory liabilities (1,791,094) (1,781,546) Puget Energy net regulatory asset (liabilities) $ (828,866) $ (851,711) ____________________ (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 $563.1 million and $508.7 million in 2021 and 2020, respectively, for the cost of removal of utility plant. These amounts are collected from PSE’s customers through depreciation rates. General Rate Case Filing PSE filed a general rate case (GRC) which includes a three year multiyear rate plan with the Washington Commission on January 31, 2022, requesting an overall increase in electric and natural gas rates of 13.6% and 13.0% respectively in 2023; 2.5% and 2.3%, respectively in 2024; and 1.2% and 1.8%, respectively, in 2025. PSE requested a return on equity of 9.9% in all three rate years. PSE requested an overall rate of return of 7.39% in 2023; 7.44% in 2024; and 7.49% in 2025. The filing requests recovery of forecasted plant additions through 2022 as required by RCW 80.28.425 as well as forecasted plant additions through 2025, the final year of the multiyear rate plan. The next phase of the filing will be to establish a procedural calendar for the adjudication of the case. PSE filed a GRC with the Washington Commission on June 20, 2019, requesting an overall increase in electric and natural gas rates of 6.9% and 7.9% respectively. On July 8, 2020, the Washington Commission issued its order on PSE’s GRC. The ruling provided for a weighted cost of capital of 7.39% or 6.8% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.4%. The order also resulted in a combined net increase to electric of $29.5 million, or 1.6%, and to natural gas of $36.5 million, or 4.0%. However, the Washington Commission extended the amortization of certain regulatory assets, PSE’s electric decoupling deferral, and PSE’s PGA deferral to mitigate the impact of the rate increase in response to the economic uncertainty created by the COVID-19 pandemic. This reduced the electric revenue increase to approximately $0.9 million, or 0.05% and the natural gas increase to $1.3 million, or 0.15% and became effective October 15, 2020 and October 1, 2020, respectively. On August 6, 2020, PSE filed a petition for judicial review with the Superior Court of the State of Washington for King County 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. 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. On October 7, 2020, PSE, the Washington Commission and interveners agreed to dismiss the petition for judicial review. The agreement was 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 would open a proceeding to review and enact the changes required by the IRS ruling. There was approximately $25.6 million in annual revenue requirement related to the 2019 GRC, which PSE requested it be allowed to track and recover. On July 30, 2021, the IRS issued a PLR to PSE which concludes that the Washington Commission’s methodology for reversing plant-related excess deferred income taxes is an impermissible methodology under the IRS normalization and consistency rules. The PLR requires adjustments to PSE's rates to bring PSE back into compliance with IRS rules. Accordingly, on September 28, 2021, the Washington Commission issued an order amending their order previously issued on July 8, 2020, to correct for items which were determined to be impermissible under IRS normalization and consistency rules as detailed in the PLR. To reflect the impact of the PLR, PSE has recorded a regulatory asset and additional revenues of $24.5 million in its operating results through December 31, 2021, of which $5.6 million was collected from customers. Thus, the annualized overall rate impact is an increase of $15.8 million, or 0.7%, for electric and $3.1 million, or 0.3%, for natural gas for a total of $18.9 million with rates effective October 1, 2021. This led to an overall annualized net increase to electric rates of $77.1 million, or 3.7%, an increase of $17.5 million above the $59.6 million granted in the revised final order. The order also led to an overall annualized net increase to natural gas rates of $45.3 million, or 5.9%, an increase of $2.4 million above the $42.9 million granted in the revised final order. The Washington Commission maintained adjustments that mitigated the impacts of the rate increases in response to the economic instability created by the COVID-19 pandemic, which reduced the electric revenue increase to approximately $48.3 million, or 2.3%, and the natural gas increase to $4.9 million, or 0.6%. Power Cost Only Rate Case On December 9, 2020, PSE filed its 2020 power cost only rate case (PCORC). The filing proposed an increase of $78.5 million (or an average of approximately 3.7%) in the Company's overall power supply costs with an anticipated effective date in June 2021. On February 2, 2021, PSE supplemented the PCORC to update its power costs, leading to a requested increase from $78.5 million to $88.0 million (or an average of approximately 4.1%). On March 2, 2021, the parties to the PCORC reached an unopposed multiparty settlement in principle. The settlement resulted in an estimated revenue increase of $65.3 million or 3.1%. A term of the settlement requires PSE to include in its next GRC (or another proceeding in 2022) the issue of whether the PCORC should continue, and further prohibits PSE from filing another PCORC before this issue is litigated. On June 1, 2021, the Washington Commission issued its Final Order approving and adopting the settlement and authorizing and requiring a power cost update through a compliance filing. On June 17, 2021, PSE filed a compliance filing with the Washington Commission with a revenue increase of $70.9 million or 3.3% due to the update on power costs with rates effective July 1, 2021. Decoupling Filings 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-year period, instead of the originally approved one-year period. Additionally, through approving the electric cost of service, the final order approved the re-allocation of decoupling balances from Schedule 40 to the remaining electric decoupling groups. On December 23, 2020, the Washington Commission approved PSE’s filing to update Schedule 142 decoupling amortization rates, with an effective date of January 1, 2021, by zeroing out rates still effective past October 15, 2020 on tariff sheet Schedule 142-H, which was replaced by rates on tariff sheet Schedule 142-I effective October 15, 2020. PSE included a true up of the over-collection amounts for the period of October 15, 2020 through December 31, 2020 in PSE’s annual May 2021 decoupling filing. On June 1, 2021, the Washington Commission approved the multi-party settlement agreement which was filed within PSE’s PCORC filing. As part of this settlement agreement, the electric annual fixed power cost allowed revenue was updated to reflect changes in the approved revenue requirement. The changes took effect on July 1, 2021. On September 28, 2021, the Washington Commission approved 2019 GRC filing updated to PLR changes. As part of this filing, the annual electric and gas delivery cost allowed revenue was updated to reflect changes in the approved revenue requirement. The changes took effect on October 1, 2021. On December 31, 2021, 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 $3.0 million of electric deferred revenue will not be collected within 24 months of the annual period; therefore a reserve adjustment was booked to 2021 electric decoupling revenue. Natural gas deferred revenue will be collected within 24 months of the annual period; therefore, no reserve adjustment was booked to 2021 natural gas decoupling revenue. This compares to $8.0 million of electric deferred revenue not being collected within 24 months of the annual period in 2020; therefore, a reserve adjustment was booked to 2020 electric decoupling revenue and natural gas deferred revenue would be collected within 24 months of the annual period; therefore no reserve adjustment was booked to 2020 natural gas decoupling revenue. Power Cost Adjustment Mechanism PSE currently has a PCA mechanism that provides for the deferral of power costs that vary from the “power cost baseline” level of power costs. The “power cost baseline” levels are set, in part, based on normalized assumptions about weather and hydroelectric conditions. Excess power costs or savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism and will trigger a surcharge or refund when the cumulative deferral trigger is reached. Effective January 1, 2017, the following graduated scale is used in the PCA mechanism: Company’s Share Customers' Share Annual Power Cost Variability Over Under Over Under Over or Under Collected by up to $17 million 100 % 100 % — % — % Over or Under Collected by between $17 million - $40 million 35 50 65 50 Over or Under Collected beyond $40 + million 10 10 90 90 For the year ended December 31, 2021, in its PCA mechanism, PSE under recovered its allowable costs by $68.0 million of which $36.7 million was apportioned to customers and $1.7 million of interest was accrued on the deferred customer balance. This compares to an under recovery of allowable costs of $76.1 million, for the year ended December 31, 2020, of which $44.0 million was apportioned to customers and accrued $2.0 million of interest on the total deferred customer balance. The under recovery in 2020 was included in the Power Cost Adjustment Clause filing, mentioned below. Power Cost Adjustment Clause Filing 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 2020. The surcharging of deferrals can be triggered by the Company when the balance in the deferral account is a credit of $20.0 million or more. During 2020, actual power costs were higher than baseline power costs, thereby creating an under-recovery of $76.1 million. Under the terms of the PCA’s sharing mechanism for under-recovered power costs, PSE absorbed $32.1 million of the under-recovered amount, and customers were responsible for the remaining $44.0 million, or $46.0 million including interest. PSE filed to recover the deferred balance in Docket UE-210300, effective December 1, 2021, and the Washington Commission approved PSE’s request on September 30, 2021. Purchased Gas Adjustment Mechanism 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. On October 28, 2021, the Washington Commission approved PSE's request for November 2021 PGA rates in Docket UG-210721, effective November 1, 2021. As part of that filing, PSE requested an annual revenue increase of $59.1 million; where PGA rates, under Schedule 101, increase annual revenue by $80.6 million, and the tracker rates under Schedule 106, decrease annual revenue by $21.5 million. Those rate increases will be set 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, 2021 and December 31, 2020: (Dollars in Thousands) At December 31, At December 31, PGA receivable balance and activity 2021 2020 PGA receivable beginning balance $ 87,655 $ 132,766 Actual natural gas costs 364,775 314,792 Allowed PGA recovery (396,236) (363,886) Interest 1,741 3,983 PGA receivable ending balance $ 57,935 $ 87,655 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, 2021 and December 31, 2020, PSE deferred $6.6 million and $2.8 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%. 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 $11.0 million in unspent low income funds from prior years, and supplements other forms of financial assistance. The program does not require an increase to rates and is compatible with other low income programs. Based on the COVID-19 pandemic and resulting state of emergency, the Washington Commission allowed the tariff revisions to become effective on April 13, 2020. PSE made an additional filing on July 21, 2020 to increase the amount of electric funds available for distribution by $4.5 million under the CACAP program. On March 28, 2021, the Washington Commission approved PSE’s second Crisis Affected Customer Assistance Program (CACAP-2), effective April 12, 2021. CACAP-2 will provide up to $2,500 in bill assistance per year for each qualifying low-income household. The CACAP-2 total program budget is $20.0 million for electric customers and $7.7 million for natural gas customers. Natural gas funds may be used for electric bills if necessary. Customers may apply for CACAP-2 more than once during the 12-month program year of October-September. On October 15, 2021, PSE submitted for the Washington Commission’s review and approval a Supplemental CACAP filing to continue assistance for PSE customers facing financial hardship due to COVID-19. The Supplemental CACAP would utilize carry-over funds not expended in any prior years under PSE’s Schedule 129 Home Energy Lifeline Program. The Supplemental CACAP benefits, for both electric and natural gas residential customers, would be a combined total of $34.5 million and be capped at $23.7 million and $10.8 million, respectively. Additionally, the Supplemental CACAP filing proposed to revise the CACAP-2 total program budget to $27.7 million for electric customers (instead of $20.0 million for electric customers and $7.7 million for natural gas customers). The Supplemental CACAP budget for natural gas customers of $10.8 million would be used for both the CACAP-2 program and the Supplemental CACAP program benefits. The Supplemental CACAP benefits would be available to PSE’s residential customers who have a past due balance on their PSE electric or natural gas service account and who have a total net household income which is at or below 200% of the federal poverty level guidelines, based on household, as determined by the Company. The Supplemental CACAP benefits would cover a qualifying residential customer’s past due balance, up to $2,500. PSE would apply the Supplemental CACAP benefits to qualifying residential service accounts automatically with an opt-out option. The Supplemental CACAP was approved by the Washington Commission at the November 12, 2021 open meeting. Both CACAP-2 and Supplemental CACAP would be administered until funds are exhausted. Storm Loss Deferral Mechanism The Washington Commission has defined deferrable weather-related events and provided that costs in excess of the annual cost threshold may be deferred for qualifying damage costs that meet the modified Institute of Electrical and Electronics Engineers outage criteria for system average interruption duration index. For the year ended December 31, 2021, PSE incurred $51.4 million in weather-related electric transmission and distribution system restoration costs, of which the Company deferred $40.9 million and $0.2 million as regulatory assets related to storms that occurred in 2021 and 2020, respectively. This compares to $21.8 million incurred in weather-related electric transmission and distribution system restoration costs for the year ended December 31, 2020, of which the Company deferred $11.2 million as regulatory assets related to storms that occurred in 2020. Under the 2017 GRC Order, the storm loss deferral mechanism approved the following: (i) the cumulative annual cost threshold for deferral of storms under the mechanism at $10.0 million; and (ii) qualifying events where the total qualifying cost is less than $0.5 million will not qualify for deferral and these costs will also not count toward the $10.0 million annual cost threshold. Environmental Remediation

Dividend Payment Restrictions

Dividend Payment Restrictions	12 Months Ended
	Dec. 31, 2021
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, 2021, approximately $1.2 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 47.5% at December 31, 2021, and the EBITDA to interest expense was 5.5 to 1.0 for the twelve months ended December 31, 2021. 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 3.9 to 1.0 for the twelve months ended December 31, 2021.

Utility Plant

Utility Plant	12 Months Ended
	Dec. 31, 2021
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) 2021 2020 2021 2020 Distribution plant 20-65 $ 7,488,629 $ 7,028,731 $ 9,026,042 $ 8,592,720 Production plant 12-90 3,147,987 3,096,092 3,815,599 3,767,014 Transmission plant 43-75 1,556,666 1,494,781 1,663,559 1,601,731 General plant 5-75 746,758 697,501 773,662 726,327 Intangible plant (including capitalized software) 1 3-50 797,691 779,767 788,240 770,317 Plant acquisition adjustment N/A 242,826 242,826 282,792 282,792 Underground storage 25-60 43,391 39,498 56,820 52,927 Liquefied natural gas storage 25-60 12,628 12,628 14,498 14,498 Plant held for future use N/A 46,020 45,929 46,172 46,081 Recoverable Cushion Gas N/A 8,655 8,655 8,655 8,655 Plant not classified N/A 316,933 384,794 316,933 384,794 Finance leases, net of accumulated amortization 2 N/A 105,020 881 105,020 881 Less: accumulated provision for depreciation (4,031,458) (3,671,094) (6,416,246) (6,087,748) Subtotal $ 10,481,746 $ 10,160,989 $ 10,481,746 $ 10,160,989 Construction work in progress 870,204 712,204 870,204 712,204 Net utility plant $ 11,351,950 $ 10,873,193 $ 11,351,950 $ 10,873,193 _______________________ 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, 2021, and 2020, accumulated amortization of finance leases at Puget Energy and PSE was $2.6 million and $1.6 million, respectively. Jointly owned generating plant service costs are included in utility plant service cost at the Company's ownership share. The Company provides financing for its ownership interest in the jointly owned utility plants. The following tables indicate the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2021. 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% $ 339,073 $ — $ (153,950) Frederickson 1 Natural Gas 49.85 63,210 — (18,215) Jackson Prairie Natural Gas 33.34 42,736 471 (10,867) Tacoma LNG Natural Gas various — 484,299 — 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 % $ 597,009 $ — $ (411,887) Frederickson 1 Natural Gas 49.85 69,278 — (24,283) Jackson Prairie Natural Gas 33.34 56,820 471 (24,952) Tacoma LNG Natural Gas various — 239,566 — In June 2019, Talen, the plant operator of Colstrip Units 1 and 2, announced a plan to shut down as of December 31, 2019. The Company retired Colstrip 1&2 from Utility Plant and transferred the unrecovered plant amount of $126.5 million to regulatory assets, offset by depreciation as included in base rates until the 2019 GRC became effective in October 2020. Consistent with the GRC settlement in 2017, monetization of the PTCs will fund the following: (i) Colstrip Community Transition Fund, (ii) unrecovered Colstrip plant and (iii) incurred decommissioning and remediation costs for Colstrip. At December 31, 2021, and December 31, 2020, 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). The Company records its ARO liabilities for its electric transmission and distribution poles as well as gas distribution mains aligned with its underlying asset data with future estimates of retirements. 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 rule 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, 2021, the Company reviewed the estimated remediation costs at Colstrip and decreased the Colstrip ARO liability by $1.5 million for Colstrip Units 1 and 2 and $3.1 million for Colstrip Units 3 and 4. The 2021 decrease to Colstrip 1 and 2 is primarily due to remediation plans approved by the Montana Department of Environmental Quality under a 2012 settlement between the plant operator and the state for the remaining sites at Colstrip. The plant operator previously contested the approved plan for Colstrip Units 1 and 2 under the defined process in the settlement with the state and reached a settlement agreement regarding the ability to still present another option under the settlement terms and conditions. The Company had previously recorded these incremental costs in 2020 for remediation work on the older ponds under ASC 410-20 “Asset Retirement and Environmental Obligations" and ASC 410-30 “Environmental Remediation". For the twelve months ended December 31, 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. For the twelve months ended December 31, 2021 and 2020, the Company also recorded relief of ARO and environmental remediation liability of $13.1 million and $9.6 million, respectively. In addition, the Company recorded Tacoma LNG facility ARO liability of $3.8 million and $3.3 million for PSE and $3.7 million and $7.4 million for Puget LNG as of December 31, 2021 and December 31, 2020, respectively. The 2021 and 2020 increases to the Tacoma LNG facility ARO liabilities are primarily due to continued construction of the plant. In 2021, the ARO liability associated with the Tacoma LNG facility was fully recorded as construction was essentially complete and commissioning activities are on-going. Puget Energy and Puget Sound Energy December 31, (Dollars in Thousands) 2021 2020 Asset retirement obligation at beginning of the period $ 216,163 $ 181,353 Relief of liability (13,146) (9,647) Revisions in estimated cash flows (46) 38,677 Accretion expense 6,070 5,780 Asset retirement obligation at end of period 1 $ 209,041 $ 216,163 ___________________ 1. Asset retirement obligations include $3.7 million and $7.4 million for Puget LNG held only at Puget Energy as of December 31, 2021, and 2020, 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, 2021: • 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, 2021
Long-term Debt, Unclassified [Abstract]
Long-term Debt	Long-Term Debt The following table presents outstanding long-term debt due dates and principal amounts, net of debt discount, issuance and other costs and fair value adjustments as of 2021 and 2020: (Dollars in Thousands) December 31, Series Type Due 2021 2020 Puget Sound Energy: 7.150% First Mortgage Bond 2025 $ 15,000 $ 15,000 7.200% First Mortgage Bond 2025 2,000 2,000 7.020% Senior Secured Note 2027 300,000 300,000 7.000% Senior Secured Note 2029 100,000 100,000 3.900% Pollution Control Bond 2031 138,460 138,460 4.000% Pollution Control Bond 2031 23,400 23,400 5.483% Senior Secured Note 2035 250,000 250,000 6.724% Senior Secured Note 2036 250,000 250,000 6.274% Senior Secured Note 2037 300,000 300,000 5.757% Senior Secured Note 2039 350,000 350,000 5.795% Senior Secured Note 2040 325,000 325,000 5.764% Senior Secured Note 2040 250,000 250,000 4.434% Senior Secured Note 2041 250,000 250,000 5.638% Senior Secured Note 2041 300,000 300,000 4.300% Senior Secured Note 2045 425,000 425,000 4.223% Senior Secured Note 2048 600,000 600,000 3.250% Senior Secured Note 2049 450,000 450,000 2.893% Senior Secured Note 2051 450,000 — 4.700% Senior Secured Note 2051 45,000 45,000 * Debt discount, issuance cost and other * (39,141) (35,816) Total PSE long-term debt $ 4,784,719 $ 4,338,044 Puget Energy: * Fair value adjustment of PSE long-term debt * $ (156,849) $ (165,357) * Revolving Credit Agreement 2023 33,300 14,700 * Term Loan Agreement 1 2022 — 210,000 5.625% Senior Secured Note 2 2022 — 450,000 3.650% Senior Secured Note 2025 400,000 400,000 2.379% Senior Secured Note 2028 500,000 — 4.100% Senior Secured Note 2030 650,000 650,000 * Debt discount, issuance cost and other * (7,404) (4,947) Total Puget Energy long-term debt $ 6,203,766 $ 5,892,440 ___________________ * Not Applicable. 1. Term loan in the amount of $210.0 million was paid off on June 23, 2021. 2. 5.625% Senior Secured Note in the amount of $450.0 million was classified on the Balance Sheet as current maturities of long-term debt as of July 31, 2021. PSE's senior secured notes will cease to be secured by the pledged first mortgage bonds on the date (the "Substitution Date") that all of the first mortgage bonds issued and outstanding under the electric or natural gas utility mortgage indenture have been retired. As of December 31, 2021, the latest maturity date of the first mortgage bonds, other than pledged first mortgage bonds, is December 22, 2025. On the Substitution Date, PSE will deliver to the trustee for PSE's senior secured notes substitute pledged first mortgage bonds to be issued under a new mortgage indenture. As a result, as of the Substitution Date PSE's outstanding senior secured notes and any future series of PSE's senior secured notes will be secured by substitute pledged first mortgage bonds. Puget Energy Long-Term Debt On May 19, 2020, Puget Energy issued $650.0 million of senior secured 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. On June 14, 2021, Puget Energy issued $500.0 million of senior secured notes at an interest rate of 2.379%. The notes were issued for a period of 7 years, mature on June 15, 2028, and pay interest semi-annually on June 15 and December 15. Proceeds from the issuance of the notes were invested in short-term money market funds, then used to repay the Company’s $500.0 million 6.0% notes that matured on September 1, 2021. On June 23, 2021, Puget Energy received an equity contribution from Puget Equico LLC, Puget Energy’s parent company. The proceeds from the equity contribution were used to pay off Puget Energy’s $210.0 million term loan. At December 31, 2021, Puget Energy maintained an $800.0 million credit facility, of which $33.3 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, $100.0 million was available to be issued. The shelf registration will expire in August 2022. On September 15, 2021, PSE issued $450.0 million of senior secured notes at an interest rate of 2.893%. The notes were issued for a period of 30 years, mature on September 15, 2051, and pay interest semi-annually on March 15 and September 15 of each year. The proceeds from the issuance will be used for repayment of commercial paper as well as general corporate purposes. 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) 2022 2023 2024 2025 2026 Thereafter Total Maturities of: PSE $ — $ — $ — $ 17,000 $ — $ 4,806,860 $ 4,823,860 Puget Energy 450,000 33,300 — 400,000 — 1,150,000 2,033,300 Total long-term debt $ 450,000 $ 33,300 $ — $ 417,000 $ — $ 5,956,860 $ 6,857,160

