Puget Sound Energy 10-Q 5 Nov 20 2020 Q3 Quarterly report Financial data

Document And Entity Information

Document And Entity Information	9 Months Ended
	Sep. 30, 2020shares
Entity Information [Line Items]
Entity Registrant Name	PUGET ENERGY INC /WA
Entity Central Index Key	0001085392
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	200
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2020
Entity Emerging Growth Company	false
Entity Small Business	true
Entity Shell Company	false
Document Transition Report	false
Document Quarterly Report	true
Subsidiaries [Member]
Entity Information [Line Items]
Entity Registrant Name	PUGET SOUND ENERGY INC
Entity Central Index Key	0000081100
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	85,903,791
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2020
Entity Emerging Growth Company	false
Entity Small Business	true
Entity Shell Company	false
Document Transition Report	false
Document Quarterly Report	true

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Operating revenue:
Electric	$ 500,976	$ 513,926	$ 1,638,432	$ 1,823,596
Natural gas	112,357	108,222	660,997	566,347
Other	7,093	4,859	18,806	22,833
Total operating revenue	620,426	627,007	2,318,235	2,412,776
Energy costs:
Purchased electricity	115,631	107,035	406,860	501,738
Electric generation fuel	54,282	93,642	150,880	208,442
Residential exchange	(16,121)	(15,295)	(56,922)	(56,430)
Purchased natural gas	31,229	27,778	247,362	168,281
Unrealized (gain) loss on derivative instruments, net	(39,942)	14,716	(3,563)	29,861
Utility operations and maintenance	141,032	142,857	444,074	450,236
Non-utility expense and other	6,340	12,436	35,143	36,813
Depreciation & amortization	161,209	138,281	462,890	483,693
Conservation amortization	21,295	17,734	69,009	71,049
Taxes other than income taxes	62,163	61,697	236,460	240,392
Total operating expenses	537,118	600,881	1,992,193	2,134,075
Operating income(loss)	83,308	26,126	326,042	278,701
Other income (expense):
Other income	13,050	15,439	43,685	44,442
Other expense	(2,160)	(2,023)	(12,910)	(5,624)
Interest charges:
AFUDC	3,847	3,732	11,404	10,652
Interest expense	(88,608)	(89,029)	(284,285)	(264,815)
Income (loss) before income taxes	9,437	(45,755)	83,936	63,356
Income tax (benefit) expense	(559)	(6,312)	2,237	3,597
Net income (loss)	9,996	(39,443)	81,699	59,759
Subsidiaries [Member]
Operating revenue:
Electric	500,976	513,926	1,638,432	1,823,596
Natural gas	112,357	108,222	660,997	566,347
Other	7,093	4,859	18,806	22,833
Total operating revenue	620,426	627,007	2,318,235	2,412,776
Energy costs:
Purchased electricity	115,631	107,035	406,860	501,738
Electric generation fuel	54,282	93,642	150,880	208,442
Residential exchange	(16,121)	(15,295)	(56,922)	(56,430)
Purchased natural gas	31,229	27,778	247,362	168,281
Unrealized (gain) loss on derivative instruments, net	(39,942)	14,716	(3,563)	29,861
Utility operations and maintenance	141,032	142,857	444,074	450,236
Non-utility expense and other	5,510	11,869	33,293	34,924
Depreciation & amortization	161,155	138,253	462,742	483,623
Conservation amortization	21,295	17,734	69,009	71,049
Taxes other than income taxes	62,163	61,697	236,460	240,392
Total operating expenses	536,234	600,286	1,990,195	2,132,116
Operating income(loss)	84,192	26,721	328,040	280,660
Other income (expense):
Other income	10,424	12,373	34,569	35,334
Other expense	(2,160)	(2,023)	(12,910)	(5,624)
Interest charges:
AFUDC	3,847	3,732	11,404	10,652
Interest expense	(61,592)	(61,145)	(184,770)	(181,230)
Income (loss) before income taxes	34,711	(20,342)	176,333	139,792
Income tax (benefit) expense	1,649	(5,085)	16,913	16,072
Net income (loss)	$ 33,062	$ (15,257)	$ 159,420	$ 123,720

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Net Income (loss)	$ 9,996	$ (39,443)	$ 81,699	$ 59,759
Other comprehensive income(loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	1,090	(1,114)	7,890	(931)
Other comprehensive income (loss)	1,090	(1,114)	7,890	(931)
Comprehensive income (loss)	11,086	(40,557)	89,589	58,828
Amortization of right-of-use asset	151	128	455	410
Interest on lease liabilities	8	10	27	29
FInance Lease, Cost	159	138	482	439
Operating lease cost	4,902	5,311	16,051	15,318
Net unrealized gain (loss) from pension and postretirement plans, net of tax	291	(297)	2,097	(247)
Subsidiaries [Member]
Net Income (loss)	33,062	(15,257)	159,420	123,720
Other comprehensive income(loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	3,195	1,340	14,765	6,362
Amortization Of Financing Cash Flow Hedge Contracts To Earnings During Period Net Of Tax	97	97	289	289
Other comprehensive income (loss)	3,292	1,437	15,054	6,651
Comprehensive income (loss)	36,354	(13,820)	174,474	130,371
Amortization of Financing Cash Flow Hedge Contracts to Earnings Tax	26	27	77	78
Net unrealized gain (loss) from pension and postretirement plans, net of tax	$ 853	$ 357	$ 3,925	$ 1,692