Liquidity Facilities and Other

Liquidity Facilities and Other Financing Arrangements	12 Months Ended
	Dec. 31, 2021
Liquidity Facilities and Other Financing Arrangements [Abstract]
Liquidity Facilities and Other Financing Arrangements	Liquidity Facilities and Other Financing Arrangements As of December 31, 2021, and 2020, PSE had $140.0 million and $373.8 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 2021 and 2020 was 1.6% and 2.0%, respectively. As of December 31, 2021, 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 receipt of commitments from one or more lenders, 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, 2021, 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, 2021, no amounts were drawn and outstanding under PSE's credit facility. No letters of credit were outstanding and $140.0 million was outstanding under the commercial paper program. Outside of the credit agreement, PSE had a $2.5 million letter of credit in support of a long-term transmission contract. Demand Promissory Note In 2006, PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a demand promissory note pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy. Under the terms of the promissory note, PSE pays interest on the outstanding borrowings based on the lower of the weighted-average interest rates of PSE’s outstanding commercial paper or PSE’s senior unsecured revolving credit facility. Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. As of December 31, 2021, there was no outstanding balance under the promissory 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 on October 25, 2023. As of December 31, 2021, there was $33.3 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, 2021
Leases [Abstract]
Lessee, Operating Leases	Leases PSE has operating leases for buildings for corporate offices and operations, real estate for operating facilities and the PSE and PLNG LNG facility, land for our wind farms, and vehicles for PSE’s fleet. Finance leases represent office printers and office buildings. The leases have remaining lease terms of less than a year to 48 years. PSE's right-of-use (ROU) assets and lease liabilities include options to extend leases when it is reasonably certain that PSE will exercise that option. During 2021, mechanical completion was achieved for the Puget LNG facility which triggered an increase in the lease payments for the Port of Tacoma lease. This remeasurement resulted in an increase of the operating lease ROU asset and operating lease liabilities of $26.3 million, of which $0.4 million was recorded in current operating lease liabilities and $25.9 million was recorded in operating lease liabilities. Additionally, two finance leases commenced for service center facilities in Kent and Puyallup, Washington. The Kent lease has a term of 20 years and resulted in an increase of electric utility plant and finance lease liabilities of $45.1 million, of which $1.0 million was recorded in other current liabilities and $44.1 million was recorded in finance lease liabilities, respectively. The Puyallup lease has a term of 20 years and resulted in an increase in common utility plant and finance lease liabilities of $61.3 million, of which $0.4 million was recorded in other current liabilities and $59.9 million was recorded in finance lease liabilities. The components of lease cost were as follows: Puget Energy and Year Ended December 31, Year Ended December 31, (Dollars in Thousands) 2021 2020 Finance lease cost: Amortization of right-of-use asset $ 1,291 $ 607 Interest on lease liabilities 358 34 Total finance lease cost $ 1,649 $ 641 Operating lease cost 1 $ 23,983 $ 21,983 _______________ 1. Includes $1.4 million and $1.0 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease or both of the years ended December 31, 2021 and December 31, 2020, 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) 2021 2020 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flow for operating leases $ 16,440 $ 15,305 Investing cash flow for operating leases 1 7,543 6,678 Operating cash flow for finance leases 358 34 Financing cash flow for finance leases 1,291 607 Non-cash disclosure upon commencement of new lease Right-of-use assets obtained in exchange for new operating lease liabilities $ 4,820 $ 6,302 Right-of-use assets obtained in exchange for new finance lease liabilities 105,176 — Non-cash disclosure upon modification of existing lease Modification of operating lease right-of-use assets $ 26,287 $ — _______________ 1 Includes $1.4 million and $1.0 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for both of the years ended December 31, 2021 and December 31, 2020, 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 2021 2020 Operating lease right-of-use asset $ 184,957 $ 172,167 Operating leases liabilities current $ 20,398 $ 19,204 Operating lease liabilities long-term 172,510 160,980 Total operating lease liabilities: $ 192,908 $ 180,184 Finance Leases Common plant $ 61,227 $ 881 Electric plant 43,793 — Total finance lease assets $ 105,020 $ 881 Other current liabilities $ 1,742 $ 475 Finance lease liabilities 105,303 320 Total finance lease liabilities $ 107,045 $ 795 Weighted Average Remaining Lease Term Operating leases 22.80 Years 18.97 Years Finance leases 20.15 Years 2.00 Years Weighted Average Discount Rate Operating leases 3.27 % 3.59 % Finance leases 3.07 % 2.98 % The following tables summarize the Company’s estimated future minimum lease payments as of December 31, 2021: Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2022 $ 23,945 $ 4,881 2023 23,717 6,260 2024 23,000 6,286 2025 19,636 6,411 2026 17,126 6,540 Thereafter 164,797 116,553 Total lease payments $ 272,221 $ 146,931 Less imputed interest (79,313) (39,886) Total net present value $ 192,908 $ 107,045
Lessee, Finance Leases	Leases PSE has operating leases for buildings for corporate offices and operations, real estate for operating facilities and the PSE and PLNG LNG facility, land for our wind farms, and vehicles for PSE’s fleet. Finance leases represent office printers and office buildings. The leases have remaining lease terms of less than a year to 48 years. PSE's right-of-use (ROU) assets and lease liabilities include options to extend leases when it is reasonably certain that PSE will exercise that option. During 2021, mechanical completion was achieved for the Puget LNG facility which triggered an increase in the lease payments for the Port of Tacoma lease. This remeasurement resulted in an increase of the operating lease ROU asset and operating lease liabilities of $26.3 million, of which $0.4 million was recorded in current operating lease liabilities and $25.9 million was recorded in operating lease liabilities. Additionally, two finance leases commenced for service center facilities in Kent and Puyallup, Washington. The Kent lease has a term of 20 years and resulted in an increase of electric utility plant and finance lease liabilities of $45.1 million, of which $1.0 million was recorded in other current liabilities and $44.1 million was recorded in finance lease liabilities, respectively. The Puyallup lease has a term of 20 years and resulted in an increase in common utility plant and finance lease liabilities of $61.3 million, of which $0.4 million was recorded in other current liabilities and $59.9 million was recorded in finance lease liabilities. The components of lease cost were as follows: Puget Energy and Year Ended December 31, Year Ended December 31, (Dollars in Thousands) 2021 2020 Finance lease cost: Amortization of right-of-use asset $ 1,291 $ 607 Interest on lease liabilities 358 34 Total finance lease cost $ 1,649 $ 641 Operating lease cost 1 $ 23,983 $ 21,983 _______________ 1. Includes $1.4 million and $1.0 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease or both of the years ended December 31, 2021 and December 31, 2020, 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) 2021 2020 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flow for operating leases $ 16,440 $ 15,305 Investing cash flow for operating leases 1 7,543 6,678 Operating cash flow for finance leases 358 34 Financing cash flow for finance leases 1,291 607 Non-cash disclosure upon commencement of new lease Right-of-use assets obtained in exchange for new operating lease liabilities $ 4,820 $ 6,302 Right-of-use assets obtained in exchange for new finance lease liabilities 105,176 — Non-cash disclosure upon modification of existing lease Modification of operating lease right-of-use assets $ 26,287 $ — _______________ 1 Includes $1.4 million and $1.0 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for both of the years ended December 31, 2021 and December 31, 2020, 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 2021 2020 Operating lease right-of-use asset $ 184,957 $ 172,167 Operating leases liabilities current $ 20,398 $ 19,204 Operating lease liabilities long-term 172,510 160,980 Total operating lease liabilities: $ 192,908 $ 180,184 Finance Leases Common plant $ 61,227 $ 881 Electric plant 43,793 — Total finance lease assets $ 105,020 $ 881 Other current liabilities $ 1,742 $ 475 Finance lease liabilities 105,303 320 Total finance lease liabilities $ 107,045 $ 795 Weighted Average Remaining Lease Term Operating leases 22.80 Years 18.97 Years Finance leases 20.15 Years 2.00 Years Weighted Average Discount Rate Operating leases 3.27 % 3.59 % Finance leases 3.07 % 2.98 % The following tables summarize the Company’s estimated future minimum lease payments as of December 31, 2021: Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2022 $ 23,945 $ 4,881 2023 23,717 6,260 2024 23,000 6,286 2025 19,636 6,411 2026 17,126 6,540 Thereafter 164,797 116,553 Total lease payments $ 272,221 $ 146,931 Less imputed interest (79,313) (39,886) Total net present value $ 192,908 $ 107,045

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2021
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 2021 2020 2021 2020 2021 2020 Electric portfolio derivatives * * $ 74,829 $ 22,544 $ 85,424 $ 46,922 Natural gas derivatives (MMBtus) 3 347 320 79,578 19,276 18,850 14,352 Total derivative contracts $ 154,407 $ 41,820 $ 104,274 $ 61,274 Current 128,210 33,015 63,309 31,441 Long-term 26,197 8,805 40,965 29,833 Total derivative contracts $ 154,407 $ 41,820 $ 104,274 $ 61,274 __________ 1. Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments. 2. Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments. 3. All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 238.0 million One Million British Thermal Units (MMBtus) and purchased electricity of 8.1 million megawatt hours (MWhs) at December 31, 2021, and 212.2 million MMBtus and 6.6 million MWhs at December 31, 2020. 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, 2021 (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 $ 154,407 $ — $ 154,407 $ (40,833) $ — $ 113,574 Liabilities: Energy derivative contracts 104,274 — 104,274 (40,833) (1,743) 61,698 Puget Energy and December 31, 2020 (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 $ 41,820 $ — $ 41,820 $ (21,696) $ — $ 20,124 Liabilities Energy Derivative Contracts 61,274 — 61,274 (21,696) (9,343) 30,235 __________ 1. All Derivative Contract deals are executed under ISDA, NAESB, and WSPP master 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 2021 2020 2019 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net $ 26,686 $ 5,534 $ 16,970 Realized Electric generation fuel 76,504 5,246 10,828 Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net (12,901) (32,341) (20,544) Realized Purchased electricity (3,044) (14,958) 48,686 Total gain (loss) recognized in income on derivatives $ 87,245 $ (36,519) $ 55,940 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, 2021, approximately 98.9% of the Company's energy portfolio exposure, excluding NPNS transactions, is with counterparties that are rated investment grade by rating agencies and 1.1% 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, 2021, 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, 2021, PSE had cash posted as collateral of $12.8 million related to contracts executed on the ICE platform. Also, as of December 31, 2021, PSE had $24.0 million in cash posted as collateral and no letter of credit posted as a condition of transacting on the ICE NGX platform. PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades during the twelve months ended December 31, 2021. 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) 2021 2020 Contingent Feature Fair Value 1 Liability Posted Contingent Fair Value 1 Liability Posted Contingent Credit rating 2 $ 52,537 $ — $ 52,537 $ 26,966 $ — $ 26,966 Requested credit for adequate assurance 9,380 — — 6,576 — — Forward value of contract 3 1,743 12,782 N/A 9,343 20,903 N/A Total $ 63,660 $ 12,782 $ 52,537 $ 42,885 $ 20,903 $ 26,966 _______________ 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, 2021
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 $53.2 million and $52.7 million at December 31, 2021, and 2020, 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, 2021 December 31, 2020 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Financial liabilities: Long-term debt (fixed-rate), net of discount 1 2 $ 6,170,466 $ 7,769,896 $ 5,667,740 $ 7,755,946 Long-term debt (variable-rate), net of discount 2 33,300 33,300 224,700 224,700 Total $ 6,203,766 $ 7,803,196 $ 5,892,440 $ 7,980,646 Puget Sound Energy December 31, 2021 December 31, 2020 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Financial liabilities: Long-term debt (fixed-rate), net of discount 2 2 $ 4,784,719 $ 6,145,639 $ 4,338,044 $ 6,086,358 Total $ 4,784,719 $ 6,145,639 $ 4,338,044 $ 6,086,358 _______________ 1. The carrying value includes debt issuances costs of $22.7 million and $22.7 million for December 31, 2021, and 2020, respectively, which are not included in fair value. 2. The carrying value includes debt issuances costs of $22.8 million and $22.9 million for December 31, 2021, and 2020, 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, 2021 December 31, 2020 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric Derivative Instruments $ 68,011 $ 6,818 $ 74,829 $ 21,947 $ 597 $ 22,544 Gas Derivative Instruments 79,526 52 79,578 19,139 137 19,276 Total derivative assets $ 147,537 $ 6,870 $ 154,407 $ 41,086 $ 734 $ 41,820 Liabilities: Electric Derivative Instruments $ 35,854 $ 49,570 $ 85,424 $ 22,607 $ 24,315 $ 46,922 Gas Derivative Instruments 16,678 2,172 18,850 13,080 1,272 14,352 Total derivative liabilities $ 52,532 $ 51,742 $ 104,274 $ 35,687 $ 25,587 $ 61,274 Puget Energy and Year Ended December 31, Level 3 Roll-Forward Net Asset(Liability) 2021 2020 2019 (Dollars in Thousands) Electric Natural Gas Total Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ (23,718) $ (1,135) $ (24,853) $ (3,379) $ 1,282 $ (2,097) $ 1,362 $ 1,673 $ 3,035 Changes during period: Realized and unrealized energy derivatives Included in earnings 1 (15,839) — (15,839) (23,559) — (23,559) 3,558 — 3,558 Included in regulatory assets / liabilities — (1,749) (1,749) — (1,049) (1,049) — 3,151 3,151 Settlements 2 (3,195) 764 (2,431) 3,220 (1,368) 1,852 (11,265) (4,708) (15,973) Transferred into Level 3 — — — — — — 4,390 (398) 3,992 Transferred out Level 3 — — — — — $ — (1,424) 1,564 $ 140 Balance at end of period $ (42,752) $ (2,120) $ (44,872) $ (23,718) $ (1,135) $ (24,853) $ (3,379) $ 1,282 $ (2,097) __________________ 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 $(21.6) million, $(21.3) million and $(3.2) million for the years ended December 31, 2021, 2020, and 2019, respectively. 2. The Company had no purchases or sales of options during the reported periods. Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company's consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company's consolidated statements of income. In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company's commodity contracts extend beyond what is considered observable as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next, and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month and reported in the Level 3 Roll-forward table above. The Company did not have any transfers between Level 2 and Level 1 during the years ended December 31, 2021, 2020, and 2019. 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, 2021: Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Electricity $ 6,818 $ 49,570 Discounted cash flow Power Prices (per MWh) $ 21.88 $ 119.38 $ 61.51 Natural Gas $ 52 $ 2,172 Discounted cash flow Natural Gas Prices (per MMBtu) $ 3.65 $ 7.54 $ 5.89 _______________ 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, 2021, 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 $17.9 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 2021 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: 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, 2021
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 $23.6 million, $22.1 million and $21.7 million for the years 2021, 2020, and 2019, 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, 2021
Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Retirement Benefits	Retirement Benefits PSE has a defined benefit pension plan (Qualified Pension Benefits) covering a substantial majority of PSE employees. For employees hired prior to 2014, pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates. Effective January 1, 2014, all new UA represented employees hired or rehired receive annual pay credits of 4.0% of eligible pay each year in the cash balance formula of the defined pension plan. Effective January 1, 2014 for non-represented employees, and December 12, 2014 for employees represented by the IBEW, newly hired or rehired employees receive annual employer contributions of 4.0% of eligible play each year into the cash balance formula of the defined benefit pension or 401k plan account. PSE also has a non-qualified Supplemental Executive Retirement Plan (SERP) for certain key senior management employees that closed to new participants in 2019. Effective 2019, PSE has an officer restoration benefit for new officers who join PSE or are promoted, such that company contributions under PSE’s applicable tax-qualified plan, which otherwise would have been credited if not for IRS limitations, are credited at 4.0% of earnings to an account with the Deferred Compensation Plan. In addition to providing pension benefits, PSE provides legacy group health care and life insurance benefits (Other Benefits) for certain retired employees. These benefits are provided principally through an insurance company. The insurance premiums, paid primarily by retirees, are based on the benefits provided during the prior year. On June 11, 2019, the Company's Welfare Benefits Committee approved the termination of the Plan effective December 31, 2019, and the creation of a Retiree Health Reimbursement Account (HRA) Plan effective January 1, 2020. Puget Energy's retirement plans were remeasured as a result of the merger in 2009, which represents the difference between Puget Energy and PSE's retirement plans. The components of service cost are included within utility operations and maintenance for PSE and within non-utility expense and other for Puget Energy while all non-service cost components are included in other income. The following tables summarize the Company’s change in benefit obligation, change in plan assets and amounts recognized in the Statements of Financial Position for the years ended December 31, 2021, and 2020: Puget Energy and Qualified SERP Other (Dollars in Thousands) 2021 2020 2021 2020 2021 2020 Change in benefit obligation: Benefit obligation at beginning of period $ 849,383 $ 774,305 $ 46,742 $ 63,000 $ 12,114 $ 11,627 Amendments — — — — 205 44 Service cost 26,888 24,337 456 756 155 190 Interest cost 22,381 25,180 1,183 1,464 302 368 Actuarial loss (gain) (6,826) 69,413 828 3,663 (514) 604 Benefits paid (55,831) (42,775) (6,054) (22,141) (803) (906) Medicare part D subsidy received — — — — 195 187 Administrative expense (1,035) (1,077) — — — — Benefit obligation at end of period $ 834,960 $ 849,383 $ 43,155 $ 46,742 $ 11,654 $ 12,114 Puget Energy and Qualified SERP Other (Dollars in Thousands) 2021 2020 2021 2020 2021 2020 Change in plan assets: Fair value of plan assets at beginning of period $ 834,655 $ 753,042 $ — $ — $ 5,918 $ 6,289 Actual return on plan assets 102,787 107,409 — — 1,005 278 Employer contribution 18,000 18,000 6,054 22,141 222 257 Benefits paid (55,831) (42,775) (6,054) (22,141) (804) (906) Administrative expense (1,061) (1,021) — — — — Fair value of plan assets at end of period $ 898,550 $ 834,655 $ — $ — $ 6,341 $ 5,918 Funded status at end of period $ 63,590 $ (14,728) $ (43,155) $ (46,742) $ (5,313) $ (6,196) Puget Energy and Qualified SERP Other (Dollars in Thousands) 2021 2020 2021 2020 2021 2020 Amounts recognized in Consolidated Balance Sheet consist of: Noncurrent assets $ 63,590 $ — $ — $ — $ — $ — Current liabilities — — (2,822) (6,763) (280) (293) Noncurrent liabilities — (14,728) (40,333) (39,979) (5,033) (5,903) Net assets (liabilities) $ 63,590 $ (14,728) $ (43,155) $ (46,742) $ (5,313) $ (6,196) Puget Energy and Qualified SERP Other (Dollars in Thousands) 2021 2020 2021 2020 2021 2020 Change in plan obligation and plan asset: Projected benefit obligation $ 834,960 $ 849,383 $ 43,155 $ 46,742 $ 11,654 $ 12,114 Accumulated benefit obligation 823,418 837,455 40,773 44,033 11,549 12,070 Fair value of plan assets 898,550 834,655 — — 6,341 5,918 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, 2021, and 2020: Puget Energy Qualified SERP Other (Dollars in Thousands) 2021 2020 2021 2020 2021 2020 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 24,859 $ 98,010 $ 9,571 $ 11,738 $ (525) $ 600 Prior service cost (credit) — (1,904) 578 927 242 44 Total $ 24,859 $ 96,106 $ 10,149 $ 12,665 $ (283) $ 644 Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2021 2020 2021 2020 2021 2020 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 127,111 $ 210,317 $ 10,103 $ 12,504 $ (622) $ 489 Prior service cost (credit) — (1,513) 578 927 242 44 Total $ 127,111 $ 208,804 $ 10,681 $ 13,431 $ (380) $ 533 The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, 2021, 2020, and 2019. Puget Energy Qualified SERP Other (Dollars in Thousands) 2021 2020 2019 2021 2020 2019 2021 2020 2019 Components of net periodic benefit cost: Service cost $ 26,888 $ 24,337 $ 22,656 $ 456 $ 756 $ 1,023 $ 155 $ 190 $ 61 Interest cost 22,381 25,180 28,913 1,183 1,464 2,314 302 368 410 Expected return on plan assets (48,239) (49,902) (50,249) — — — (355) (389) (393) Amortization of prior service cost (credit) (1,904) (1,980) (1,980) 349 349 331 6 — — Amortization of net loss (gain) 11,803 8,160 1,151 2,165 2,122 1,365 (39) (82) (374) Net periodic benefit cost $ 10,929 $ 5,795 $ 491 $ 4,153 $ 4,691 $ 5,033 $ 69 $ 87 $ (296) Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2021 2020 2019 2021 2020 2019 2021 2020 2019 Components of net periodic benefit cost: Service cost $ 26,888 $ 24,337 $ 22,656 $ 456 $ 756 $ 1,023 $ 155 $ 190 $ 61 Interest cost 22,381 25,180 28,913 1,183 1,464 2,314 302 368 410 Expected return on plan assets (48,242) (49,910) (50,267) — — — (355) (389) (393) Amortization of prior service cost (credit) (1,513) (1,573) (1,573) 349 349 333 6 — — Amortization of net loss (gain) 21,862 19,043 12,877 2,344 2,385 1,733 (52) (137) (562) Net periodic benefit cost $ 21,376 $ 17,077 $ 12,606 $ 4,332 $ 4,954 $ 5,403 $ 56 $ 32 $ (484) The following tables summarize Puget Energy's and PSE's benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, 2021, and 2020: Puget Energy Qualified SERP Other (Dollars in Thousands) 2021 2020 2021 2020 2021 2020 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ (61,348) $ 11,851 $ 828 $ 3,663 $ (1,164) $ 715 Amortization of net (loss) gain (11,803) (8,160) (2,164) (2,122) 39 82 Settlements, mergers, sales, and closures — — (830) (4,806) — — Prior service cost (credit) — — — — 205 44 Amortization of prior service (cost) credit 1,904 1,980 (349) (349) (6) — Total change in other comprehensive income for year $ (71,247) $ 5,671 $ (2,515) $ (3,614) $ (926) $ 841 Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2021 2020 2021 2020 2021 2020 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ (61,345) $ 11,858 $ 828 $ 3,663 $ (1,164) $ 715 Amortization of net (loss) gain (21,862) (19,043) (2,343) (2,385) 53 137 Settlements, mergers, sales, and closures — — (886) (5,248) — — Prior service cost (credit) — — — — 205 44 Amortization of prior service (cost) credit 1,513 1,573 (349) (349) (6) — Total change in other comprehensive income for year $ (81,694) $ (5,612) $ (2,750) $ (4,319) $ (912) $ 896 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, 2022, are expected to be at least $18.0 million, $2.8 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 2021 2020 2019 2021 2020 2019 2021 2020 2019 Discount rate 3.00 % 2.70 % 3.35 % 3.00 % 2.70 % 3.35 % 3.00 % 2.70 % 3.35 % Rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Interest crediting rate 4.00 4.00 4.00 N/A N/A N/A N/A N/A N/A Benefit Cost Assumptions Discount rate 2.70 3.35 4.40 2.70 3.35 4.40 2.70 3.35 4.40 Return on plan assets 6.50 7.15 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 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 $6.8 million in 2021. This is primarily due to the decrease in the discount rate used in measuring the benefit obligation. 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. 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) 2022 2023 2024 2025 2026 2027-2031 Qualified Pension total benefits $ 46,900 $ 47,900 $ 49,100 $ 50,400 $ 51,300 $ 265,200 SERP Pension total benefits 2,822 3,881 6,786 7,796 2,265 17,047 Other Benefits total with Medicare Part D subsidy 962 925 896 877 860 4,012 Other Benefits total without Medicare Part D subsidy 962 925 896 877 860 4,012 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, 2021, and 2020: Recurring Fair Value Measures Recurring Fair Value Measures December 31, 2021 December 31, 2020 (Dollars in Thousands) Level 1 Level 2 Other Total Level 1 Level 2 Other Total Assets: Common Stock – Domestic $ 249,021 $ 99 $ — $ 249,120 $ 228,247 $ 53 $ — $ 228,300 – Foreign 25,963 — — 25,963 19,216 — — 19,216 Government Securities 65,266 2,470 — 67,736 73,006 9,148 — 82,154 Corporate Securities – Domestic — 12,820 — 12,820 — 6,082 — 6,082 – Foreign — 5,239 — 5,239 — 3,699 — 3,699 Cash and cash equivalents 3,638 (540) — 3,098 4,612 3,223 — 7,835 Investments measured at NAV - Collective Investment Funds — — 359,861 359,861 — — 342,014 342,014 - Partnership — — 115,570 115,570 — — 107,137 107,137 - Mutual Funds — — 80,724 80,724 — — 82,103 82,103 - Other — — 1,434 1,434 — — 1,096 1,096 Net (payable) receivable — — (23,015) (23,015) — — (44,981) (44,981) Total assets $ 343,888 $ 20,088 $ 534,574 $ 898,550 $ 325,081 $ 22,205 $ 487,369 $ 834,655 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, 2021 December 31, 2020 (Dollars in Thousands) Level 1 Level 2 Other Total Level 1 Level 2 Other Total Assets: Money Markets $ 4 $ — $ — $ 4 $ — $ — $ — $ — Mutual fund — 6,337 — 6,337 5,916 — — 5,916 Net (payable) receivable — — — — — — 2 2 Total assets $ 4 $ 6,337 $ — $ 6,341 $ 5,916 $ — $ 2 $ 5,918 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, 2021
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) 2021 2020 2019 Charged to operating expenses: Current: Federal $ 25,395 $ 7,962 $ 9,424 State 721 7 164 Deferred: Federal (1,759) (6,414) 7,357 State 158 109 128 Total income tax expense $ 24,515 $ 1,664 $ 17,073 Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2021 2020 2019 Charged to operating expenses: Current: Federal $ 52,616 $ 10,607 $ 18,093 State 670 383 570 Deferred: Federal (9,027) 15,252 20,485 State — — — Total income tax expense $ 44,259 $ 26,242 $ 39,148 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) 2021 2020 2019 Income taxes at the statutory rate $ 59,927 $ 38,720 $ 47,834 Increase (decrease): Utility plant differences 1 $ (22,325) $ (22,991) $ (23,025) AFUDC, net 1,509 (6,095) (4,462) Executive compensation 1,386 2,440 2,596 Treasury grant amortization (5,424) (8,935) (7,870) Excess deferred tax amortization (13,392) (3,038) — Other–net 2,834 1,563 2,000 Total income tax expense $ 24,515 $ 1,664 $ 17,073 Effective tax rate 8.6 % 0.9 % 7.5 % Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2021 2020 2019 Income taxes at the statutory rate $ 79,868 $ 63,110 $ 69,735 Increase (decrease): Utility plant differences 1 $ (22,325) $ (22,991) $ (23,025) AFUDC, net 1,509 (6,095) (4,462) Executive compensation 1,386 2,440 2,596 Treasury grant amortization (5,424) (8,935) (7,870) Excess deferred tax amortization (13,392) (3,038) — Other–net 2,637 1,751 2,174 Total income tax expense $ 44,259 $ 26,242 $ 39,148 Effective tax rate 11.6 % 8.7 % 11.8 % _______________ 1. Utility plant differences include the reversal of excess deferred taxes using the average rate assumption method in the amount of $27.6 million in both 2021 and 2020. The Company’s net deferred tax liability at December 31, 2021, and 2020, is composed of amounts related to the following types of temporary differences: Puget Energy At December 31, (Dollars in Thousands) 2021 2020 Utility plant and equipment $ 1,892,674 $ 1,923,933 Other deferred tax liabilities 202,783 175,333 Subtotal deferred tax liabilities 2,095,457 2,099,266 Net operating loss carryforward (254,007) (261,260) Net regulatory liability for income taxes (865,976) (953,274) Production tax credit carryforward — (35,995) Other deferred tax assets (62,990) (38,008) Subtotal deferred tax assets (1,182,973) (1,288,537) Total net deferred tax liabilities $ 912,484 $ 810,729 Puget Sound Energy At December 31, (Dollars in Thousands) 2021 2020 Utility plant and equipment $ 1,892,674 $ 1,923,933 Other, net deferred tax liabilities 121,060 91,438 Subtotal deferred tax liabilities 2,013,734 2,015,371 Net regulatory liability for income taxes (866,541) (953,987) Production tax credit carryforward — (35,995) Other deferred tax assets (62,990) (38,007) Subtotal deferred tax assets (929,531) (1,027,989) Total net deferred tax liabilities $ 1,084,203 $ 987,382 The Company calculates its deferred tax assets and liabilities under ASC 740, “Income Taxes” (ASC 740). ASC 740 requires recording deferred tax balances, at the currently enacted tax rate, on assets and liabilities that are reported differently for income tax purposes than for financial reporting purposes. The utilization of deferred tax assets requires sufficient taxable income in future years. ASC 740 requires a valuation allowance on deferred tax assets when it is more likely than not that the deferred tax assets will not be realized. PSE fully utilized it’s PTC balance in 2021 and has no carryforwards at the end of 2021. Puget Energy’s net operating loss carryforwards expire from 2029 through 2037. Net operating losses generated in 2018 and thereafter have no expiration date. No valuation allowance has been provided for net operating loss carryforwards. Unrecognized Tax Benefits The Company accounts for uncertain tax positions under ASC 740, which clarifies the accounting for uncertainty in income taxes recognized in the financial statements. ASC 740 requires the use of a two-step approach for recognizing and measuring tax positions taken or expected to be taken in a tax return. First, a tax position should only be recognized when it is more likely than not, based on technical merits, that the position will be sustained upon challenge by the taxing authorities and taken by management to the court of last resort. Second, a tax position that meets the recognition threshold should be measured at the largest amount that has a greater than 50.0% likelihood of being sustained. As of December 31, 2021, and 2020, the Company had no material unrecognized tax benefits. As a result, no interest or penalties were accrued for unrecognized tax benefits during the year. On July 30, 2021, the IRS issued a PLR to PSE which concluded that the Washington Commission’s methodology for reversing plant-related excess deferred income taxes was an impermissible methodology under the IRS normalization and consistency rules. The PLR requires adjustments to PSE's rates to bring PSE back into compliance with IRS rules. Accordingly, on September 28, 2021, the Washington Commission issued an order amending their previous order to correct the impermissible methodology and adjust customer rates in accordance with the PLR. For more information, see Note 4, "Regulation and Rates," to the consolidated financial statements included in Item 8 of this report. The Company has open tax years from 2018 through 2021. The Company classifies interest as interest expense and penalties as other expense in the financial statements.

Litigation

Litigation	12 Months Ended
	Dec. 31, 2021
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. As part of a settlement that was signed by all Colstrip owners, Colstrip Units 1 and 2 owners, PSE and Talen Energy Corporation (Talen), agreed to retire the two oldest units (Units 1 and 2) at Colstrip no later than July 1, 2022. Depreciation rates were updated in the 2017 GRC, 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 2017 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. Talen permanently shut down Units 1 and 2 on 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. 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. On May 4, 2021, PSE along with the Colstrip owners, Avista Corporation, PacifiCorp and Portland General Electric filed a lawsuit against the state of Montana after Montana Governor Greg Gianforte signed Senate Bill 265 and 266 into law. The litigation challenged the constitutionality of Senate Bill 266. On October 13, 2021, the United States District Court for the District of Montana issued a preliminary injunction finding it likely that Senate Bill 266 unconstitutionally violates the commerce clause of the United States Constitution. Since then, a motion was filed requesting that the findings of the preliminary injunction be made permanent. As of December 31, 2021, the Company is not able to predict the outcome, nor an amount or range of potential impact in the event of an outcome that is adverse to the Company’s interests. Puget LNG In January 2018, the 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. In December 2019, PSCAA issued the air quality permit for the facility, a decision which was appealed to the Washington Pollution Control Hearings Board (PCHB) by each of the Puyallup Tribe of Indians and nonprofit law firm Earthjustice. In November 2021, the PCHB affirmed the PSCAA ruling in PSE's favor. In December 2021, the PCHB decision was appealed with the Pierce County Superior Court by each of the Puyallup Tribe of Indians and nonprofit law firm Earthjustice. The appeal did not delay commissioning at the plant, which was completed on February 1, 2022. Puget LNG is expected to commence commercial operations in 2022. 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 being held 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 August 2018, the EPA proposed the Affordable Clean Energy (ACE) rule, pursuant to Section 111(d) of the Clean Air Act. The ACE rule was finalized in June 2019, and establishes 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 it misinterpreted the Clean Air Act. That matter is now pending before the US Supreme Court. Washington Clean Air Rule The Washington Clean Air Rule (CAR) was adopted by the state of Washington’s Department of Ecology in September 2016 and was intended to reduce greenhouse gas emissions from “covered entities” located within Washington, including large manufacturers, petroleum producers and natural gas utilities, including PSE. In September 2016, PSE, along with Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed lawsuits in both the U.S. District Court for the Eastern District of Washington and in the Superior Court of the State of Washington for Thurston County challenging the CAR. In March 2018, the Superior Court of the State of Washington for Thurston County invalidated the CAR. After an appeal by the Washington Department of Ecology, 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, and 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; the Department of Ecology has asked 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, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies For the year ended December 31, 2021, approximately 13.3% of the Company’s energy output was obtained at an average cost of approximately $0.034 per Kilowatt Hour (kWh) through long-term contracts with three of the Washington Public Utility Districts (PUDs) that own hydroelectric projects on the Columbia River. The purchase of power from the Columbia River projects is on a pro rata share basis under which the Company pays a proportionate share of the annual debt service, operating and maintenance costs and other expenses associated with each project, in proportion to the contractual share of power that PSE obtains from that project. In these instances, PSE’s payments are not contingent upon the projects being operable; therefore, PSE is required to make the payments even if power is not delivered. These projects are financed substantially through debt service payments and their annual costs should not vary significantly over the term of the contracts unless additional financing is required to meet the costs of major maintenance, repairs or replacements, or license requirements. The Company’s share of the costs and the output of the projects is subject to reduction due to various withdrawal rights of the PUDs and others over the contract lives. The Company's expenses under these PUD contracts were as follows for the years ended December 31, : (Dollars in Thousands) 2021 2020 2019 PUD contract costs $ 117,812 $ 116,874 $ 87,135 As of December 31, 2021, 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 2022 Costs 2022 Debt Service Costs Interest included in 2022 Debt Service Costs Debt Outstanding Chelan County PUD: Rock Island Project 2031 30.0 % 187 $ 43,568 $ 12,074 $ 5,484 $ 99,510 Rocky Reach Project 2031 30.0 390 43,942 5,056 2,090 36,723 Douglas County PUD: Wells Project 1 2028 31.1 261 43,095 — — — Grant County PUD: Priest Rapids Development 2052 0.6 6 1,749 894 450 11,276 Wanapum Development 2052 0.6 7 1,749 894 450 11,276 Total 851 $ 134,103 $ 18,918 $ 8,474 $ 158,785 _______________ 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. 2. In March 2021, PSE entered into a new PPA with Chelan County PUD for additional Rocky Reach and Rock Island output. The contract begins on January 1, 2022, and continues through December 31, 2026. This agreement increases PSE’s share of output by 5% for each project, which equates to additional capacity of 31MW for Rock Island and 65MW for Rocky Reach. 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) 2022 2023 2024 2025 2026 Thereafter Total Columbia River projects $ 151,378 $ 136,635 $ 134,188 $ 124,724 $ 123,243 $ 421,272 $ 1,091,440 Electric portfolio contracts 330,189 377,331 384,655 344,021 142,903 1,755,102 3,334,201 Electric wholesale market transactions 300,027 62,821 62,761 11,616 11,616 — 448,841 Total $ 781,594 $ 576,787 $ 581,604 $ 480,361 $ 277,762 $ 2,176,374 $ 4,874,482 Total purchased power contracts provided the Company with approximately 13.1 million, 13.2 million and 12.5 million MWhs of firm energy at a cost of approximately $631.4 million, $491.7 million and $550.6 million for the years 2021, 2020, and 2019, respectively. Natural Gas Supply Obligations The Company has entered into various firm supply, transportation and storage service contracts in order to ensure adequate availability of natural gas supply for its customers and generation requirements. The Company contracts for its long-term natural gas supply on a firm basis, which means the Company has a 100% daily take obligation and the supplier has a 100% daily delivery obligation to ensure service to PSE’s customers and generation requirements. The transportation and storage contracts, which have remaining terms from 1 to 23 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. The Company incurred demand charges of $136.4 million, $135.8 million, and $125.1 million for firm transportation, storage and peaking services for its natural gas customers for the years 2021, 2020, and 2019. The Company incurred demand charges of $52.8 million, $51.2 million, and $51.2 million for firm transportation, storage and peaking services for the natural gas supply for its combustion turbines for the years 2021, 2020, and 2019. 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 Canadian Energy Regulator currently authorized rates, which are subject to change. Natural Gas Supply and Demand Charge Obligations 2022 2023 2024 2025 2026 Thereafter Total Natural gas wholesale market transactions $ 564,580 $ 299,400 $ 210,198 $ 153,054 $ 98,725 $ — $ 1,325,957 Firm transportation service 177,185 166,153 131,611 114,470 98,847 694,279 1,382,545 Firm storage service 8,899 2,270 68 67 56 — 11,360 Total $ 750,664 $ 467,823 $ 341,877 $ 267,591 $ 197,628 $ 694,279 $ 2,719,862 Service Contracts The following table summarizes the Company’s estimated obligations for service contracts through the terms of its existing contracts. Service Contract Obligations 2022 2023 2024 2025 2026 Thereafter Total Energy production service contracts $ 31,167 $ 31,916 $ 32,699 $ 33,468 $ 17,087 $ 81,854 $ 228,191 Automated meter reading system 46,455 47,517 47,526 48,249 49,098 — 238,845 Total $ 77,622 $ 79,433 $ 80,225 $ 81,717 $ 66,185 $ 81,854 $ 467,036 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, 2021
Related Party Transactions [Abstract]
Related Party Transactions	Related Party TransactionsThe Company identified no material related party transactions during the year ended December 31, 2021 and December 31, 2020.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2021
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, 2021
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, 2021, 2020, and 2019, 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, 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) Other comprehensive income (loss) before reclassifications 49,226 49,226 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 9,779 9,779 Net current-period other comprehensive income (loss) 59,005 59,005 Balance at December 31, 2021 $ (27,432) $ (27,432) 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, 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) Other comprehensive income (loss) before reclassifications 49,265 — 49,265 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 18,166 384 18,550 Net current-period other comprehensive income (loss) 67,431 384 67,815 Balance at December 31, 2021 $ (108,541) $ (4,600) $ (113,141) Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2021, 2020, and 2019, 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 2021 2020 2019 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,549 $ 1,631 $ 1,648 Amortization of net gain (loss) (a) (13,928) (10,200) (2,142) Total before tax (12,379) (8,569) (494) Tax (expense) or benefit 2,600 1,799 104 Net of tax (9,779) (6,770) (390) Total reclassification for the period Net of tax $ (9,779) $ (6,770) $ (390) __________ (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 2021 2020 2019 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,158 $ 1,224 $ 1,240 Amortization of net gain (loss) (a) (24,153) (21,291) (14,048) Total before tax (22,995) (20,067) (12,808) Tax (expense) or benefit 4,829 4,214 2,690 Net of tax (18,166) (15,853) (10,118) Net unrealized gain (loss) on treasury interest rate swaps: Interest rate contracts Interest expense (487) (487) (487) Tax (expense) or benefit 103 102 102 Net of tax (384) (385) (385) Total reclassification for the period Net of tax $ (18,550) $ (16,238) $ (10,503) ____________ (a) These AOCI components are included in the computation of net periodic pension cost, see Note 13, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.

SCHEDULE I CONDENSED FINANCIAL

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY	12 Months Ended
	Dec. 31, 2021
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, 2021 2020 2019 Non-utility expense and other $ (913) $ (1,579) $ (1,495) Other income (deductions): Equity in earnings of subsidiary 337,405 277,654 294,724 Interest income 4,261 4,760 6,643 Interest expense (100,002) (123,592) (111,716) Income tax benefit (expense) 20,098 25,474 22,552 Net income (loss) $ 260,849 $ 182,717 $ 210,708 Comprehensive income (loss) $ 319,854 $ 180,429 $ 203,761 See accompanying notes to the condensed financial statements. Puget Energy Condensed Balance Sheets (Dollars in Thousands) December 31, 2021 2020 Assets: Investment in subsidiaries $ 4,446,758 $ 4,279,501 Other property and investments: Goodwill 1,656,513 1,656,513 Current assets: Cash 6,386 790 Receivables from affiliates 1 233,258 211,411 Income tax receivables 6,006 — Total current assets 245,650 212,201 Long-term assets: Deferred income taxes 250,820 258,033 Other 984 1,520 Total long-term assets 251,804 259,553 Total assets $ 6,600,725 $ 6,407,768 Capitalization and liabilities: Common equity $ 4,563,316 $ 4,139,882 Long-term debt 1,571,287 1,714,744 Total capitalization 6,134,603 5,854,626 Current liabilities: Accounts payable to affiliates 1 147 349 Accrued taxes — 3,334 Current maturities of long-term debt 450,000 524,000 Interest 15,975 25,459 Total current liabilities 466,122 553,142 Commitments and contingencies (Note 16) Total capitalization and liabilities $ 6,600,725 $ 6,407,768 _______________ 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, 2021 2020 2019 Operating activities: Net cash provided by (used in) operating activities $ 143,691 $ 38,280 $ 68,724 Investing activities: Investment in subsidiaries (21,783) — (210,000) (Increase) decrease in loan to subsidiary — (31,043) (41,708) Net cash provided by (used in) investing activities (21,783) (31,043) (251,708) Financing activities: Dividends paid (106,420) (45,421) (64,220) Investment from Parent 210,000 4,575 — Issuance of long-term debts 515,475 644,690 246,200 Redemption of long-term debts (734,000) (609,400) — Issue costs and others (1,367) (1,838) (116) Net cash provided by (used in) by financing activities (116,312) (7,394) 181,864 Increase (decrease) in cash 5,596 (157) (1,120) Cash at beginning of year 790 947 2,067 Cash at end of year $ 6,386 $ 790 $ 947 See accompanying notes to the condensed financial statements. NOTES TO CONDENSED FINANCIAL STATEMENTS (1) Basis of Presentation Puget Energy is an energy services holding company that conducts substantially all of its business operations through its regulated subsidiary, PSE. Puget Energy also has a wholly-owned non-regulated subsidiary, named Puget LNG, LLC (Puget LNG). Puget LNG was formed in November 2016, and has the sole purpose of owning, developing and financing the non-regulated activity of a liquefied natural gas (LNG) facility at the Port of Tacoma, Washington. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These financial statements, in which Puget Energy’s subsidiaries have been included using the equity method, should be read in conjunction with the consolidated financial statements and notes thereto of Puget Energy included in Item 8, "Financial Statements and Supplementary Data" of this report. Puget Energy owns 100% of the common stock of its subsidiaries. Equity earnings of subsidiary included earnings from PSE and PLNG of $335.0 million, $274.3 million and $292.9 million for the years ended December 31, 2021, 2020, and 2019, respectively, and business combination accounting adjustments under ASC 805 recorded at Puget Energy for PSE of $2.4 million, $3.4 million and $2.9 million for the years ended December 31, 2021, 2020, and 2019, respectively. Investment in subsidiaries includes Puget Energy business combination accounting adjustments under ASC 805 that are recorded at Puget Energy. (2) Long-Term Debt For information concerning Puget Energy’s long-term debt obligations, see Note 7, "Long-Term Debt" to the consolidated financial statements included in Item 8 of this report. (3) Commitments and Contingencies For information concerning Puget Energy’s material contingencies and guarantees, see Note 16, "Commitments and Contingencies" to the consolidated financial statements included in Item 8 of this report.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Puget Energy is an energy services holding company that owns Puget Sound Energy (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma liquefied natural gas (LNG) facility. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that are incurred by PSE and allocated to Puget LNG are related party transactions by nature. In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any ASC 805, “Business Combinations” (ASC 805) purchase accounting adjustments. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.
Utility Plant	Utility Plant Puget Energy and PSE capitalize, at original cost, additions to utility plant, including renewals and betterments. Costs include indirect costs such as engineering, supervision, certain taxes, pension and other employee benefits and an allowance for funds used during construction (AFUDC). Replacements of minor items of property are included in maintenance expense. When the utility plant is retired and removed from service, the original cost of the property is charged to accumulated depreciation and costs associated with removal of the property, less salvage, are charged to the cost of removal regulatory liability. Planned Major Maintenance Planned major maintenance is an activity that typically occurs when PSE overhauls or substantially upgrades various systems and equipment on a scheduled basis. Costs related to planned major maintenance are deferred and amortized to the next scheduled major maintenance. This accounting method also follows the Washington Utilities and Transportation Commission (Washington Commission) regulatory treatment related to these generating facilities. Other Property and Investments For PSE, the costs of other property and investments (i.e., non-utility) are stated at historical cost. Expenditures for refurbishment and improvements that significantly add to productive capacity or extend useful life of an asset are capitalized. Replacements of minor items are expensed on a current basis. Gains and losses on assets sold or retired, which were previously recorded in utility plant, are apportioned between regulatory assets/liabilities and earnings. However, gains and losses on assets sold or retired, not previously recorded in utility plant, are reflected in earnings.
Depreciation and Amortization	Depreciation and Amortization The Company provides for depreciation and amortization on a straight-line basis. Amortization is recorded for intangibles such as regulatory assets and liabilities, computer software and franchises. The annual depreciation provision stated as a percent of a depreciable electric utility plant was 3.4%, 3.5%, and 3.4% in 2021, 2020, and 2019, respectively; depreciable natural gas utility plant was 2.8%, 2.9%, and 2.8% in 2021, 2020, and 2019, respectively; and depreciable common utility plant was 6.8%, 7.3% and 7.3% in 2021, 2020, and 2019, 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 $268.5 million, $240.8 million and $236.5 million for 2021, 2020, and 2019, respectively. The Company reports the collection of such taxes on a gross basis in operation revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income. PSE's electric and natural gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, natural gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. The mechanism mitigates volatility in revenue and gross margin erosion due to weather and energy efficiency. Any differences in revenue are deferred to a regulatory asset for under recovery or regulatory liability for over recovery under alternative revenue recognition standard. Revenue is recognized under this program when deemed collectible within 24 months based on alternative revenue recognition guidance. Decoupled rate increases are effective May 1 of each year subject to a soft rate cap of total revenue for decoupled rate schedules, where rate cap is applied to under-collected revenue and any over-collected revenues are passed back to customers at 100%. Any excess under-recovered revenue above the rate cap will be included in the following year's decoupled rate and the Company will only be able to recognize revenue below the rate cap of total revenue for decoupled rate schedules. For revenue deferrals exceeding the annual rate cap of total revenue for decoupled rate schedules, the Company will assess the excess amount to determine its ability to be collected within 24 months per GAAP rules. The soft rate cap test, which limits the amount of revenues PSE can collect in its annual filings, is 5.0% for natural gas customers and 3.0% for electric customers. The Company will not record any decoupling revenue that is expected to take longer than 24 months to collect following the end of the annual period in which the revenues would have otherwise been recognized. Once determined to be collectible within 24 months, any previously non-recognized amounts will be recognized. Revenues associated with energy costs under the power cost adjustment (PCA) mechanism and purchased gas adjustment (PGA) mechanism are excluded from the decoupling mechanism.
Allowance for Doubtful Accounts	Allowance for Credit Losses 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 at December 31, 2021, and 2020: Puget Energy and (Dollars in Thousands) Year Ended December 31, Allowance for credit losses: 2021 2020 Beginning balance $ 20,080 8,294 Provision for credit loss expense 1 27,204 23,292 Receivables charged-off (12,326) (11,506) Total ending allowance balance $ 34,958 $ 20,080 1 $2.8 million and $0.0 million of provision were deferred as cost specific to COVID-19 in 2021 and 2020, respectively.
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. The cumulative annual cost threshold for deferral of storms under the mechanism is $10.0 million. Additionally, costs may only be deferred if the outage meets the Institute of Electrical and Electronics Engineers (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, 2021 and 2020, $45.6 million and $39.8 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 finance lease liabilities in our consolidated balance sheets. ROU assets represent the right to use an underlying asset for the lease term, and consist of the amount of the initial measurement of the lease liability, any lease payments made to the lessor at or before the commencement date, minus any lease incentives received, and any initial direct costs incurred by the lessee. Lease liabilities represent our obligation to make lease payments arising from the lease and are measured at present value of the lease payments not yet paid, discounted using the discount rate for the lease, determined based on PSE's incremental borrowing rate, at commencement. As most of PSE's leases do not provide an implicit interest rate, PSE uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. For fleet, IT and wind farm leases, this rate is applied using a portfolio approach. The lease terms may include options to extend or terminate the lease when it is reasonably certain that PSE will exercise that option. On the statement of income, operating leases are generally accounted for under a straight-line expense model, while finance leases, which were previously referred to as capital leases, are generally accounted for under a financing model. Consistent with the previous lease guidance, however, the standard allows rate-regulated utilities to recognize expense consistent with the timing of recovery in rates.
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 renewable energy credits to PSE over a term of 20 years. Skookumchuck commenced commercial operation in November 2020. PSE has no equity investment in Skookumchuck but is Skookumchuck’s only customer. Based on the terms of the contract, PSE will receive all of the output of the facility, subject to curtailment rights. PSE has concluded that it is not the primary beneficiary of this VIE since it does not control the commercial and operating activities of the facility. Additionally, PSE does not have the obligation to absorb losses or receive benefits. Therefore, PSE will not consolidate the VIE. Purchased energy of $19.0 million was recognized in purchased electricity on the Company's consolidated statements of income for the year ended December 31, 2021 and $2.7 million is included in accounts payable on the Company's consolidated balance sheet

Accounting Policies (Tables)

Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Accounts Receivable, Allowance for Credit Loss	The following table presents the activity in the allowance for credit losses for accounts receivable at December 31, 2021, and 2020: Puget Energy and (Dollars in Thousands) Year Ended December 31, Allowance for credit losses: 2021 2020 Beginning balance $ 20,080 8,294 Provision for credit loss expense 1 27,204 23,292 Receivables charged-off (12,326) (11,506) Total ending allowance balance $ 34,958 $ 20,080 1 $2.8 million and $0.0 million of provision were deferred as cost specific to COVID-19 in 2021 and 2020, respectively.

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2021
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: 2021 2020 2019 Electric retail $ 2,348,356 $ 2,106,122 $ 2,132,522 Natural gas retail 1,036,411 938,061 870,457 Other 349,365 178,208 308,111 Total revenue from contracts with customers 3,734,132 3,222,391 3,311,090 Alternative revenue programs (31,510) 35,006 (18,634) Other non-customer revenue 103,039 69,053 108,674 Total operating revenue $ 3,805,661 $ 3,326,450 $ 3,401,130
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction	Based on management’s best estimate of commencement, the Company expects to recognize this revenue over the following time periods: Puget Energy (Dollars in Thousands) 2024 2025 2026 2027 2028 Thereafter Total Remaining Performance Obligations $ 15,359 19,710 19,454 19,454 19,454 102,135 $ 195,566

Regulation and Rates (Tables)

Regulation and Rates (Tables)	12 Months Ended
	Dec. 31, 2021
Regulatory Assets [Line Items]
Schedule of Net Regulatory Assets and Liabilities	Puget Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2021 2020 Total PSE regulatory assets (a) $ 952,539 $ 918,107 Puget Energy acquisition adjustments: Regulatory assets related to power contracts 4 to 31 years 9,689 11,728 Total Puget Energy regulatory assets 962,228 929,835 Total PSE regulatory liabilities (a) (1,709,461) (1,685,221) Puget Energy acquisition adjustments: Deferred income taxes 565 713 Regulatory liabilities related to power contracts 4 to 31 years (80,934) (95,774) Various other regulatory liabilities Varies (1,264) (1,264) Total Puget Energy regulatory liabilities (1,791,094) (1,781,546) Puget Energy net regulatory asset (liabilities) $ (828,866) $ (851,711) ____________________ (a) Puget Energy’s regulatory assets and liabilities include purchase accounting adjustments under ASC 805.
Subsidiaries [Member]
Regulatory Assets [Line Items]
Schedule of Net Regulatory Assets and Liabilities	The net regulatory assets and liabilities at December 31, 2021, and 2020, are included the following tables: Puget Sound Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2021 2020 Environmental remediation (a) $ 127,977 $ 102,647 Storm damage costs electric 4 years 127,789 108,491 PCA mechanism N/A 79,546 82,801 Decoupling deferrals and interest (b) Less than 2 years 79,125 88,504 Chelan PUD contract initiation 9.8 years 69,699 76,787 Deferred Washington Commission AFUDC 30 years 62,244 59,763 PGA receivable 2 years 57,935 87,655 Baker Dam licensing operating and maintenance costs (c) 54,525 54,354 Lower Snake River 15.4 years 53,757 58,442 Get to zero depreciation expense deferral N/A 50,220 53,236 Unamortized loss on reacquired debt 1 to 46 years 35,805 37,991 Property tax tracker Less than 2 years 25,896 24,860 Advanced metering infrastructure (a) 23,037 22,652 Low Income Program Costs N/A 21,755 — Private Letter Ruling EDIT 1 year 18,850 — Generation plant major maintenance, excluding Colstrip 1 to 8 years 12,094 10,494 Snoqualmie licensing operating and maintenance costs (c) 7,446 7,435 Mint Farm ownership and operating costs 3.3 years 6,318 8,318 Washington Commission electric vehicle N/A 6,109 3,641 Water heater rental property loss N/A 5,725 6,973 Colstrip major maintenance (d) 4,035 4,335 Washington Commission COVID-19 N/A 3,657 — Energy conservation costs (a) 3,573 8,009 Various other regulatory assets (a) 15,422 10,719 Total PSE regulatory assets $ 952,539 $ 918,107 Deferred income taxes (e) N/A (866,541) (953,987) Cost of removal (f) (563,129) (508,707) Repurposed production tax credits N/A (134,270) (79,581) PGA unrealized gain N/A (60,728) (4,925) Decoupling liability Less than 2 years (36,506) (16,448) Treasury grants 2 years (22,476) (43,164) Green direct N/A (13,194) (14,313) Gain on Sale Shuffleton N/A (4,892) (11,131) Production tax credits (g) — (47,094) Various other regulatory liabilities (a) (7,725) (5,871) Total PSE regulatory liabilities (1,709,461) (1,685,221) PSE net regulatory assets (liabilities) $ (756,922) $ (767,114) __________________ (a) Amortization periods vary depending on timing of underlying transactions. (b) Decoupling deferrals and interest includes a 24 month GAAP reserve of $3.0 million and $8.0 million for December 31, 2021 and 2020, respectively. (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) For additional information, see Note 14,"Income Taxes" to the consolidated financial statements included in Item 8 of this report. (f) The balance is dependent upon the cost of removal of underlying assets and the life of utility plant. (g) Amortize as PTCs are utilized on PSE's tax return.
Schedule of Graduated Scale of Rate Adjustment Mechanism	Effective January 1, 2017, the following graduated scale is used in the PCA mechanism: Company’s Share Customers' Share Annual Power Cost Variability Over Under Over Under Over or Under Collected by up to $17 million 100 % 100 % — % — % Over or Under Collected by between $17 million - $40 million 35 50 65 50 Over or Under Collected beyond $40 + million 10 10 90 90
Schedule of PGA Receivable Payable	The following table presents the PGA mechanism balances and activity at December 31, 2021 and December 31, 2020: (Dollars in Thousands) At December 31, At December 31, PGA receivable balance and activity 2021 2020 PGA receivable beginning balance $ 87,655 $ 132,766 Actual natural gas costs 364,775 314,792 Allowed PGA recovery (396,236) (363,886) Interest 1,741 3,983 PGA receivable ending balance $ 57,935 $ 87,655

Utility Plant (Tables)

Utility Plant (Tables)	12 Months Ended
	Dec. 31, 2021
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) 2021 2020 2021 2020 Distribution plant 20-65 $ 7,488,629 $ 7,028,731 $ 9,026,042 $ 8,592,720 Production plant 12-90 3,147,987 3,096,092 3,815,599 3,767,014 Transmission plant 43-75 1,556,666 1,494,781 1,663,559 1,601,731 General plant 5-75 746,758 697,501 773,662 726,327 Intangible plant (including capitalized software) 1 3-50 797,691 779,767 788,240 770,317 Plant acquisition adjustment N/A 242,826 242,826 282,792 282,792 Underground storage 25-60 43,391 39,498 56,820 52,927 Liquefied natural gas storage 25-60 12,628 12,628 14,498 14,498 Plant held for future use N/A 46,020 45,929 46,172 46,081 Recoverable Cushion Gas N/A 8,655 8,655 8,655 8,655 Plant not classified N/A 316,933 384,794 316,933 384,794 Finance leases, net of accumulated amortization 2 N/A 105,020 881 105,020 881 Less: accumulated provision for depreciation (4,031,458) (3,671,094) (6,416,246) (6,087,748) Subtotal $ 10,481,746 $ 10,160,989 $ 10,481,746 $ 10,160,989 Construction work in progress 870,204 712,204 870,204 712,204 Net utility plant $ 11,351,950 $ 10,873,193 $ 11,351,950 $ 10,873,193 _______________________ 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, 2021, and 2020, accumulated amortization of finance leases at Puget Energy and PSE was $2.6 million and $1.6 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% $ 339,073 $ — $ (153,950) Frederickson 1 Natural Gas 49.85 63,210 — (18,215) Jackson Prairie Natural Gas 33.34 42,736 471 (10,867) Tacoma LNG Natural Gas various — 484,299 — 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 % $ 597,009 $ — $ (411,887) Frederickson 1 Natural Gas 49.85 69,278 — (24,283) Jackson Prairie Natural Gas 33.34 56,820 471 (24,952) Tacoma LNG Natural Gas various — 239,566 —
Schedule of Asset Retirement Obligations	Puget Energy and Puget Sound Energy December 31, (Dollars in Thousands) 2021 2020 Asset retirement obligation at beginning of the period $ 216,163 $ 181,353 Relief of liability (13,146) (9,647) Revisions in estimated cash flows (46) 38,677 Accretion expense 6,070 5,780 Asset retirement obligation at end of period 1 $ 209,041 $ 216,163 ___________________ 1. Asset retirement obligations include $3.7 million and $7.4 million for Puget LNG held only at Puget Energy as of December 31, 2021, and 2020, respectively.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2021
Long-term Debt, Unclassified [Abstract]
Schedule of Long-Term Debt Instruments	The following table presents outstanding long-term debt due dates and principal amounts, net of debt discount, issuance and other costs and fair value adjustments as of 2021 and 2020: (Dollars in Thousands) December 31, Series Type Due 2021 2020 Puget Sound Energy: 7.150% First Mortgage Bond 2025 $ 15,000 $ 15,000 7.200% First Mortgage Bond 2025 2,000 2,000 7.020% Senior Secured Note 2027 300,000 300,000 7.000% Senior Secured Note 2029 100,000 100,000 3.900% Pollution Control Bond 2031 138,460 138,460 4.000% Pollution Control Bond 2031 23,400 23,400 5.483% Senior Secured Note 2035 250,000 250,000 6.724% Senior Secured Note 2036 250,000 250,000 6.274% Senior Secured Note 2037 300,000 300,000 5.757% Senior Secured Note 2039 350,000 350,000 5.795% Senior Secured Note 2040 325,000 325,000 5.764% Senior Secured Note 2040 250,000 250,000 4.434% Senior Secured Note 2041 250,000 250,000 5.638% Senior Secured Note 2041 300,000 300,000 4.300% Senior Secured Note 2045 425,000 425,000 4.223% Senior Secured Note 2048 600,000 600,000 3.250% Senior Secured Note 2049 450,000 450,000 2.893% Senior Secured Note 2051 450,000 — 4.700% Senior Secured Note 2051 45,000 45,000 * Debt discount, issuance cost and other * (39,141) (35,816) Total PSE long-term debt $ 4,784,719 $ 4,338,044 Puget Energy: * Fair value adjustment of PSE long-term debt * $ (156,849) $ (165,357) * Revolving Credit Agreement 2023 33,300 14,700 * Term Loan Agreement 1 2022 — 210,000 5.625% Senior Secured Note 2 2022 — 450,000 3.650% Senior Secured Note 2025 400,000 400,000 2.379% Senior Secured Note 2028 500,000 — 4.100% Senior Secured Note 2030 650,000 650,000 * Debt discount, issuance cost and other * (7,404) (4,947) Total Puget Energy long-term debt $ 6,203,766 $ 5,892,440 ___________________ * Not Applicable. 1. Term loan in the amount of $210.0 million was paid off on June 23, 2021. 2. 5.625% Senior Secured Note in the amount of $450.0 million was classified on the Balance Sheet as current maturities of long-term debt as of July 31, 2021.
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) 2022 2023 2024 2025 2026 Thereafter Total Maturities of: PSE $ — $ — $ — $ 17,000 $ — $ 4,806,860 $ 4,823,860 Puget Energy 450,000 33,300 — 400,000 — 1,150,000 2,033,300 Total long-term debt $ 450,000 $ 33,300 $ — $ 417,000 $ — $ 5,956,860 $ 6,857,160

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2021
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) 2021 2020 Finance lease cost: Amortization of right-of-use asset $ 1,291 $ 607 Interest on lease liabilities 358 34 Total finance lease cost $ 1,649 $ 641 Operating lease cost 1 $ 23,983 $ 21,983 _______________ 1. Includes $1.4 million and $1.0 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease or both of the years ended December 31, 2021 and December 31, 2020, 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) 2021 2020 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flow for operating leases $ 16,440 $ 15,305 Investing cash flow for operating leases 1 7,543 6,678 Operating cash flow for finance leases 358 34 Financing cash flow for finance leases 1,291 607 Non-cash disclosure upon commencement of new lease Right-of-use assets obtained in exchange for new operating lease liabilities $ 4,820 $ 6,302 Right-of-use assets obtained in exchange for new finance lease liabilities 105,176 — Non-cash disclosure upon modification of existing lease Modification of operating lease right-of-use assets $ 26,287 $ — _______________ 1 Includes $1.4 million and $1.0 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for both of the years ended December 31, 2021 and December 31, 2020, 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 2021 2020 Operating lease right-of-use asset $ 184,957 $ 172,167 Operating leases liabilities current $ 20,398 $ 19,204 Operating lease liabilities long-term 172,510 160,980 Total operating lease liabilities: $ 192,908 $ 180,184 Finance Leases Common plant $ 61,227 $ 881 Electric plant 43,793 — Total finance lease assets $ 105,020 $ 881 Other current liabilities $ 1,742 $ 475 Finance lease liabilities 105,303 320 Total finance lease liabilities $ 107,045 $ 795 Weighted Average Remaining Lease Term Operating leases 22.80 Years 18.97 Years Finance leases 20.15 Years 2.00 Years Weighted Average Discount Rate Operating leases 3.27 % 3.59 % Finance leases 3.07 % 2.98 %
Finance Lease, Liability, Maturity	The following tables summarize the Company’s estimated future minimum lease payments as of December 31, 2021: Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2022 $ 23,945 $ 4,881 2023 23,717 6,260 2024 23,000 6,286 2025 19,636 6,411 2026 17,126 6,540 Thereafter 164,797 116,553 Total lease payments $ 272,221 $ 146,931 Less imputed interest (79,313) (39,886) Total net present value $ 192,908 $ 107,045
Lessee, Operating Lease, Liability, Maturity	The following tables summarize the Company’s estimated future minimum lease payments as of December 31, 2021: Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2022 $ 23,945 $ 4,881 2023 23,717 6,260 2024 23,000 6,286 2025 19,636 6,411 2026 17,126 6,540 Thereafter 164,797 116,553 Total lease payments $ 272,221 $ 146,931 Less imputed interest (79,313) (39,886) Total net present value $ 192,908 $ 107,045
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 2021 2020 Operating lease right-of-use asset $ 184,957 $ 172,167 Operating leases liabilities current $ 20,398 $ 19,204 Operating lease liabilities long-term 172,510 160,980 Total operating lease liabilities: $ 192,908 $ 180,184 Finance Leases Common plant $ 61,227 $ 881 Electric plant 43,793 — Total finance lease assets $ 105,020 $ 881 Other current liabilities $ 1,742 $ 475 Finance lease liabilities 105,303 320 Total finance lease liabilities $ 107,045 $ 795 Weighted Average Remaining Lease Term Operating leases 22.80 Years 18.97 Years Finance leases 20.15 Years 2.00 Years Weighted Average Discount Rate Operating leases 3.27 % 3.59 % Finance leases 3.07 % 2.98 %

Accounting for Derivative Ins_2

Accounting for Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2021
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 2021 2020 2021 2020 2021 2020 Electric portfolio derivatives * * $ 74,829 $ 22,544 $ 85,424 $ 46,922 Natural gas derivatives (MMBtus) 3 347 320 79,578 19,276 18,850 14,352 Total derivative contracts $ 154,407 $ 41,820 $ 104,274 $ 61,274 Current 128,210 33,015 63,309 31,441 Long-term 26,197 8,805 40,965 29,833 Total derivative contracts $ 154,407 $ 41,820 $ 104,274 $ 61,274 __________ 1. Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments. 2. Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments. 3. All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 238.0 million One Million British Thermal Units (MMBtus) and purchased electricity of 8.1 million megawatt hours (MWhs) at December 31, 2021, and 212.2 million MMBtus and 6.6 million MWhs at December 31, 2020.
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, 2021 (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 $ 154,407 $ — $ 154,407 $ (40,833) $ — $ 113,574 Liabilities: Energy derivative contracts 104,274 — 104,274 (40,833) (1,743) 61,698 Puget Energy and December 31, 2020 (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 $ 41,820 $ — $ 41,820 $ (21,696) $ — $ 20,124 Liabilities Energy Derivative Contracts 61,274 — 61,274 (21,696) (9,343) 30,235 __________ 1. All Derivative Contract deals are executed under ISDA, NAESB, and WSPP master 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 2021 2020 2019 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net $ 26,686 $ 5,534 $ 16,970 Realized Electric generation fuel 76,504 5,246 10,828 Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net (12,901) (32,341) (20,544) Realized Purchased electricity (3,044) (14,958) 48,686 Total gain (loss) recognized in income on derivatives $ 87,245 $ (36,519) $ 55,940
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) 2021 2020 Contingent Feature Fair Value 1 Liability Posted Contingent Fair Value 1 Liability Posted Contingent Credit rating 2 $ 52,537 $ — $ 52,537 $ 26,966 $ — $ 26,966 Requested credit for adequate assurance 9,380 — — 6,576 — — Forward value of contract 3 1,743 12,782 N/A 9,343 20,903 N/A Total $ 63,660 $ 12,782 $ 52,537 $ 42,885 $ 20,903 $ 26,966 _______________ 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, 2021
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, 2021 December 31, 2020 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Financial liabilities: Long-term debt (fixed-rate), net of discount 1 2 $ 6,170,466 $ 7,769,896 $ 5,667,740 $ 7,755,946 Long-term debt (variable-rate), net of discount 2 33,300 33,300 224,700 224,700 Total $ 6,203,766 $ 7,803,196 $ 5,892,440 $ 7,980,646 Puget Sound Energy December 31, 2021 December 31, 2020 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Financial liabilities: Long-term debt (fixed-rate), net of discount 2 2 $ 4,784,719 $ 6,145,639 $ 4,338,044 $ 6,086,358 Total $ 4,784,719 $ 6,145,639 $ 4,338,044 $ 6,086,358 _______________ 1. The carrying value includes debt issuances costs of $22.7 million and $22.7 million for December 31, 2021, and 2020, respectively, which are not included in fair value. 2. The carrying value includes debt issuances costs of $22.8 million and $22.9 million for December 31, 2021, and 2020, 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) 2021 2020 2019 (Dollars in Thousands) Electric Natural Gas Total Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ (23,718) $ (1,135) $ (24,853) $ (3,379) $ 1,282 $ (2,097) $ 1,362 $ 1,673 $ 3,035 Changes during period: Realized and unrealized energy derivatives Included in earnings 1 (15,839) — (15,839) (23,559) — (23,559) 3,558 — 3,558 Included in regulatory assets / liabilities — (1,749) (1,749) — (1,049) (1,049) — 3,151 3,151 Settlements 2 (3,195) 764 (2,431) 3,220 (1,368) 1,852 (11,265) (4,708) (15,973) Transferred into Level 3 — — — — — — 4,390 (398) 3,992 Transferred out Level 3 — — — — — $ — (1,424) 1,564 $ 140 Balance at end of period $ (42,752) $ (2,120) $ (44,872) $ (23,718) $ (1,135) $ (24,853) $ (3,379) $ 1,282 $ (2,097) __________________ 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 $(21.6) million, $(21.3) million and $(3.2) million for the years ended December 31, 2021, 2020, and 2019, respectively. 2. The Company had no purchases or sales of options during the reported periods.
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Table Text Block]	Below are the forward price ranges for the Company's commodity contracts, as of December 31, 2021: Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Electricity $ 6,818 $ 49,570 Discounted cash flow Power Prices (per MWh) $ 21.88 $ 119.38 $ 61.51 Natural Gas $ 52 $ 2,172 Discounted cash flow Natural Gas Prices (per MMBtu) $ 3.65 $ 7.54 $ 5.89 _______________ 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: 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, 2021 December 31, 2020 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric Derivative Instruments $ 68,011 $ 6,818 $ 74,829 $ 21,947 $ 597 $ 22,544 Gas Derivative Instruments 79,526 52 79,578 19,139 137 19,276 Total derivative assets $ 147,537 $ 6,870 $ 154,407 $ 41,086 $ 734 $ 41,820 Liabilities: Electric Derivative Instruments $ 35,854 $ 49,570 $ 85,424 $ 22,607 $ 24,315 $ 46,922 Gas Derivative Instruments 16,678 2,172 18,850 13,080 1,272 14,352 Total derivative liabilities $ 52,532 $ 51,742 $ 104,274 $ 35,687 $ 25,587 $ 61,274

Retirement Benefits (Tables)

Retirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021, and 2020: Puget Energy and Qualified SERP Other (Dollars in Thousands) 2021 2020 2021 2020 2021 2020 Change in benefit obligation: Benefit obligation at beginning of period $ 849,383 $ 774,305 $ 46,742 $ 63,000 $ 12,114 $ 11,627 Amendments — — — — 205 44 Service cost 26,888 24,337 456 756 155 190 Interest cost 22,381 25,180 1,183 1,464 302 368 Actuarial loss (gain) (6,826) 69,413 828 3,663 (514) 604 Benefits paid (55,831) (42,775) (6,054) (22,141) (803) (906) Medicare part D subsidy received — — — — 195 187 Administrative expense (1,035) (1,077) — — — — Benefit obligation at end of period $ 834,960 $ 849,383 $ 43,155 $ 46,742 $ 11,654 $ 12,114
Schedule of Changes in Fair Value of Plan Assets	Puget Energy and Qualified SERP Other (Dollars in Thousands) 2021 2020 2021 2020 2021 2020 Change in plan assets: Fair value of plan assets at beginning of period $ 834,655 $ 753,042 $ — $ — $ 5,918 $ 6,289 Actual return on plan assets 102,787 107,409 — — 1,005 278 Employer contribution 18,000 18,000 6,054 22,141 222 257 Benefits paid (55,831) (42,775) (6,054) (22,141) (804) (906) Administrative expense (1,061) (1,021) — — — — Fair value of plan assets at end of period $ 898,550 $ 834,655 $ — $ — $ 6,341 $ 5,918 Funded status at end of period $ 63,590 $ (14,728) $ (43,155) $ (46,742) $ (5,313) $ (6,196)
Schedule of Amounts Recognized in Balance Sheet and Accumulated Other Comprehensive Income	Puget Energy and Qualified SERP Other (Dollars in Thousands) 2021 2020 2021 2020 2021 2020 Amounts recognized in Consolidated Balance Sheet consist of: Noncurrent assets $ 63,590 $ — $ — $ — $ — $ — Current liabilities — — (2,822) (6,763) (280) (293) Noncurrent liabilities — (14,728) (40,333) (39,979) (5,033) (5,903) Net assets (liabilities) $ 63,590 $ (14,728) $ (43,155) $ (46,742) $ (5,313) $ (6,196)
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) 2021 2020 2021 2020 2021 2020 Change in plan obligation and plan asset: Projected benefit obligation $ 834,960 $ 849,383 $ 43,155 $ 46,742 $ 11,654 $ 12,114 Accumulated benefit obligation 823,418 837,455 40,773 44,033 11,549 12,070 Fair value of plan assets 898,550 834,655 — — 6,341 5,918
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, 2021, 2020, and 2019. Puget Energy Qualified SERP Other (Dollars in Thousands) 2021 2020 2019 2021 2020 2019 2021 2020 2019 Components of net periodic benefit cost: Service cost $ 26,888 $ 24,337 $ 22,656 $ 456 $ 756 $ 1,023 $ 155 $ 190 $ 61 Interest cost 22,381 25,180 28,913 1,183 1,464 2,314 302 368 410 Expected return on plan assets (48,239) (49,902) (50,249) — — — (355) (389) (393) Amortization of prior service cost (credit) (1,904) (1,980) (1,980) 349 349 331 6 — — Amortization of net loss (gain) 11,803 8,160 1,151 2,165 2,122 1,365 (39) (82) (374) Net periodic benefit cost $ 10,929 $ 5,795 $ 491 $ 4,153 $ 4,691 $ 5,033 $ 69 $ 87 $ (296)
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, 2021, and 2020: Puget Energy Qualified SERP Other (Dollars in Thousands) 2021 2020 2021 2020 2021 2020 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ (61,348) $ 11,851 $ 828 $ 3,663 $ (1,164) $ 715 Amortization of net (loss) gain (11,803) (8,160) (2,164) (2,122) 39 82 Settlements, mergers, sales, and closures — — (830) (4,806) — — Prior service cost (credit) — — — — 205 44 Amortization of prior service (cost) credit 1,904 1,980 (349) (349) (6) — Total change in other comprehensive income for year $ (71,247) $ 5,671 $ (2,515) $ (3,614) $ (926) $ 841
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 2021 2020 2019 2021 2020 2019 2021 2020 2019 Discount rate 3.00 % 2.70 % 3.35 % 3.00 % 2.70 % 3.35 % 3.00 % 2.70 % 3.35 % Rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Interest crediting rate 4.00 4.00 4.00 N/A N/A N/A N/A N/A N/A Benefit Cost Assumptions Discount rate 2.70 3.35 4.40 2.70 3.35 4.40 2.70 3.35 4.40 Return on plan assets 6.50 7.15 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
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) 2022 2023 2024 2025 2026 2027-2031 Qualified Pension total benefits $ 46,900 $ 47,900 $ 49,100 $ 50,400 $ 51,300 $ 265,200 SERP Pension total benefits 2,822 3,881 6,786 7,796 2,265 17,047 Other Benefits total with Medicare Part D subsidy 962 925 896 877 860 4,012 Other Benefits total without Medicare Part D subsidy 962 925 896 877 860 4,012
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, 2021, and 2020: Recurring Fair Value Measures Recurring Fair Value Measures December 31, 2021 December 31, 2020 (Dollars in Thousands) Level 1 Level 2 Other Total Level 1 Level 2 Other Total Assets: Common Stock – Domestic $ 249,021 $ 99 $ — $ 249,120 $ 228,247 $ 53 $ — $ 228,300 – Foreign 25,963 — — 25,963 19,216 — — 19,216 Government Securities 65,266 2,470 — 67,736 73,006 9,148 — 82,154 Corporate Securities – Domestic — 12,820 — 12,820 — 6,082 — 6,082 – Foreign — 5,239 — 5,239 — 3,699 — 3,699 Cash and cash equivalents 3,638 (540) — 3,098 4,612 3,223 — 7,835 Investments measured at NAV - Collective Investment Funds — — 359,861 359,861 — — 342,014 342,014 - Partnership — — 115,570 115,570 — — 107,137 107,137 - Mutual Funds — — 80,724 80,724 — — 82,103 82,103 - Other — — 1,434 1,434 — — 1,096 1,096 Net (payable) receivable — — (23,015) (23,015) — — (44,981) (44,981) Total assets $ 343,888 $ 20,088 $ 534,574 $ 898,550 $ 325,081 $ 22,205 $ 487,369 $ 834,655
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, 2021 December 31, 2020 (Dollars in Thousands) Level 1 Level 2 Other Total Level 1 Level 2 Other Total Assets: Money Markets $ 4 $ — $ — $ 4 $ — $ — $ — $ — Mutual fund — 6,337 — 6,337 5,916 — — 5,916 Net (payable) receivable — — — — — — 2 2 Total assets $ 4 $ 6,337 $ — $ 6,341 $ 5,916 $ — $ 2 $ 5,918 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, 2021, and 2020: Puget Energy Qualified SERP Other (Dollars in Thousands) 2021 2020 2021 2020 2021 2020 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 24,859 $ 98,010 $ 9,571 $ 11,738 $ (525) $ 600 Prior service cost (credit) — (1,904) 578 927 242 44 Total $ 24,859 $ 96,106 $ 10,149 $ 12,665 $ (283) $ 644
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) 2021 2020 2021 2020 2021 2020 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 127,111 $ 210,317 $ 10,103 $ 12,504 $ (622) $ 489 Prior service cost (credit) — (1,513) 578 927 242 44 Total $ 127,111 $ 208,804 $ 10,681 $ 13,431 $ (380) $ 533
Schedule of Net Benefit Costs	Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2021 2020 2019 2021 2020 2019 2021 2020 2019 Components of net periodic benefit cost: Service cost $ 26,888 $ 24,337 $ 22,656 $ 456 $ 756 $ 1,023 $ 155 $ 190 $ 61 Interest cost 22,381 25,180 28,913 1,183 1,464 2,314 302 368 410 Expected return on plan assets (48,242) (49,910) (50,267) — — — (355) (389) (393) Amortization of prior service cost (credit) (1,513) (1,573) (1,573) 349 349 333 6 — — Amortization of net loss (gain) 21,862 19,043 12,877 2,344 2,385 1,733 (52) (137) (562) Net periodic benefit cost $ 21,376 $ 17,077 $ 12,606 $ 4,332 $ 4,954 $ 5,403 $ 56 $ 32 $ (484)
Schedule of Amounts Recognized in Other Comprehensive Income (Loss)	Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2021 2020 2021 2020 2021 2020 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ (61,345) $ 11,858 $ 828 $ 3,663 $ (1,164) $ 715 Amortization of net (loss) gain (21,862) (19,043) (2,343) (2,385) 53 137 Settlements, mergers, sales, and closures — — (886) (5,248) — — Prior service cost (credit) — — — — 205 44 Amortization of prior service (cost) credit 1,513 1,573 (349) (349) (6) — Total change in other comprehensive income for year $ (81,694) $ (5,612) $ (2,750) $ (4,319) $ (912) $ 896

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2021
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) 2021 2020 2019 Charged to operating expenses: Current: Federal $ 25,395 $ 7,962 $ 9,424 State 721 7 164 Deferred: Federal (1,759) (6,414) 7,357 State 158 109 128 Total income tax expense $ 24,515 $ 1,664 $ 17,073
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) 2021 2020 2019 Income taxes at the statutory rate $ 59,927 $ 38,720 $ 47,834 Increase (decrease): Utility plant differences 1 $ (22,325) $ (22,991) $ (23,025) AFUDC, net 1,509 (6,095) (4,462) Executive compensation 1,386 2,440 2,596 Treasury grant amortization (5,424) (8,935) (7,870) Excess deferred tax amortization (13,392) (3,038) — Other–net 2,834 1,563 2,000 Total income tax expense $ 24,515 $ 1,664 $ 17,073 Effective tax rate 8.6 % 0.9 % 7.5 % Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2021 2020 2019 Income taxes at the statutory rate $ 79,868 $ 63,110 $ 69,735 Increase (decrease): Utility plant differences 1 $ (22,325) $ (22,991) $ (23,025) AFUDC, net 1,509 (6,095) (4,462) Executive compensation 1,386 2,440 2,596 Treasury grant amortization (5,424) (8,935) (7,870) Excess deferred tax amortization (13,392) (3,038) — Other–net 2,637 1,751 2,174 Total income tax expense $ 44,259 $ 26,242 $ 39,148 Effective tax rate 11.6 % 8.7 % 11.8 % _______________ 1. Utility plant differences include the reversal of excess deferred taxes using the average rate assumption method in the amount of $27.6 million in both 2021 and 2020.
Schedule of Deferred Tax Assets and Liabilities	The Company’s net deferred tax liability at December 31, 2021, and 2020, is composed of amounts related to the following types of temporary differences: Puget Energy At December 31, (Dollars in Thousands) 2021 2020 Utility plant and equipment $ 1,892,674 $ 1,923,933 Other deferred tax liabilities 202,783 175,333 Subtotal deferred tax liabilities 2,095,457 2,099,266 Net operating loss carryforward (254,007) (261,260) Net regulatory liability for income taxes (865,976) (953,274) Production tax credit carryforward — (35,995) Other deferred tax assets (62,990) (38,008) Subtotal deferred tax assets (1,182,973) (1,288,537) Total net deferred tax liabilities $ 912,484 $ 810,729 Puget Sound Energy At December 31, (Dollars in Thousands) 2021 2020 Utility plant and equipment $ 1,892,674 $ 1,923,933 Other, net deferred tax liabilities 121,060 91,438 Subtotal deferred tax liabilities 2,013,734 2,015,371 Net regulatory liability for income taxes (866,541) (953,987) Production tax credit carryforward — (35,995) Other deferred tax assets (62,990) (38,007) Subtotal deferred tax assets (929,531) (1,027,989) Total net deferred tax liabilities $ 1,084,203 $ 987,382
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) 2021 2020 2019 Charged to operating expenses: Current: Federal $ 52,616 $ 10,607 $ 18,093 State 670 383 570 Deferred: Federal (9,027) 15,252 20,485 State — — — Total income tax expense $ 44,259 $ 26,242 $ 39,148

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2021
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) 2021 2020 2019 PUD contract costs $ 117,812 $ 116,874 $ 87,135 As of December 31, 2021, 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 2022 Costs 2022 Debt Service Costs Interest included in 2022 Debt Service Costs Debt Outstanding Chelan County PUD: Rock Island Project 2031 30.0 % 187 $ 43,568 $ 12,074 $ 5,484 $ 99,510 Rocky Reach Project 2031 30.0 390 43,942 5,056 2,090 36,723 Douglas County PUD: Wells Project 1 2028 31.1 261 43,095 — — — Grant County PUD: Priest Rapids Development 2052 0.6 6 1,749 894 450 11,276 Wanapum Development 2052 0.6 7 1,749 894 450 11,276 Total 851 $ 134,103 $ 18,918 $ 8,474 $ 158,785 _______________ 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. 2. In March 2021, PSE entered into a new PPA with Chelan County PUD for additional Rocky Reach and Rock Island output. The contract begins on January 1, 2022, and continues through December 31, 2026. This agreement increases PSE’s share of output by 5% for each project, which equates to additional capacity of 31MW for Rock Island and 65MW for Rocky Reach.
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 2022 2023 2024 2025 2026 Thereafter Total Energy production service contracts $ 31,167 $ 31,916 $ 32,699 $ 33,468 $ 17,087 $ 81,854 $ 228,191 Automated meter reading system 46,455 47,517 47,526 48,249 49,098 — 238,845 Total $ 77,622 $ 79,433 $ 80,225 $ 81,717 $ 66,185 $ 81,854 $ 467,036
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) 2022 2023 2024 2025 2026 Thereafter Total Columbia River projects $ 151,378 $ 136,635 $ 134,188 $ 124,724 $ 123,243 $ 421,272 $ 1,091,440 Electric portfolio contracts 330,189 377,331 384,655 344,021 142,903 1,755,102 3,334,201 Electric wholesale market transactions 300,027 62,821 62,761 11,616 11,616 — 448,841 Total $ 781,594 $ 576,787 $ 581,604 $ 480,361 $ 277,762 $ 2,176,374 $ 4,874,482
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 Canadian Energy Regulator currently authorized rates, which are subject to change. Natural Gas Supply and Demand Charge Obligations 2022 2023 2024 2025 2026 Thereafter Total Natural gas wholesale market transactions $ 564,580 $ 299,400 $ 210,198 $ 153,054 $ 98,725 $ — $ 1,325,957 Firm transportation service 177,185 166,153 131,611 114,470 98,847 694,279 1,382,545 Firm storage service 8,899 2,270 68 67 56 — 11,360 Total $ 750,664 $ 467,823 $ 341,877 $ 267,591 $ 197,628 $ 694,279 $ 2,719,862

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021, 2020, and 2019, 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, 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) Other comprehensive income (loss) before reclassifications 49,226 49,226 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 9,779 9,779 Net current-period other comprehensive income (loss) 59,005 59,005 Balance at December 31, 2021 $ (27,432) $ (27,432)
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2021, 2020, and 2019, 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 2021 2020 2019 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,549 $ 1,631 $ 1,648 Amortization of net gain (loss) (a) (13,928) (10,200) (2,142) Total before tax (12,379) (8,569) (494) Tax (expense) or benefit 2,600 1,799 104 Net of tax (9,779) (6,770) (390) Total reclassification for the period Net of tax $ (9,779) $ (6,770) $ (390) __________ (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, 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) Other comprehensive income (loss) before reclassifications 49,265 — 49,265 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 18,166 384 18,550 Net current-period other comprehensive income (loss) 67,431 384 67,815 Balance at December 31, 2021 $ (108,541) $ (4,600) $ (113,141)
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 2021 2020 2019 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,158 $ 1,224 $ 1,240 Amortization of net gain (loss) (a) (24,153) (21,291) (14,048) Total before tax (22,995) (20,067) (12,808) Tax (expense) or benefit 4,829 4,214 2,690 Net of tax (18,166) (15,853) (10,118) Net unrealized gain (loss) on treasury interest rate swaps: Interest rate contracts Interest expense (487) (487) (487) Tax (expense) or benefit 103 102 102 Net of tax (384) (385) (385) Total reclassification for the period Net of tax $ (18,550) $ (16,238) $ (10,503) ____________ (a) These AOCI components are included in the computation of net periodic pension cost, see Note 13, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details) $ in Thousands	Dec. 19, 2017	Dec. 31, 2021USD ($)mi²	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Jan. 01, 2018USD ($)
Accounting Policies
Excise taxes collected		$ 268,500	$ 240,800	$ 236,500
Allowance for doubtful accounts		34,958	20,080
Monetized production tax credits		$ 45,600	39,800
PTC, Operation Period		10 years
Bad Debt Deferral, COVID 19		$ 2,800	$ 0
Electric Transmission
Accounting Policies
Annual depreciation provision		3.40%	3.50%	3.40%
Gas Transmission Equipment
Accounting Policies
Annual depreciation provision		2.80%	2.90%	2.80%
Common Plant
Accounting Policies
Annual depreciation provision		6.80%	7.30%	7.30%
Subsidiaries [Member]
Accounting Policies
Area of service territory (sqmi) | mi²		6,000
Allowance for doubtful accounts		$ (34,958)	$ (20,080)
Public Utilities, Rate Case, Deferred Storm Costs Threshold					$ 10,000
Variable Interest Entity, Measure of Activity, Expense		$ 19,000	4,200
Contract Length, PPA		20 years
Variable Interest Entity, Payable		$ 2,700
Regulatory Asset, Amortization Period		1 year
Regulatory Liability, Amortization Period		1 year
Puget LNG [Member]
Accounting Policies
Jointly Owned Non-Utility Plant Share		57.00%
Construction in Progress, Gross		$ 244,700	231,600
Operating Costs and Expenses		$ 1,300	600	$ 1,200
Tacoma LNG [Member]
Accounting Policies
Jointly Owned Non-Utility Plant Share		43.00%
Construction in Progress, Gross		$ 239,600	$ 207,700
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 [Member] | Subsidiaries [Member] | Maximum
Accounting Policies
Public Utilities, Approved Rate Increase (Decrease), Percentage	5.00%

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - AFUDC (Details)	Oct. 15, 2020	Oct. 01, 2020	Dec. 19, 2017	Dec. 31, 2021
Regulatory Assets [Line Items]
Public Utilities, Property, Plant and Equipment, Non-project Electric Utility Plant, Estimated Useful Life Average				30 years
Subsidiaries [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Debt Capital Structure, Percentage			7.60%
Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Debt Capital Structure, Percentage	7.39%
Subsidiaries [Member] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Debt Capital Structure, Percentage		7.39%

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Allowance for Credit Losses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Jan. 01, 2021	Jan. 01, 2020
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Allowance for Credit Losses, Beginning Balance			$ 20,080	$ 8,294
Provision for Credit Loss	$ 27,204	$ 23,292
Receivables Charged-Off	(12,326)	(11,506)
Allowance for Credit Loss, Ending Balance	$ 34,958	$ 20,080

Revenue (Details)

Revenue (Details) - USD ($) $ in Thousands	Aug. 13, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Revenue from Contract with Customer, Including Assessed Tax		$ 3,734,132	$ 3,222,391	$ 3,311,090
Regulated Operating Revenue, Other		66,620	26,121	28,718
Revenues		3,805,661	3,326,450	3,401,130
Puget LNG [Member]
Revenue, Remaining Performance Obligation, Amount		195,566
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction		15,359
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, 2025		19,710
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, 2026		19,454
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, 2027		19,454
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, 2028		19,454
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Thereafter		$ 102,135
Remaining Contract Term, PLNG		10 years
Subsidiaries [Member]
Regulated Operating Revenue, Other		$ 66,620	26,121	28,718
Revenues		3,805,661	3,326,450	3,401,130
Other Non-Customer Revenue	$ 23,200
Nonutility Revenue	23,200
Nonutility Expense	$ 12,900
Electricity, US Regulated [Member]
Revenue from Contract with Customer, Including Assessed Tax		2,348,356	2,106,122	2,132,522
Natural Gas, US Regulated [Member]
Revenue from Contract with Customer, Including Assessed Tax		1,036,411	938,061	870,457
Other Revenue From Contracts with Customers [Member]
Revenue from Contract with Customer, Including Assessed Tax		349,365	178,208	308,111
Decoupling over-collection [Member]
Regulated Operating Revenue, Other		(31,510)	35,006	(18,634)
Other Non-606 Revenue [Member]
Regulated Operating Revenue, Other		$ 103,039	$ 69,053	$ 108,674

Regulation and Rates Net regula

Regulation and Rates Net regulatory assets and liabilities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Jan. 01, 2018
Regulatory Assets [Line Items]
Regulatory Assets	$ 962,228,000	$ 929,835,000
Regulatory Liabilities	1,791,094,000	1,781,546,000
Accrual for Environmental Loss Contingencies	62,100,000
Deferred income tax charge
Regulatory Assets [Line Items]
Regulatory Liabilities	$ 565,000	713,000
Regulatory liabilities related to power contracts
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Min	4 years
Net Regulatory Assets, Remaining Amortization Period, Max	31 years
Regulatory Liabilities	$ 80,934,000	95,774,000
Various other regulatory liabilities
Regulatory Assets [Line Items]
Regulatory Liabilities	1,264,000	1,264,000
Net Regulatory Asset (Liability)
Regulatory Assets [Line Items]
Net Regulatory Assets	(828,866,000)	(851,711,000)
Requlatory Assets Related to Power Contracts
Regulatory Assets [Line Items]
Regulatory Assets	$ 9,689,000	11,728,000
Net Regulatory Assets, Remaining Amortization Period, Min	4 years
Net Regulatory Assets, Remaining Amortization Period, Max	31 years
Subsidiaries [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 952,539,000	918,107,000
Regulatory Liabilities	1,709,461,000	1,685,221,000
Regulatory Liabilities Reclassified from Accumulated Depreciation	563,100,000	508,700,000
Storm Damage Costs Incurred During Period	51,400,000	21,800,000
Public Utilities, Rate Case, Deferred Storm Costs Threshold			$ 10,000,000
Public Utilities, Rate Case, Deferred Storm Qualifying Costs			$ 500,000
Subsidiaries [Member] | Deferred income tax charge
Regulatory Assets [Line Items]
Regulatory Liabilities	866,541,000	953,987,000
Subsidiaries [Member] | Cost of removal
Regulatory Assets [Line Items]
Regulatory Liabilities	$ 563,129,000	508,707,000
Subsidiaries [Member] | Treasury grants
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period	2 years
Regulatory Liabilities	$ 22,476,000	43,164,000
Subsidiaries [Member] | Production tax credits [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	0	47,094,000
Subsidiaries [Member] | Gain on Sale Shuffleton [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	4,892,000	11,131,000
Subsidiaries [Member] | Repurposed production tax credits [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	$ 134,270,000	79,581,000
Subsidiaries [Member] | Deferred decoupling revenue, net [Member]
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period	2 years
Regulatory Liabilities	$ 36,506,000	16,448,000
Subsidiaries [Member] | Various other regulatory liabilities
Regulatory Assets [Line Items]
Regulatory Liabilities	7,725,000	5,871,000
Subsidiaries [Member] | Liabilities, Total
Regulatory Assets [Line Items]
Regulatory Liabilities	1,709,461,000	1,685,221,000
Subsidiaries [Member] | Green Direct
Regulatory Assets [Line Items]
Regulatory Liabilities	13,194,000	14,313,000
Subsidiaries [Member] | Net Regulatory Asset (Liability)
Regulatory Assets [Line Items]
Net Regulatory Assets	(756,922,000)	(767,114,000)
Subsidiaries [Member] | PGA Unrealized Gain
Regulatory Assets [Line Items]
Regulatory Liabilities	60,728,000	4,925,000
Subsidiaries [Member] | Storm Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 127,789,000	108,491,000
Net Regulatory Assets, Remaining Amortization Period	4 years
Subsidiaries [Member] | Chelan PUD contract initiation
Regulatory Assets [Line Items]
Regulatory Assets	$ 69,699,000	76,787,000
Net Regulatory Assets, Remaining Amortization Period	9 years 9 months 18 days
Subsidiaries [Member] | Environmental remediation
Regulatory Assets [Line Items]
Regulatory Assets	$ 127,977,000	102,647,000
Subsidiaries [Member] | Lower Snake River
Regulatory Assets [Line Items]
Regulatory Assets	$ 53,757,000	58,442,000
Net Regulatory Assets, Remaining Amortization Period	15 years 4 months 24 days
Subsidiaries [Member] | Deferred decoupling revenue, net [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 79,125,000	88,504,000
Net Regulatory Assets, Remaining Amortization Period	2 years
Subsidiaries [Member] | Baker Dam Licensing Operating Maintenance Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 54,525,000	54,354,000
Hydro license term	50 years
Subsidiaries [Member] | Deferred Washington Commission AFUDC
Regulatory Assets [Line Items]
Regulatory Assets	$ 62,244,000	59,763,000
Net Regulatory Assets, Remaining Amortization Period	30 years
Subsidiaries [Member] | Property tax tracker
Regulatory Assets [Line Items]
Regulatory Assets	$ 25,896,000	24,860,000
Net Regulatory Assets, Remaining Amortization Period	2 years
Subsidiaries [Member] | Unamortized loss on reacquired debt
Regulatory Assets [Line Items]
Regulatory Assets	$ 35,805,000	37,991,000
Net Regulatory Assets, Remaining Amortization Period, Min	1 year
Net Regulatory Assets, Remaining Amortization Period, Max	46 years
Subsidiaries [Member] | Energy Conservation Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 3,573,000	8,009,000
Subsidiaries [Member] | GTZ depreciation expense deferral [Member]
Regulatory Assets [Line Items]
Regulatory Assets	50,220,000	53,236,000
Subsidiaries [Member] | Advanced metering infrastructure [Member]
Regulatory Assets [Line Items]
Regulatory Assets	23,037,000	22,652,000
Subsidiaries [Member] | Generation plant major maintenance [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 12,094,000	10,494,000
Net Regulatory Assets, Remaining Amortization Period, Min	1 year
Net Regulatory Assets, Remaining Amortization Period, Max	8 years
Subsidiaries [Member] | PGA deferral of unrealized losses on derivative instruments
Regulatory Assets [Line Items]
Regulatory Assets	$ 5,725,000	6,973,000
Subsidiaries [Member] | Mint Farm ownership and operating costs
Regulatory Assets [Line Items]
Regulatory Assets	$ 6,318,000	8,318,000
Net Regulatory Assets, Remaining Amortization Period	3 years 3 months 18 days
Subsidiaries [Member] | PGA receivable [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 57,935,000	87,655,000
Net Regulatory Assets, Remaining Amortization Period	2 years
Subsidiaries [Member] | Snoqualmie Licensing Operating Maintenance Costs
Regulatory Assets [Line Items]
Regulatory Assets	$ 7,446,000	7,435,000
Hydro license term	40 years
Subsidiaries [Member] | Colstrip major maintenance [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 4,035,000	4,335,000
Subsidiaries [Member] | PCA Mechanism [Member]
Regulatory Assets [Line Items]
Regulatory Assets	79,546,000	82,801,000
Subsidiaries [Member] | WUTC Electric Vehicle
Regulatory Assets [Line Items]
Regulatory Assets	6,109,000	3,641,000
Subsidiaries [Member] | WUTC COVID-19
Regulatory Assets [Line Items]
Regulatory Assets	3,657,000	0
Subsidiaries [Member] | Low Income Program Costs
Regulatory Assets [Line Items]
Regulatory Assets	21,755,000	0
Subsidiaries [Member] | PLR EDIT
Regulatory Assets [Line Items]
Regulatory Assets	$ 18,850,000	0
Net Regulatory Assets, Remaining Amortization Period	1 year
Subsidiaries [Member] | Various other regulatory assets
Regulatory Assets [Line Items]
Regulatory Assets	$ 15,422,000	$ 10,719,000

General Rate Case Filing (Detai

General Rate Case Filing (Details) - Subsidiaries [Member] - USD ($) $ in Millions	Oct. 01, 2021	Sep. 28, 2021	Oct. 15, 2020	Sep. 30, 2020	Jul. 31, 2020	Jul. 08, 2020	Jun. 20, 2019	Dec. 19, 2017	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2021
Schedule of Regulatory Assets and Liabilities [Line Items]
Public Utilities, Approved Debt Capital Structure, Percentage								7.60%
General Rate Case [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 18.9
Annual Revenue Requirement				$ 25.6
Regulatory assets and additional revenues												$ 24.5
Revenue Not from Contract with Customer, Other												$ 5.6
General Rate Case [Member] | Maximum
Schedule of Regulatory Assets and Liabilities [Line Items]
Public Utilities, Approved Debt Capital Structure, Net of Tax, Percentage						6.80%
Public Utilities, Approved Equity Capital Structure, Percentage						48.50%
Public Utilities, Approved Return on Equity, Percentage						9.40%
Forecast | General Rate Case [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities									7.49%	7.44%	7.39%
Forecast | General Rate Case [Member] | Maximum
Schedule of Regulatory Assets and Liabilities [Line Items]
Public Utilities, Requested Return on Equity, Percentage									9.90%	9.90%	9.90%
Electricity, US Regulated [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Public Utilities, Approved Debt Capital Structure, Percentage			7.39%
Electricity, US Regulated [Member] | General Rate Case [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage							6.90%
Public Utilities, Interim Rate Increase (Decrease), Amount		$ 48.3			$ 59.6	$ 29.5
Public Utilities, Interim Rate Increase (Decrease), Percentage		2.30%				1.60%
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 15.8					$ 0.9
Public Utilities, Approved Rate Increase (Decrease), Percentage	0.70%					0.05%
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount		$ 77.1
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage		3.70%
PublicUtilitiesIncremenalRateIncreaseDecreaseAmount		$ 17.5
Electricity, US Regulated [Member] | Forecast | General Rate Case [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage									1.20%	2.50%	13.60%
Natural Gas, US Regulated [Member] | General Rate Case [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage							7.90%
Public Utilities, Interim Rate Increase (Decrease), Amount		$ 4.9			$ 42.9	$ 36.5
Public Utilities, Interim Rate Increase (Decrease), Percentage		0.60%				4.00%
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 3.1					$ 1.3
Public Utilities, Approved Rate Increase (Decrease), Percentage	0.30%					0.15%
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount		$ 45.3
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage		5.90%
PublicUtilitiesIncremenalRateIncreaseDecreaseAmount		$ 2.4
Natural Gas, US Regulated [Member] | Forecast | General Rate Case [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage									1.80%	2.30%	13.00%

Power Cost Only Rate Case (Deta

Power Cost Only Rate Case (Details) - Subsidiaries [Member] - Electricity, US Regulated [Member] - USD ($) $ in Thousands	Jul. 01, 2021	Mar. 02, 2021	Feb. 02, 2021	Dec. 09, 2020
PCORC [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 88,000	$ 78,500
Public Utilities, Requested Rate Increase (Decrease), Percentage			4.10%	3.70%
Power Cost Only Rate Case
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 65,300
Public Utilities, Requested Rate Increase (Decrease), Percentage		3.10%
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 70,900
Public Utilities, Approved Rate Increase (Decrease), Percentage	3.30%

Decoupling Filings (Details)

Decoupling Filings (Details) - Subsidiaries [Member] - Decoupling Mechanism [Member] - USD ($) $ in Millions	Dec. 19, 2017	Dec. 31, 2021	Dec. 31, 2020
Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Contract with Customer, Liability, Revenue Recognized		$ 3	$ 8
Electricity, US Regulated [Member] | Maximum
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage	3.00%
Natural Gas [Member]
Regulatory Assets [Line Items]
Contract with Customer, Liability, Revenue Recognized		$ 0	$ 0
Natural Gas [Member] | Maximum
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage	5.00%

Schedule of Power Cost Adjustme

Schedule of Power Cost Adjustment Mechanism (Details) - Subsidiaries [Member] $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)
Regulatory Assets [Line Items]
Annual Power Cost Variability, Interest	$ 1.7	$ 2
Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount	68	76.1
Customer's share | Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount	$ 36.7	44
Customer's share | Range 1 | Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	0
Customer's share | Range 1 | Over-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	0
Customer's share | Range 2 | Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	0.50
Customer's share | Range 2 | Over-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	0.65
Customer's share | Range 3 | Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	0.90
Customer's share | Range 3 | Over-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	0.90
Companys share | Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount		$ 32.1
Companys share | Range 1 | Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	1
Companys share | Range 1 | Over-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	1
Companys share | Range 2 | Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	0.50
Companys share | Range 2 | Over-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	0.35
Companys share | Range 3 | Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	0.10
Companys share | Range 3 | Over-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	0.10

Power Cost Adjustment Clause Fi

Power Cost Adjustment Clause Filing (Details) - Subsidiaries [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount	$ 68	$ 76.1
Under-collection | Companys share
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount		32.1
Under-collection | Customer's share
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount	$ 36.7	44
Under-collection | Customer's share plus interest [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount		46
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, 2021	Nov. 01, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Regulatory Assets [Line Items]
Other regulatory assets			$ 815,058	$ 747,651
Subsidiaries [Member]
Regulatory Assets [Line Items]
Other regulatory assets			815,058	747,651
PGA payable			57,935	87,655	$ 132,766
Subsidiaries [Member] | Purchased Gas Adjustment [Member]
Regulatory Assets [Line Items]
Annual revenue		$ 37,400
Out of Cycle PGA	$ 69,400	69,400
Purchased natural gas costs			364,775	314,792
Purchased natural gas costs, recoverable			(396,236)	(363,886)
Purchased natural gas adjustment, interest			$ 1,741	$ 3,983
Public Utilities, Approved Rate Increase (Decrease), Amount	59,100	$ 32,600
Subsidiaries [Member] | Schedule 101
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	80,600
Subsidiaries [Member] | Schedule 106
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ (21,500)

Narrative (Details)

Narrative (Details) - USD ($)	Oct. 15, 2021	Apr. 06, 2020	Apr. 10, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Apr. 12, 2021	Jul. 21, 2020	Jan. 01, 2018
Regulatory Assets [Line Items]
Depreciation and amortization				$ 704,783,000	$ 647,755,000	$ 656,323,000
Accrual for Environmental Loss Contingencies				62,100,000
Natural Gas, US Regulated [Member]
Regulatory Assets [Line Items]
Environmental Remediation Expense				69,000,000
Environmental Expense and Liabilities				75,800,000	50,900,000
Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Environmental Remediation Expense				48,600,000
Environmental Expense and Liabilities				52,200,000	51,800,000
Subsidiaries [Member]
Regulatory Assets [Line Items]
Depreciation and amortization				704,372,000	647,546,000	$ 656,220,000
Customer Bill Assistance	$ 2,500	$ 1,000
Liabilities, Other than Long-term Debt, Noncurrent	$ 34,500,000	$ 11,000,000					$ 27,700,000	$ 4,500,000
Storm Damage Costs Incurred During Period				51,400,000	21,800,000
Public Utilities, Rate Case, Deferred Storm Costs Threshold									$ 10,000,000
Public Utilities, Rate Case, Deferred Storm Qualifying Costs									$ 500,000
Customer Bill Assistance, Qualifying threshold	200.00%
Subsidiaries [Member] | Natural Gas [Member]
Regulatory Assets [Line Items]
Liabilities, Other than Long-term Debt, Noncurrent	$ 10,800,000						7,700,000
Subsidiaries [Member] | Electricity [Member]
Regulatory Assets [Line Items]
Liabilities, Other than Long-term Debt, Noncurrent	$ 23,700,000						$ 20,000,000
Subsidiaries [Member] | Storm that occurred in 2018 [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Deferred During Period					11,200,000
Subsidiaries [Member] | Storm that occurred in 2020
Regulatory Assets [Line Items]
Storm Damage Costs Deferred During Period				200,000
Subsidiaries [Member] | Storm that occurred in 2021
Regulatory Assets [Line Items]
Storm Damage Costs Deferred During Period				40,900,000
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				$ 6,600,000	$ 2,800,000
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, 2021USD ($)
Parent [Line Items]
Retained Earnings, Unappropriated	$ 1,200,000,000
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio, Threshold For Dividend Payment	2
EBITDA Interest Expense Ratio	3.9
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	47.50%
EBITDA Interest Expense Ratio	5.5
EBITDA to Interest Expense Denominator	1
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End	1

Utility Plant (Details)

Utility Plant (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Public Utility, Property, Plant and Equipment
Accumulated amortization of capital leases	$ 2,600	$ 1,600
Utility Plant
Distribution plant	7,488,629	7,028,731
Production plant	3,147,987	3,096,092
Transmission plant	1,556,666	1,494,781
General plant	746,758	697,501
Intangible plant (including capitalized software)1	797,691	779,767
Plant acquisition adjustment	242,826	242,826
Underground storage	43,391	39,498
Liquefied natural gas storage	12,628	12,628
Plant held for future use	46,020	45,929
Recoverable Cushion Gas	8,655	8,655
Plant not classified	316,933	384,794
Finance leases, net of accumulated amortization2	105,020	881
Less: accumulated provision for depreciation	(4,031,458)	(3,671,094)
Subtotal	10,481,746	10,160,989
Construction work in progress	870,204	712,204
Net utility plant	$ 11,351,950	10,873,193
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	$ 9,026,042	8,592,720
Production plant	3,815,599	3,767,014
Transmission plant	1,663,559	1,601,731
General plant	773,662	726,327
Intangible plant (including capitalized software)1	788,240	770,317
Plant acquisition adjustment	282,792	282,792
Underground storage	56,820	52,927
Liquefied natural gas storage	14,498	14,498
Plant held for future use	46,172	46,081
Recoverable Cushion Gas	8,655	8,655
Plant not classified	316,933	384,794
Finance leases, net of accumulated amortization2	105,020	881
Less: accumulated provision for depreciation	(6,416,246)	(6,087,748)
Subtotal	10,481,746	10,160,989
Construction work in progress	870,204	712,204
Net utility plant	$ 11,351,950	$ 10,873,193

Utility Plant - Jointly Owned U

Utility Plant - Jointly Owned Utility Plant (Details) $ in Thousands	Dec. 31, 2021USD ($)
Colstrip Units 3 & 4
Jointly Owned Utility Plant Interests
Plant in Service at Cost	$ 339,073
Construction Work in Progress	0
Accumulated Depreciation	(153,950)
Frederickson 1
Jointly Owned Utility Plant Interests
Plant in Service at Cost	63,210
Construction Work in Progress	0
Accumulated Depreciation	(18,215)
Jackson Prairie [Member]
Jointly Owned Utility Plant Interests
Plant in Service at Cost	42,736
Construction Work in Progress	471
Accumulated Depreciation	(10,867)
Tacoma LNG [Member]
Jointly Owned Utility Plant Interests
Plant in Service at Cost	0
Construction Work in Progress	484,299
Accumulated Depreciation	$ 0
Subsidiaries [Member] | Colstrip Units 3 & 4
Jointly Owned Utility Plant Interests
Company’s Ownership Share	25.00%
Plant in Service at Cost	$ 597,009
Construction Work in Progress	0
Accumulated Depreciation	$ (411,887)
Subsidiaries [Member] | Frederickson 1
Jointly Owned Utility Plant Interests
Company’s Ownership Share	49.85%
Plant in Service at Cost	$ 69,278
Construction Work in Progress	0
Accumulated Depreciation	$ (24,283)
Subsidiaries [Member] | Jackson Prairie [Member]
Jointly Owned Utility Plant Interests
Company’s Ownership Share	33.34%
Plant in Service at Cost	$ 56,820
Construction Work in Progress	471
Accumulated Depreciation	(24,952)
Subsidiaries [Member] | Tacoma LNG [Member]
Jointly Owned Utility Plant Interests
Plant in Service at Cost	0
Construction Work in Progress	239,566
Accumulated Depreciation	$ 0

Utility Plant - Schedule of Ass

Utility Plant - Schedule of Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Tacoma LNG [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Decommissioning Liability, Noncurrent	$ 3,800	$ 3,300
Subsidiaries [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of the period	216,163	181,353
Relief of liability	(13,146)	(9,647)
Revisions in estimated cash flows	(46)	38,677
Accretion expense	6,070	5,780
Asset Retirement Obligation, Ending Balance	209,041	216,163
Decommissioning Liability, Noncurrent	13,100	9,600
Puget LNG [Member] | Tacoma LNG [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Decommissioning Liability, Noncurrent	$ 3,700	$ 7,400

Utility Plant - Narrative (Deta

Utility Plant - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2021	Dec. 31, 2019
Tacoma LNG [Member]
Jointly Owned Utility Plant Interests
Decommissioning Liability, Noncurrent	$ 3.3	$ 3.8
Subsidiaries [Member]
Jointly Owned Utility Plant Interests
Decommissioning Liability, Noncurrent	9.6	13.1
Subsidiaries [Member] | Colstrip Units 1 and 2 [Member]
Jointly Owned Utility Plant Interests
Regulatory Assets, Unrecovered plant balance			$ 126.5
Decommissioning Liability, Noncurrent	29.7	1.5
Environmental Remediation, Current Period Addition	39
Subsidiaries [Member] | Colstrip Units 3 and 4 [Member]
Jointly Owned Utility Plant Interests
Decommissioning Liability, Noncurrent	2	3.1
Puget LNG [Member] | Tacoma LNG [Member]
Jointly Owned Utility Plant Interests
Decommissioning Liability, Noncurrent	$ 7.4	$ 3.7

Long-Term Debt (Schedule of Lon

Long-Term Debt (Schedule of Long-Term Debt Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Sep. 15, 2021	Jun. 14, 2021	Dec. 31, 2020	Sep. 26, 2019	Mar. 05, 2018	Oct. 10, 2017
Debt Instrument [Line Items]
Total PSE long-term debt	$ 6,857,160
Long Term Debt, Reconciliation, Fair Value Adjustment	(156,849)			$ (165,357)
Long-term Debt, term loan					$ 210,000
Long-term Line of Credit, Noncurrent	33,300			14,700
Unamortized discount on senior notes	(7,404)			(4,947)
Long-term Debt, Excluding Current Maturities	6,203,766			5,892,440
Current maturities of long-term debt	450,000			526,412
Short-term debt	140,000			373,800
$210M Term Loan Due 2022
Debt Instrument [Line Items]
Long-term Debt, term loan	$ 0			210,000
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	$ 0			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%
Current maturities of long-term debt			$ 500,000
Senior Secured Note | 4.100% Senior Secured Note Due 2030
Debt Instrument [Line Items]
Stated interest rate percent	4.10%
Total PSE long-term debt	$ 650,000			650,000
Senior Secured Note | 2.379% Senior Secured Note Due 2028
Debt Instrument [Line Items]
Stated interest rate percent	2.379%		2.379%
Total PSE long-term debt	$ 500,000		$ 500,000	0
Long-term Debt, Term			7 years
Subsidiaries [Member]
Debt Instrument [Line Items]
Total PSE long-term debt	4,823,860
Unamortized discount on senior notes	(39,141)			(35,816)
Long-term Debt, Excluding Current Maturities	4,784,719			4,338,044
Current maturities of long-term debt	0			2,412
Short-term debt	$ 140,000			373,800
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
Subsidiaries [Member] | Senior Secured Note | 2.893% Senior Secured Note Due 2051
Debt Instrument [Line Items]
Stated interest rate percent	2.893%	2.893%
Total PSE long-term debt	$ 450,000	$ 450,000		$ 0
Long-term Debt, Term		30 years

Long-Term Debt (Narrative) (Det

Long-Term Debt (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Sep. 15, 2021	Jun. 14, 2021	Jun. 18, 2020	Sep. 26, 2019	Aug. 02, 2019
Debt Instrument [Line Items]
Long-term Debt, term loan							$ 210,000
Total PSE long-term debt	$ 6,857,160
Long-term Line of Credit, Noncurrent	33,300	$ 14,700
Long-term debt	6,857,160
Line of Credit Facility, Remaining Borrowing Capacity								$ 100,000
Line of Credit Facility, Maximum Borrowing Capacity	1,300,000
Gain (Loss) on Extinguishment of Debt	0	(13,546)	$ 0
Repayments of Debt	234,000	159,400	$ 0
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
Senior Secured Note | 2.379% Senior Secured Note Due 2028
Debt Instrument [Line Items]
Total PSE long-term debt	500,000	0			$ 500,000
Long-term debt	$ 500,000	0			$ 500,000
Stated interest rate percent	2.379%				2.379%
Long-term Debt, Term					7 years
Senior Secured Note | 6.000% Senior Secured Note Due 2021
Debt Instrument [Line Items]
Stated interest rate percent					6.00%
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	4,823,860
Long-term debt	4,823,860
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%
Subsidiaries [Member] | Senior Secured Note | 2.893% Senior Secured Note Due 2051
Debt Instrument [Line Items]
Total PSE long-term debt	$ 450,000	0		$ 450,000
Long-term debt	$ 450,000	$ 0		$ 450,000
Stated interest rate percent	2.893%			2.893%
Long-term Debt, Term				30 years

Long-Term Debt (Schedule of Mat

Long-Term Debt (Schedule of Maturities of Long-Term Debt) (Details) $ in Thousands	Dec. 31, 2021USD ($)
Maturities of Long-term Debt [Abstract]
2022	$ 450,000
2023	33,300
2024	0
2025	417,000
2026	0
Thereafter	5,956,860
Total long-term debt	6,857,160
Subsidiaries [Member]
Maturities of Long-term Debt [Abstract]
2022	0
2023	0
2024	0
2025	17,000
2026	0
Thereafter	4,806,860
Total long-term debt	4,823,860
Parent Company [Member]
Maturities of Long-term Debt [Abstract]
2022	450,000
2023	33,300
2024	0
2025	400,000
2026	0
Thereafter	1,150,000
Total long-term debt	$ 2,033,300

Liquidity Facilities and Othe_2

Liquidity Facilities and Other Financing Arrangements (Details) - USD ($) $ in Thousands	Sep. 25, 2019	Feb. 10, 2012	Dec. 31, 2021	Dec. 31, 2020	Aug. 02, 2019	Oct. 10, 2017
Short-term Debt [Line Items]
Short-term debt			$ 140,000	$ 373,800
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			$ 140,000	$ 373,800
Weighted-average interest rate on short-term debt (percent)			1.60%	2.00%
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
Letters of Credit Outstanding, Amount			$ 0
Promissory Note Outstanding, Amount			0
Subsidiaries [Member] | Working Capital Needs
Short-term Debt [Line Items]
Current borrowing capacity of line of credit						$ 800,000
Subsidiaries [Member] | Letter of Credit | Working Capital Needs
Short-term Debt [Line Items]
Current borrowing capacity of line of credit			2,500
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
Parent
Short-term Debt [Line Items]
Short-term debt			$ 0	$ 0
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Basis spread on variable rate (percent)			1.75%
Line of Credit Facility, Commitment Fee Percentage		0.275%
Line of Credit Facility, Fair Value of Amount Outstanding			$ 33,300
Revolving Credit Facility [Member] | Subsidiaries [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Fair Value of Amount Outstanding			$ 0

Leases (Details)

Leases (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)lease	Dec. 31, 2020USD ($)
Lessee, Lease, Description [Line Items]
Lease, Remaining Lease Term	48 years
ROU Asset, Modification, Operating	$ 26,300
Current Lease Liability, Modification, Operating	400
Long-Term Lease Liability, Modification, Operating	25,900
Subsidiaries [Member]
Lessee, Lease, Description [Line Items]
Right-of-Use, Modification, Operating	$ 26,287	$ 0
Property Subject to or Available for Finance Lease, Number of Units | lease	2
Subsidiaries [Member] | Kent Service Center
Lessee, Lease, Description [Line Items]
Finance Lease ROU Asset, Addition	$ 45,100
Current Lease Liability, Addition, Finance	1,000
Long-Term Lease Liability, Addition, Finance	$ 44,100
Lessee, Finance Lease, Term of Contract	20 years
Subsidiaries [Member] | Puyallup Service Center
Lessee, Lease, Description [Line Items]
Finance Lease ROU Asset, Addition	$ 61,300
Current Lease Liability, Addition, Finance	400
Long-Term Lease Liability, Addition, Finance	$ 59,900
Lessee, Finance Lease, Term of Contract	20 years

Leases (Schedule of Operating L

Leases (Schedule of Operating Lease Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Operating Leased Assets [Line Items]
Finance Lease, Right-of-Use Asset, Amortization	$ 1,291	$ 607
Finance Lease, Interest Expense	358	34
Finance Lease, Cost	1,649	641
Operating Lease, Cost	23,983	21,983
Subsidiaries [Member] | Land [Member]
Operating Leased Assets [Line Items]
Operating Lease, Cost	$ 1,400	$ 1,000

Leases (Cash paid) (Details)

Leases (Cash paid) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Lessee, Lease, Description [Line Items]
Operating Lease, Payments	$ 16,440	$ 15,305
Operating Lease, Payments, Use	7,543	6,678
Finance Lease, Interest Payment on Liability	358	34
Finance Lease, Principal Payments	1,291	607
Operating Lease, Cost	23,983	21,983
Subsidiaries [Member]
Lessee, Lease, Description [Line Items]
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	4,820	6,302
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	105,176	0
Right-of-Use, Modification, Operating	26,287	0
Subsidiaries [Member] | Land [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	$ 1,400	$ 1,000

Leases (Balance Sheet) (Details

Leases (Balance Sheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Operating lease right-of-use asset	$ 184,957	$ 172,167
Operating lease liabilities	20,398	19,204
Operating lease liabilities	172,510	160,980
Operating Lease, Liability	192,908	180,184
Finance Lease, Right-of-Use Asset	105,020	881
Finance Lease, Liability, Current	1,742	475
Finance Lease, Liability, Noncurrent	105,303	320
Finance Lease, Liability	$ 107,045	$ 795
Operating Lease, Weighted Average Remaining Lease Term	22 years 9 months 18 days	18 years 11 months 19 days
Finance Lease, Weighted Average Remaining Lease Term	20 years 1 month 24 days	2 years
Operating Lease, Weighted Average Discount Rate, Percent	3.27%	3.59%
Finance Lease, Weighted Average Discount Rate, Percent	3.07%	2.98%
Operating Leased Assets [Line Items]
Finance Lease, Right-of-Use Asset	$ 105,020	$ 881
Common Plant
Leases [Abstract]
Finance Lease, Right-of-Use Asset	61,227	881
Operating Leased Assets [Line Items]
Finance Lease, Right-of-Use Asset	61,227	881
Electric Transmission
Leases [Abstract]
Finance Lease, Right-of-Use Asset	43,793	0
Operating Leased Assets [Line Items]
Finance Lease, Right-of-Use Asset	$ 43,793	$ 0

Leases (Remaining Cash Payments

Leases (Remaining Cash Payments) (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months	$ 23,945
Lessee, Operating Lease, Liability, Payments, Due Year Two	23,717
Lessee, Operating Lease, Liability, Payments, Due Year Three	23,000
Lessee, Operating Lease, Liability, Payments, Due Year Four	19,636
Lessee, Operating Lease, Liability, Payments, Due Year Five	17,126
Lessee, Operating Lease, Liability, Payments, Due after Year Five	164,797
Lessee, Operating Lease, Liability, Payments, Due	272,221
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(79,313)
Operating Lease, Liability	192,908	$ 180,184
Finance Lease, Liability, Payments, Due Next Twelve Months	4,881
Finance Lease, Liability, Payments, Due Year Two	6,260
Finance Lease, Liability, Payments, Due Year Three	6,286
Finance Lease, Liability, Payments, Due Year Four	6,411
Finance Lease, Liability, Payments, Due Year Five	6,540
Finance Lease, Liability, Payments, Due after Year Five	116,553
Finance Lease, Liability, Payment, Due	146,931
Finance Lease, Liability, Undiscounted Excess Amount	(39,886)
Finance Lease, Liability	$ 107,045	$ 795

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, 2021USD ($)MMBTUMWh	Dec. 31, 2020USD ($)MMBTUMWh
Derivative [Line Items]
Assets, Current	$ 128,210	$ 33,015
Assets, Long-term	26,197	8,805
Liabilities, Current	63,309	31,441
Liabilities, Long-term	40,965	29,833
Not Designated as Hedging Instrument
Derivative [Line Items]
Total derivative assets	154,407	41,820
Total derivative liabilities	104,274	61,274
Not Designated as Hedging Instrument | Parent Company [Member]
Derivative [Line Items]
Assets, Current	128,210	33,015
Assets, Long-term	26,197	8,805
Liabilities, Current	63,309	31,441
Liabilities, Long-term	$ 40,965	$ 29,833
Not Designated as Hedging Instrument | Electric Generation Fuel
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	238	212.2
Not Designated as Hedging Instrument | Purchased Electricity
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MWh	8.1	6.6
Not Designated as Hedging Instrument | Natural Gas Portfolio
Derivative [Line Items]
Total derivative assets	$ 79,578	$ 19,276
Total derivative liabilities	18,850	14,352
Not Designated as Hedging Instrument | Electric Portfolio
Derivative [Line Items]
Total derivative assets	74,829	22,544
Total derivative liabilities	$ 85,424	$ 46,922
Not Designated as Hedging Instrument | Gas Derivatives
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	347	320

Accounting for Derivative Ins_4

Accounting for Derivative Instruments and Hedging Activities (Offsetting) (Details) - Commodity Contract [Member] - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Derivative Asset, Fair Value, Amount Offset Against Collateral [Abstract]
Derivative Asset, Fair Value, Gross Asset	$ 154,407	$ 41,820
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	0
Derivative Asset	154,407	41,820
Derivative, Collateral, Obligation to Return Securities	40,833	21,696
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	113,574	20,124
Derivative Liability, Fair Value, Amount Offset Against Collateral [Abstract]
Derivative Liability, Fair Value, Gross Liability	104,274	61,274
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	0
Derivative Liability	104,274	61,274
Derivative, Collateral, Right to Reclaim Securities	40,833	21,696
Derivative, Collateral, Right to Reclaim Cash	1,743	9,343
Derivative Liability, Fair Value, Amount Offset Against Collateral	$ 61,698	$ 30,235

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments, net	$ 13,785	$ (26,807)	$ (3,574)
Credit Rating
Derivative Instruments, (Loss) Gain [Line Items]
Posted Collateral	12,800
Natural Gas Portfolio
Derivative Instruments, (Loss) Gain [Line Items]
Posted Collateral	24,000
Natural Gas Portfolio | Credit Rating
Derivative Instruments, (Loss) Gain [Line Items]
Posted Collateral	0
Not Designated as Hedging Instrument
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments, net	87,245	(36,519)	55,940
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	26,686	5,534	16,970
Not Designated as Hedging Instrument | Commodity Contract [Member] | Electric Generation Fuel
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments, net	76,504	5,246	10,828
Not Designated as Hedging Instrument | Commodity Contract [Member] | Purchased Electricity
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments, net	(3,044)	(14,958)	48,686
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	$ (12,901)	$ (32,341)	$ (20,544)

Accounting for Derivative Ins_6

Accounting for Derivative Instruments and Hedging Activities (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Natural Gas Portfolio
Derivative [Line Items]
Posted Collateral	$ 24,000
Electric Portfolio
Derivative [Line Items]
Posted Collateral	$ 12,782	$ 20,903
External Credit Rating, Investment Grade [Member] | Electric Portfolio
Derivative [Line Items]
Percentage of derivatives with credit risk exposure	98.90%
External Credit Rating, Non Investment Grade [Member] | Electric Portfolio
Derivative [Line Items]
Percentage of derivatives with credit risk exposure	1.10%
Credit Rating
Derivative [Line Items]
Posted Collateral	$ 12,800
Credit Rating | Natural Gas Portfolio
Derivative [Line Items]
Posted Collateral	0
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, 2021	Dec. 31, 2020
Electric Portfolio
Derivative [Line Items]
Fair Value Liability	$ 63,660	$ 42,885
Posted Collateral	12,782	20,903
Contingent Collateral	52,537	26,966
Forward Value of Contract [Member] | Electric Portfolio
Derivative [Line Items]
Fair Value Liability	1,743	9,343
Posted Collateral	12,782	20,903
Requested Credit for Adequate Assurance | Electric Portfolio
Derivative [Line Items]
Fair Value Liability	9,380	6,576
Posted Collateral	0	0
Contingent Collateral	0	0
Credit Rating
Derivative [Line Items]
Posted Collateral	12,800
Credit Rating | Electric Portfolio
Derivative [Line Items]
Fair Value Liability	52,537	26,966
Posted Collateral	0	0
Contingent Collateral	$ 52,537	$ 26,966

Fair Value Measurements - Debt

Fair Value Measurements - Debt at Carrying and Fair Value (Details) - USD ($)	Dec. 31, 2021	Dec. 31, 2020
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	$ 4,784,719,000	$ 4,338,044,000
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	22,800,000	22,900,000
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	4,784,719,000	4,338,044,000
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	6,145,639,000	6,086,358,000
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	6,145,639,000	6,086,358,000
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	53,200,000	52,700,000
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	6,203,766,000	5,892,440,000
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	22,700,000
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	6,170,466,000	5,667,740,000
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure	33,300,000	224,700,000
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	7,803,196,000	7,980,646,000
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	7,769,896,000	7,755,946,000
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure	$ 33,300,000	$ 224,700,000

Fair Value Measurements - Sched

Fair Value Measurements - Schedule of Assets and Liabilities (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	$ 154,407	$ 41,820
Derivative Liability	104,274	61,274
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	147,537	41,086
Derivative Liability	52,532	35,687
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	6,870	734
Derivative Liability	51,742	25,587
Electric Portfolio
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	74,829	22,544
Derivative Liability	85,424	46,922
Electric Portfolio | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	68,011	21,947
Derivative Liability	35,854	22,607
Electric Portfolio | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	6,818	597
Derivative Liability	49,570	24,315
Natural Gas Portfolio
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	79,578	19,276
Derivative Liability	18,850	14,352
Natural Gas Portfolio | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	79,526	19,139
Derivative Liability	16,678	13,080
Natural Gas Portfolio | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	52	137
Derivative Liability	$ 2,172	$ 1,272

Fair Value Measurements - Unobs

Fair Value Measurements - Unobservable Input Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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	$ (24,853)	$ (2,097)	$ 3,035
Included in earnings	(15,839)	(23,559)	3,558
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities)	(1,749)	(1,049)	3,151
Settlements	(2,431)	1,852	(15,973)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3	0	0	3,992
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3	0	0	140
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Ending Balance	(44,872)	(24,853)	(2,097)
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	(23,718)	(3,379)	1,362
Included in earnings	(15,839)	(23,559)	3,558
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities)	0	0	0
Settlements	(3,195)	3,220	(11,265)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3	0	0	4,390
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3	0	0	(1,424)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Ending Balance	(42,752)	(23,718)	(3,379)
Unrealized gain (loss) on derivative instruments, net	(21,600)	(21,300)	(3,200)
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	(1,135)	1,282	1,673
Included in earnings	0	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities)	(1,749)	(1,049)	3,151
Settlements	764	(1,368)	(4,708)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3	0	0	(398)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3	0	0	1,564
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Ending Balance	$ (2,120)	$ (1,135)	$ 1,282

Fair Value Measurements - Forwa

Fair Value Measurements - Forward Price Ranges (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)$ / MMBTU$ / MWh	Dec. 31, 2020USD ($)
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	$ 17,900
Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	154,407	$ 41,820
Derivative Liability	104,274	61,274
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	6,870	734
Derivative Liability	51,742	25,587
Natural Gas Portfolio | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	79,578	19,276
Derivative Liability	18,850	14,352
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	52	137
Derivative Liability	$ 2,172	1,272
Natural Gas Portfolio | Income Approach Valuation Technique | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU	3.65
Natural Gas Portfolio | Income Approach Valuation Technique | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU	7.54
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	5.89
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	$ 52
Derivative Liability	2,172
Electric Portfolio | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	74,829	22,544
Derivative Liability	85,424	46,922
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	6,818	597
Derivative Liability	$ 49,570	$ 24,315
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	21.88
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	119.38
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	61.51
Electric Portfolio | Parent Company [Member] | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 6,818
Derivative Liability	$ 49,570

Fair Value Measurements - Valua

Fair Value Measurements - Valuations (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Impairment of Intangible Assets (Excluding Goodwill)		$ 0	$ 52,565,000
Options Purchases or Sales		$ 0	$ 0	$ 0
Wells Project [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-Lived Intangible Assets, Net	$ 147,168,000
Impairment of Intangible Assets (Excluding Goodwill)	52,565,000
Wells Project [Member] | Carrying Amount
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure	$ 94,603,000

Fair Value Measurements - Uno_2

Fair Value Measurements - Unobservable Input (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2020USD ($)$ / MWh	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Firm Storage and Peaking Service [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Long-term Purchase Commitment, Demand Charges		$ 136,400,000	$ 135,800,000	$ 125,100,000
Combustion turbines
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Long-term Purchase Commitment, Demand Charges		$ 52,800,000	$ 51,200,000	$ 51,200,000
Minimum | Wells Project [Member] | Income Approach Valuation Technique
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 | Wells Project [Member] | Income Approach Valuation Technique
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 | Wells Project [Member] | Income Approach Valuation Technique
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, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Contribution Plan Disclosure [Line Items]
Employer discretionary contribution amount	$ 23,600,000	$ 22,100,000	$ 21,700,000
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, 2021	Dec. 31, 2020
Other Pension Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	$ 12,114	$ 11,627
Amendments	205	44
Service cost	155	190
Interest cost	302	368
Actuarial loss (gain)	514	(604)
Benefits paid	803	906
Medicare part D subsidy received	195	187
Administrative expense	0	0
Benefit obligation at end of period	11,654	12,114
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of period	5,918	6,289
Actual return on plan assets	1,005	278
Employer contribution	222	257
Benefits paid	(804)	(906)
Administrative expense	0	0
Fair value of plan assets at end of period	6,341	5,918
Funded status at end of period	(5,313)	(6,196)
Nonqualified Plan | Pension Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	46,742	63,000
Amendments	0	0
Service cost	456	756
Interest cost	1,183	1,464
Actuarial loss (gain)	(828)	(3,663)
Benefits paid	6,054	22,141
Medicare part D subsidy received	0	0
Administrative expense	0	0
Benefit obligation at end of period	43,155	46,742
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	6,054	22,141
Benefits paid	(6,054)	(22,141)
Administrative expense	0	0
Fair value of plan assets at end of period	0	0
Funded status at end of period	(43,155)	(46,742)
Qualified Plan | Pension Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	849,383	774,305
Amendments	0	0
Service cost	26,888	24,337
Interest cost	22,381	25,180
Actuarial loss (gain)	6,826	(69,413)
Benefits paid	55,831	42,775
Medicare part D subsidy received	0	0
Administrative expense	(1,035)	(1,077)
Benefit obligation at end of period	834,960	849,383
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of period	834,655	753,042
Actual return on plan assets	102,787	107,409
Employer contribution	18,000	18,000
Benefits paid	(55,831)	(42,775)
Administrative expense	(1,061)	(1,021)
Fair value of plan assets at end of period	898,550	834,655
Funded status at end of period	$ 63,590	$ (14,728)

Retirement Benefits - Amounts R

Retirement Benefits - Amounts Recognized (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Other Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 11,654	$ 12,114	$ 11,627
Accumulated benefit obligation	11,549	12,070
Fair value of plan assets	6,341	5,918	6,289
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets	0	0
Current liabilities	(280)	(293)
Noncurrent liabilities	(5,033)	(5,903)
Net assets (liabilities)	(5,313)	(6,196)
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	(525)	600
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax	242	44
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total	(283)	644
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	(622)	489
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax	242	44
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total	(380)	533
Nonqualified Plan | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	43,155	46,742	63,000
Accumulated benefit obligation	40,773	44,033
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	(2,822)	(6,763)
Noncurrent liabilities	(40,333)	(39,979)
Net assets (liabilities)	(43,155)	(46,742)
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	9,571	11,738
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax	578	927
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total	10,149	12,665
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	10,103	12,504
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax	578	927
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total	10,681	13,431
Qualified Plan | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	834,960	849,383	774,305
Accumulated benefit obligation	823,418	837,455
Fair value of plan assets	898,550	834,655	$ 753,042
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets	63,590	0
Current liabilities	0	0
Noncurrent liabilities	0	(14,728)
Net assets (liabilities)	63,590	(14,728)
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	24,859	98,010
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax	0	(1,904)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total	24,859	96,106
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	127,111	210,317
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax	0	(1,513)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total	$ 127,111	$ 208,804

Retirement Benefits - Net Perio

Retirement Benefits - Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Other Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	$ 155	$ 190
Interest cost	302	368
Parent Company [Member] | Other Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	155	190	$ 61
Interest cost	302	368	410
Expected return on plan assets	(355)	(389)	(393)
Amortization of prior service cost (credit)	6	0	0
Amortization of net loss (gain)	(39)	(82)	(374)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	69	87	(296)
Subsidiaries [Member] | Other Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	155	190	61
Interest cost	302	368	410
Expected return on plan assets	(355)	(389)	(393)
Amortization of prior service cost (credit)	6	0	0
Amortization of net loss (gain)	(52)	(137)	(562)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	56	32	(484)
Nonqualified Plan | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	456	756
Interest cost	1,183	1,464
Nonqualified Plan | Parent Company [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	456	756	1,023
Interest cost	1,183	1,464	2,314
Expected return on plan assets	0	0	0
Amortization of prior service cost (credit)	349	349	331
Amortization of net loss (gain)	2,165	2,122	1,365
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	4,153	4,691	5,033
Nonqualified Plan | Subsidiaries [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	456	756	1,023
Interest cost	1,183	1,464	2,314
Expected return on plan assets	0	0	0
Amortization of prior service cost (credit)	349	349	333
Amortization of net loss (gain)	2,344	2,385	1,733
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	4,332	4,954	5,403
Qualified Plan | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	26,888	24,337
Interest cost	22,381	25,180
Qualified Plan | Parent Company [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	26,888	24,337	22,656
Interest cost	22,381	25,180	28,913
Expected return on plan assets	(48,239)	(49,902)	(50,249)
Amortization of prior service cost (credit)	(1,904)	(1,980)	(1,980)
Amortization of net loss (gain)	11,803	8,160	1,151
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	10,929	5,795	491
Qualified Plan | Subsidiaries [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	26,888	24,337	22,656
Interest cost	22,381	25,180	28,913
Expected return on plan assets	(48,242)	(49,910)	(50,267)
Amortization of prior service cost (credit)	(1,513)	(1,573)	(1,573)
Amortization of net loss (gain)	21,862	19,043	12,877
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	$ 21,376	$ 17,077	$ 12,606

Retirement Benefits - Benefit O

Retirement Benefits - Benefit Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer matching contribution, percent	4.50%
Defined Contribution Plan, Interest Credit	4.00%
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)	$ 1,164	$ (715)
Amortization of net (loss) gain	39	82
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	0	0
Prior service cost (credit)	205	44
Amortization of prior service (cost) credit	6	0
Total change in other comprehensive income for year	(926)	841
Other Pension Plan [Member] | Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss (gain)	1,164	(715)
Amortization of net (loss) gain	53	137
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	0	0
Prior service cost (credit)	205	44
Amortization of prior service (cost) credit	6	0
Total change in other comprehensive income for year	(912)	896
Qualified Plan | Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss (gain)	61,348	(11,851)
Amortization of net (loss) gain	(11,803)	(8,160)
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	(1,904)	(1,980)
Total change in other comprehensive income for year	(71,247)	5,671
Qualified Plan | Pension Plan [Member] | Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss (gain)	61,345	(11,858)
Amortization of net (loss) gain	(21,862)	(19,043)
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	(1,513)	(1,573)
Total change in other comprehensive income for year	(81,694)	(5,612)
Nonqualified Plan | Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss (gain)	(828)	(3,663)
Amortization of net (loss) gain	(2,164)	(2,122)
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	830	(4,806)
Prior service cost (credit)	0	0
Amortization of prior service (cost) credit	349	349
Total change in other comprehensive income for year	(2,515)	(3,614)
Nonqualified Plan | Pension Plan [Member] | Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss (gain)	(828)	(3,663)
Amortization of net (loss) gain	(2,343)	(2,385)
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	886	(5,248)
Prior service cost (credit)	0	0
Amortization of prior service (cost) credit	349	349
Total change in other comprehensive income for year	$ (2,750)	$ (4,319)

Retirement Benefits - Textuals

Retirement Benefits - Textuals (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Five-year smoothing of asset gains (losses)	5 years
Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Interest Credit	4.00%
Forecast | Qualified Plan | Subsidiaries [Member] | Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Estimated Future Employer Contributions in Current Fiscal Year		$ 18
Forecast | Nonqualified Plan | Subsidiaries [Member] | Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Estimated Future Employer Contributions in Current Fiscal Year		2.8
Forecast | Other Pension Plan [Member] | Subsidiaries [Member] | Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Estimated Future Employer Contributions in Current Fiscal Year		$ 0.3

Retirement Benefits - Assumptio

Retirement Benefits - Assumptions (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Other Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	3.00%	2.70%	3.35%
Rate of compensation increase	4.50%	4.50%	4.50%
Benefit Cost Assumptions
Discount rate	2.70%	3.35%	4.40%
Return on plan assets	7.00%	7.00%	7.00%
Rate of compensation increase	4.50%	4.50%	4.50%
Nonqualified Plan | Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	3.00%	2.70%	3.35%
Rate of compensation increase	4.50%	4.50%	4.50%
Benefit Cost Assumptions
Discount rate	2.70%	3.35%	4.40%
Return on plan assets	0.00%	0.00%	0.00%
Rate of compensation increase	4.50%	4.50%	4.50%
Qualified Plan | Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	3.00%	2.70%	3.35%
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%
Benefit Cost Assumptions
Discount rate	2.70%	3.35%	4.40%
Return on plan assets	6.50%	7.15%	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%

Retirement Benefits - Future Be

Retirement Benefits - Future Benefit Payments (Details) $ in Thousands	Dec. 31, 2021USD ($)
Other Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2020	$ 962
2021	925
2022	896
2023	877
2024	860
2025-2029	4,012
2020, without Medicare Part D subsidy	962
2021, without Medicare Part D subsidy	925
2022, without Medicare Part D subsidy	896
2023, without Medicare Part D subsidy	877
2024, without Medicare Part D subsidy	860
2025-2029, without Medicare Part D subsidy	4,012
Qualified Plan | Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2020	46,900
2021	47,900
2022	49,100
2023	50,400
2024	51,300
2025-2029	265,200
Nonqualified Plan | Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2020	2,822
2021	3,881
2022	6,786
2023	7,796
2024	2,265
2025-2029	$ 17,047

Retirement Benefits - Plan Asse

Retirement Benefits - Plan Asset Allocation (Details)	Dec. 31, 2021
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, 2021	Dec. 31, 2020	Dec. 31, 2019
Other Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 6,341	$ 5,918	$ 6,289
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	4	5,916
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	6,337	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	0	2
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	898,550	834,655
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	6,341	5,918
Mutual Funds | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	5,916
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	6,337	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 | Other Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6,337	5,916
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	65,266	73,006
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	2,470	9,148
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	67,736	82,154
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	3,638	4,612
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	(540)	3,223
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	3,098	7,835
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	343,888	325,081
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	20,088	22,205
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	534,574	487,369
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	(23,015)	(44,981)
Net Receivables [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	2
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	(23,015)	(44,981)
Net Receivables [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	2
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	115,570	107,137
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	115,570	107,137
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	359,861	342,014
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	359,861	342,014
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	1,434	1,096
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	1,434	1,096
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	80,724	82,103
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	80,724	82,103
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	5,239	3,699
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	5,239	3,699
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	12,820	6,082
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	12,820	6,082
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	249,021	228,247
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	99	53
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	249,120	228,300
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	25,963	19,216
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	25,963	19,216
Money Market Funds | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4	0
Money Market Funds | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Money Market Funds | Fair Value Measured at Net Asset Value Per Share [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Money Market Funds | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 4	$ 0

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosures [Line Items]
Current Federal Tax Expense (Benefit)	$ 25,395	$ 7,962	$ 9,424
Current State and Local Tax Expense (Benefit)	721	7	164
Deferred Federal Income Tax Expense (Benefit)	(1,759)	(6,414)	7,357
Deferred State and Local Income Tax Expense (Benefit)	158	109	128
Total income tax expense	$ 24,515	1,664	17,073
Valuation Allowance, Commentary	No
Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Current Federal Tax Expense (Benefit)	$ 52,616	10,607	18,093
Current State and Local Tax Expense (Benefit)	670	383	570
Deferred Federal Income Tax Expense (Benefit)	(9,027)	15,252	20,485
Deferred State and Local Income Tax Expense (Benefit)	0	0	0
Total income tax expense	$ 44,259	$ 26,242	$ 39,148

Income Taxes - Deferred Income

Income Taxes - Deferred Income Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Deferred Tax Liabilities, Gross
Deferred Tax Liabilities, Property, Plant and Equipment	$ 1,892,674	$ 1,923,933
Deferred Tax Liabilities, Other	202,783	175,333
Deferred Tax Liabilities, Gross, Total	2,095,457	2,099,266
Deferred Tax Assets, Gross
Deferred Tax Assets, Operating Loss Carryforwards	(254,007)	(261,260)
Deferred Tax Assets, Net Regulatory Liability for Income Taxes	(865,976)	(953,274)
Deferred Tax Assets, Tax Credit Carryforwards, Production	0	(35,995)
Deferred Tax Assets, Other	(62,990)	(38,008)
Deferred Tax Assets, Gross	(1,182,973)	(1,288,537)
Deferred Tax Liabilities, Net, Total	912,484	810,729
Subsidiaries [Member]
Deferred Tax Liabilities, Gross
Deferred Tax Liabilities, Property, Plant and Equipment	1,892,674	1,923,933
Deferred Tax Liabilities, Other	121,060	91,438
Deferred Tax Liabilities, Gross, Total	2,013,734	2,015,371
Deferred Tax Assets, Gross
Deferred Tax Assets, Net Regulatory Liability for Income Taxes	(866,541)	(953,987)
Deferred Tax Assets, Tax Credit Carryforwards, Production	0	(35,995)
Deferred Tax Assets, Other	(62,990)	(38,007)
Deferred Tax Assets, Gross	(929,531)	(1,027,989)
Deferred Tax Liabilities, Net, Total	$ 1,084,203	$ 987,382

Income Taxes - Balance Sheet Lo

Income Taxes - Balance Sheet Location (Details) - USD ($) $ in Thousands	12 Months Ended			24 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2021
Income Tax Disclosures [Line Items]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	$ (13,392)	$ (3,038)	$ 0
Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	$ (13,392)	(3,038)	$ 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	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating Loss Carryforwards [Line Items]
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount	$ 59,927	$ 38,720	$ 47,834
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depreciation and Amortization, Amount	(22,325)	(22,991)	(23,025)
Income Tax Reconciliation, AFUDC (net)	1,509	(6,095)	(4,462)
Income Tax Reconciliation, Executive Compensation	1,386	2,440	2,596
Income Tax Reconciliation, Treasury Grant	(5,424)	(8,935)	(7,870)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	(13,392)	(3,038)	0
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount	2,834	1,563	2,000
Total income tax expense	$ 24,515	$ 1,664	$ 17,073
Effective Income Tax Rate Reconciliation, Percent	8.60%	0.90%	7.50%
Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount	$ 79,868	$ 63,110	$ 69,735
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depreciation and Amortization, Amount	(22,325)	(22,991)	(23,025)
Income Tax Reconciliation, AFUDC (net)	1,509	(6,095)	(4,462)
Income Tax Reconciliation, Executive Compensation	1,386	2,440	2,596
Income Tax Reconciliation, Treasury Grant	(5,424)	(8,935)	(7,870)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	(13,392)	(3,038)	0
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount	2,637	1,751	2,174
Total income tax expense	$ 44,259	$ 26,242	$ 39,148
Effective Income Tax Rate Reconciliation, Percent	11.60%	8.70%	11.80%

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($)	12 Months Ended		24 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2021
Operating Loss Carryforwards [Line Items]
Valuation Allowance, Commentary	No
Unrecognized Tax Benefits	$ 0	$ 0	$ 0
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense	$ 0	0
ARAM [Member]
Operating Loss Carryforwards [Line Items]
Deferred Other Tax Expense (Benefit)		$ 27,600,000	$ 27,600,000

Litigation (Details)

Litigation (Details) - Subsidiaries [Member]	Dec. 31, 2021
Colstrip Unit 4 [Member]
Jointly Owned Utility Plant Interests
Company’s Ownership Share	25.00%
Colstrip Units 1 & 2
Jointly Owned Utility Plant Interests
Company’s Ownership Share	50.00%

Commitments and Contingencies_2

Commitments and Contingencies (Details)	1 Months Ended	12 Months Ended
	Mar. 31, 2021MW	Dec. 31, 2021USD ($)MWhContractsMW	Dec. 31, 2020USD ($)MWh	Dec. 31, 2019USD ($)MWh
Long-term Purchase Commitment [Line Items]
Long-term Line of Credit, Noncurrent		$ 33,300,000	$ 14,700,000
Average cost of Company's energy output (US$ per kWh)		$ 0.034
Number of Public Utility Districts with long term purchase agreements | Contracts		3
Contract expenses		$ 117,812,000	$ 116,874,000	$ 87,135,000
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased		13.30%
Long-term Contract for Purchase of Electric Power, Capacity | MW		851
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost		$ 134,103,000
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required		18,918,000
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges		8,474,000
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding		158,785,000
Payment Obligations for Power Purchases
2022		781,594,000
2023		576,787,000
2024		581,604,000
2025		480,361,000
2026		277,762,000
Thereafter		2,176,374,000
Total		$ 4,874,482,000
Total energy obtained during period under purchased power contracts (MWh) | MWh		13.1	13.2	12.5
Cost incurred during period to provide energy under purchased power contracts		$ 631,400,000	$ 491,700,000	$ 550,600,000
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
2022		$ 564,580,000
2023		299,400,000
2024		210,198,000
2025		153,054,000
2026		98,725,000
Thereafter		0
Total		1,325,957,000
Colombia River Projects [Member]
Payment Obligations for Power Purchases
2022		151,378,000
2023		136,635,000
2024		134,188,000
2025		124,724,000
2026		123,243,000
Thereafter		421,272,000
Non-Utility Generators [Member]
Payment Obligations for Power Purchases
Total		448,841,000
Firm Transportation Service [Member]
Payment Obligations for Power Purchases
2022		177,185,000
2023		166,153,000
2024		131,611,000
2025		114,470,000
2026		98,847,000
Thereafter		694,279,000
Total		1,382,545,000
Firm Storage and Peaking Service [Member]
Payment Obligations for Power Purchases
2022		8,899,000
2023		2,270,000
2024		68,000
2025		67,000
2026		56,000
Thereafter		0
Total		11,360,000
Long-term Purchase Commitment, Demand Charges		136,400,000	135,800,000	125,100,000
Combustion turbines
Payment Obligations for Power Purchases
Long-term Purchase Commitment, Demand Charges		52,800,000	$ 51,200,000	$ 51,200,000
Energy production service contracts
Payment Obligations for Power Purchases
2022		31,167,000
2023		31,916,000
2024		32,699,000
2025		33,468,000
2026		17,087,000
Thereafter		81,854,000
Total		228,191,000
Automated meter reading system
Payment Obligations for Power Purchases
2022		46,455,000
2023		47,517,000
2024		47,526,000
2025		48,249,000
2026		49,098,000
Thereafter		0
Total		238,845,000
Service contract obligations
Payment Obligations for Power Purchases
2022		77,622,000
2023		79,433,000
2024		80,225,000
2025		81,717,000
2026		66,185,000
Thereafter		81,854,000
Total		467,036,000
Colombia River Projects [Member]
Payment Obligations for Power Purchases
Total		1,091,440,000
Other Utilities [Member]
Payment Obligations for Power Purchases
Total		3,334,201,000
Electric Portfolio
Payment Obligations for Power Purchases
2022		330,189,000
2023		377,331,000
2024		384,655,000
2025		344,021,000
2026		142,903,000
Thereafter		1,755,102,000
Firm natural gas supply
Payment Obligations for Power Purchases
2022		750,664,000
2023		467,823,000
2024		341,877,000
2025		267,591,000
2026		197,628,000
Thereafter		694,279,000
Total		$ 2,719,862,000
Minimum | Combustion turbines
Payment Obligations for Power Purchases
Remaining terms under contract		1 year
Maximum | Combustion turbines
Payment Obligations for Power Purchases
Remaining terms under contract		23 years
Rock Island Project
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased	5.00%	30.00%
Long-term Contract for Purchase of Electric Power, Capacity | MW	31	187
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost		$ 43,568,000
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required		12,074,000
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges		5,484,000
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding		$ 99,510,000
Rocky Reach Project
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased	5.00%	30.00%
Long-term Contract for Purchase of Electric Power, Capacity | MW	65	390
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost		$ 43,942,000
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required		5,056,000
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges		2,090,000
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding		$ 36,723,000
Wells Project [Member]
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased		31.10%
Long-term Contract for Purchase of Electric Power, Capacity | MW		261
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost		$ 43,095,000
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		$ 1,749,000
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required		894,000
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges		450,000
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding		$ 11,276,000
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		$ 1,749,000
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required		894,000
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges		450,000
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding		11,276,000
Electricity, US Regulated [Member]
Payment Obligations for Power Purchases
2022		300,027,000
2023		62,821,000
2024		62,761,000
2025		11,616,000
2026		11,616,000
Thereafter		$ 0

Related Party Transactions (Det

Related Party Transactions (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction	$ 0

Segment Information (Details)

Segment Information (Details)	12 Months Ended
	Dec. 31, 2021mi²segment
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, 2021	Dec. 31, 2020	Dec. 31, 2019
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	$ (86,437)
Accumulated other comprehensive income (loss), net of tax	(27,432)	$ (86,437)
Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(180,956)
Accumulated other comprehensive income (loss), net of tax	(113,141)	(180,956)
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	(86,437)	(84,149)	$ (77,202)
Other comprehensive income (loss) before reclassifications	49,226	(9,058)	(7,337)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	9,779	6,770	390
Net current-period other comprehensive income (loss)	59,005	(2,288)	(6,947)
Accumulated other comprehensive income (loss), net of tax	(27,432)	(86,437)	(84,149)
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	(175,972)	(183,108)	(185,130)
Other comprehensive income (loss) before reclassifications	49,265	(8,717)	(8,096)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	18,166	15,853	10,118
Net current-period other comprehensive income (loss)	67,431	7,136	2,022
Accumulated other comprehensive income (loss), net of tax	(108,541)	(175,972)	(183,108)
Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(86,437)	(84,149)	(77,202)
Other comprehensive income (loss) before reclassifications	49,226	(9,058)	(7,337)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	9,779	6,770	390
Net current-period other comprehensive income (loss)	59,005	(2,288)	(6,947)
Accumulated other comprehensive income (loss), net of tax	(27,432)	(86,437)	(84,149)
Comprehensive Income [Member] | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(180,956)	(188,477)	(190,884)
Other comprehensive income (loss) before reclassifications	49,265	(8,717)	(8,096)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	18,550	16,238	10,503
Net current-period other comprehensive income (loss)	67,815	7,521	2,407
Accumulated other comprehensive income (loss), net of tax	(113,141)	(180,956)	(188,477)
Interest Rate Swap [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member] | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(4,984)	(5,369)	(5,754)
Other comprehensive income (loss) before reclassifications	0	0	0
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	384	385	385
Net current-period other comprehensive income (loss)	384	385	385
Accumulated other comprehensive income (loss), net of tax	$ (4,600)	$ (4,984)	$ (5,369)

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Reclassification out of Accumulated Other Comprehensive Income | Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Total reclassification for the period	$ (9,779)	$ (6,770)	$ (390)
Reclassification out of Accumulated Other Comprehensive Income | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Total reclassification for the period	(18,550)	(16,238)	(10,503)
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	1,549	1,631	1,648
Amortization of net (loss) gain	(13,928)	(10,200)	(2,142)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax	(12,379)	(8,569)	(494)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax	2,600	1,799	104
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, after Tax	(9,779)	(6,770)	(390)
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]
Reclassification from AOCI, Current Period, before Tax, Attributable to Parent	(487)	(487)	(487)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, Tax	(103)	(102)	(102)
Total reclassification for the period	(384)	(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	1,158	1,224	1,240
Amortization of net (loss) gain	(24,153)	(21,291)	(14,048)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax	(22,995)	(20,067)	(12,808)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax	4,829	4,214	2,690
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, after Tax	$ (18,166)	$ (15,853)	$ (10,118)

SCHEDULE I CONDENSED FINANCIA_2

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Statements of Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Condensed Financial Statements, Captions [Line Items]
Nonutility Expense And Other	$ (58,281)	$ (43,425)	$ (47,907)
Interest expense	(352,092)	(373,822)	(356,638)
Income Tax Expense (Benefit)	(24,515)	(1,664)	(17,073)
Net income (loss)	260,849	182,717	210,708
Comprehensive income (loss)	319,854	180,429	203,761
Condensed Cash Flow Statements, Captions [Line Items]
Net Cash Provided by (Used in) Operating Activities	826,598	727,568	527,336
Payments for (Proceeds from) Other Investing Activities	(1,367)	(5,340)	(6,908)
Net Cash Provided by (Used in) Investing Activities	(920,777)	(902,796)	(952,479)
Payments of Dividends	106,420	45,421	64,220
Proceeds from Contributions from Parent	210,000	4,575	0
Proceeds from Issuance of Long-term Debt	961,538	644,690	689,351
Repayments of Long-term Debt	502,410	450,000	0
Net Cash Provided by (Used in) Financing Activities	115,478	190,933	435,727
Net increase (decrease) in cash, cash equivalents, and restricted cash	21,299	15,705	10,584
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	103,150	81,851	66,146	$ 55,562
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Nonutility Expense And Other	(913)	(1,579)	(1,495)
Equity In Net Income (Loss) Of Subsidiaries	337,405	277,654	294,724
Investment Income, Interest	4,261	4,760	6,643
Interest expense	(100,002)	(123,592)	(111,716)
Income Tax Expense (Benefit)	20,098	25,474	22,552
Net income (loss)	260,849	182,717	210,708
Comprehensive income (loss)	319,854	180,429	203,761
Condensed Cash Flow Statements, Captions [Line Items]
Net Cash Provided by (Used in) Operating Activities	143,691	38,280	68,724
Adjustments to Additional Paid in Capital, Other	21,783	0	210,000
Payments for (Proceeds from) Loans Receivable from Subsidiary	0	31,043	41,708
Net Cash Provided by (Used in) Investing Activities	(21,783)	(31,043)	(251,708)
Payments of Dividends	106,420	45,421	64,220
Proceeds from Contributions from Parent	(210,000)	(4,575)	0
Proceeds from Issuance of Long-term Debt	515,475	644,690	246,200
Repayments of Long-term Debt	734,000	609,400	0
Issue costs and others	1,367	1,838	116
Net Cash Provided by (Used in) Financing Activities	(116,312)	(7,394)	181,864
Net increase (decrease) in cash, cash equivalents, and restricted cash	5,596	(157)	(1,120)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 6,386	$ 790	$ 947	$ 2,067

SCHEDULE I CONDENSED FINANCIA_3

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Other Property And Investments [Abstract]
Goodwill	$ 1,656,513	$ 1,656,513
Current assets:
Cash and Cash Equivalents, at Carrying Value	56,946	52,307
Total current assets	1,138,108	916,617
Assets, Noncurrent [Abstract]
Other	163,374	80,751
Total assets	15,871,884	15,042,965
Capitalization, Long-term Debt and Equity [Abstract]
Stockholders' Equity Attributable to Parent	4,563,316	4,139,882	$ 4,000,299	$ 3,860,758
Long-term debt	1,583,300	1,724,700
Total capitalization	10,767,082	10,032,322
Current liabilities:
Accounts payable	444,384	342,404
Current maturities of long-term debt	450,000	526,412
Interest	67,807	73,647
Unrealized loss on derivative instruments	63,309	31,441
Total current liabilities	1,425,423	1,595,614
Liabilities, Noncurrent [Abstract]
Unrealized loss on derivative instruments	40,965	29,833
Total capitalization and liabilities	15,871,884	15,042,965
Parent
Assets
Investments in subsidiaries	4,446,758	4,279,501
Other Property And Investments [Abstract]
Goodwill	1,656,513	1,656,513
Current assets:
Cash and Cash Equivalents, at Carrying Value	6,386	790
Receivables from affiliates	233,258	211,411
Income Taxes Receivable, Current	6,006	0
Total current assets	245,650	212,201
Assets, Noncurrent [Abstract]
Deferred Tax Assets, Net of Valuation Allowance, Noncurrent	250,820	258,033
Other	984	1,520
Assets, Noncurrent, Total	251,804	259,553
Total assets	6,600,725	6,407,768
Capitalization, Long-term Debt and Equity [Abstract]
Stockholders' Equity Attributable to Parent	4,563,316	4,139,882
Long-term debt	1,571,287	1,714,744
Total capitalization	6,134,603	5,854,626
Current liabilities:
Accounts payable	147	349
Accrued Income Taxes, Current	0	3,334
Current maturities of long-term debt	450,000	524,000
Interest	15,975	25,459
Total current liabilities	466,122	553,142
Liabilities, Noncurrent [Abstract]
Total capitalization and liabilities	$ 6,600,725	$ 6,407,768

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, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net Cash Provided by (Used in) Operating Activities	$ 826,598	$ 727,568	$ 527,336
Net Cash Provided by (Used in) Investing Activities
Payments for (Proceeds from) Other Investing Activities	(1,367)	(5,340)	(6,908)
Net Cash Provided by (Used in) Investing Activities	(920,777)	(902,796)	(952,479)
Net Cash Provided by (Used in) Financing Activities
Payments of Dividends	106,420	45,421	64,220
Proceeds from Issuance of Long-term Debt	961,538	644,690	689,351
Repayments of Long-term Debt	502,410	450,000	0
Net Cash Provided by (Used in) Financing Activities	115,478	190,933	435,727
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect	21,299	15,705	10,584
Cash, cash equivalents, and restricted cash at end of period	56,946	52,307
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	103,150	81,851	66,146	$ 55,562
Parent Company [Member]
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net Cash Provided by (Used in) Operating Activities	143,691	38,280	68,724
Net Cash Provided by (Used in) Investing Activities
Adjustments to Additional Paid in Capital, Other	(21,783)	0	(210,000)
Net Cash Provided by (Used in) Investing Activities	(21,783)	(31,043)	(251,708)
Net Cash Provided by (Used in) Financing Activities
Payments of Dividends	106,420	45,421	64,220
Proceeds from Issuance of Long-term Debt	515,475	644,690	246,200
Repayments of Long-term Debt	734,000	609,400	0
Net Cash Provided by (Used in) Financing Activities	(116,312)	(7,394)	181,864
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect	5,596	(157)	(1,120)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 6,386	$ 790	$ 947	$ 2,067

SCHEDULE I CONDENSED FINANCIA_5

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY Notes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Ownership percentage	100.00%
Net Income (Loss) Attributable to Parent	$ 260,849	$ 182,717	$ 210,708
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	319,854	180,429	203,761
Net Cash Provided by (Used in) Operating Activities	826,598	727,568	527,336
Net Cash Provided by (Used in) Investing Activities	(920,777)	(902,796)	(952,479)
Business Combination Adjustment, ASC 805	2,400	3,400	2,900
Parent Company [Member]
Net Income (Loss) Attributable to Parent	260,849	182,717	210,708
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	319,854	180,429	203,761
Net Cash Provided by (Used in) Operating Activities	143,691	38,280	68,724
Net Cash Provided by (Used in) Investing Activities	(21,783)	(31,043)	(251,708)
Subsidiaries [Member]
Net Income (Loss) Attributable to Parent	336,063	274,280	292,924
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	403,878	281,801	295,331
Net Cash Provided by (Used in) Operating Activities	920,393	824,810	623,924
Net Cash Provided by (Used in) Investing Activities	(906,906)	(871,097)	(912,363)
PSE and PLNG
Net Income (Loss) Attributable to Parent	$ 335,000	$ 274,300	$ 292,900

SCHEDULE II__VALUATION AND QUAL

SCHEDULE II: VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) - SEC Schedule, 12-09, Allowance, Credit Loss [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount, Beginning Balance	$ 20,080	$ 8,294	$ 8,408
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Cost and Expense	27,204	23,292	17,633
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	12,326	11,506	17,747
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount, Ending Balance	$ 34,958	$ 20,080	$ 8,294