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Net unrealized gain (loss) from pension and postretirement plans, net of tax	$ 291	$ (297)	$ 2,097	$ (247)
Subsidiaries [Member]
Net unrealized gain (loss) from pension and postretirement plans, net of tax	853	357	3,925	1,692
Amortization of treasury interest rate swaps to earnings, net of tax	$ 26	$ 27	$ 77	$ 78

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2020	Dec. 31, 2019
Utility Plant [Abstract]
Electric plant	$ 9,103,067	$ 8,811,889
Natural gas plant	4,178,643	3,916,040
Common plant	1,097,556	1,096,649
Less: Accumulated depreciation and amortization	(3,569,494)	(3,236,240)
Net utility plant	10,809,772	10,588,338
Other property and investments:
Goodwill	1,656,513	1,656,513
Other property and investments	312,353	286,975
Total other property and investments	1,968,866	1,943,488
Current assets:
Cash and cash equivalents	21,766	45,259
Restricted cash	22,763	20,887
Accounts Receivable, after Allowance for Credit Loss, Current	232,996	316,352
Unbilled revenue	119,960	224,657
Materials and supplies, at average cost	120,049	115,684
Fuel and natural gas inventory, at average cost	56,119	52,083
Unrealized gain on derivative instruments	73,677	23,626
Prepaid expense and other	46,416	27,504
Power contract acquisition adjustment gain	14,262	9,067
Total current assets	708,008	835,119
Other long-term and regulatory assets:
Power cost adjustment mechanism	65,169	41,745
Regulatory assets related to power contracts	12,109	14,146
Other regulatory assets	713,909	673,021
Unrealized gain on derivative instruments	20,428	7,682
Power contract acquisition adjustment gain	84,522	147,530
Operating lease right-of-use asset	175,091	183,048
Other	90,691	92,980
Total other long-term and regulatory assets	1,263,826	1,292,918
Total assets	14,750,472	14,659,863
Capitalization
Common stock	0	0
Additional paid-in capital	3,308,957	3,308,957
Retained earnings	811,778	775,491
Accumulated other comprehensive income (loss), net of tax	(76,259)	(84,149)
Total common shareholder’s equity	4,044,476	4,000,299
Long-term debt:
First mortgage bonds and senior notes	4,212,000	4,212,000
Pollution control bonds	161,860	161,860
Long-term debt	1,757,900	1,758,100
Debt discount issuance costs and other	(208,962)	(211,635)
Total long-term debt	5,922,798	5,920,325
Total capitalization	9,967,274	9,920,624
Current liabilities:
Accounts payable	293,906	325,913
Short-term debt	221,000	176,000
Accrued expenses:
Taxes	109,440	99,979
Salaries and wages	40,589	50,091
Interest	81,644	74,855
Unrealized loss on derivative instruments	25,146	13,428
Power contract acquisition adjustment loss	2,113	2,418
Operating lease liabilities	19,400	15,862
Other	75,410	107,809
Total current liabilities	1,371,060	1,318,767
Other long-term and regulatory liabilities:
Unrealized loss on derivative instruments	28,389	12,693
Regulatory liabilities	776,555	730,879
Regulatory liability for deferred income taxes	922,543	946,179
Regulatory liabilities related to power contracts	98,784	156,597
Power contract acquisition adjustment loss	9,996	11,728
Operating lease liabilities	163,453	174,327
Total long-term and regulatory liabilities	3,412,138	3,420,472
Commitments and Contingencies
Total capitalization and liabilities	14,750,472	14,659,863
purchase gas adjustment, long-term	101,907	132,766
Long-term Debt, Current Maturities	502,412	452,412
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	747,255	591,199
Allowance for doubtful accounts	$ 13,889	$ 8,294
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	200	200
Other Deferred Credits	$ 563,887	$ 563,349
Deferred Tax and Other Liabilities, Noncurrent	848,531	824,720
Subsidiaries [Member]
Utility Plant [Abstract]
Electric plant	10,944,553	10,671,328
Natural gas plant	4,738,358	4,478,048
Common plant	1,121,488	1,121,568
Less: Accumulated depreciation and amortization	(5,994,627)	(5,682,606)
Net utility plant	10,809,772	10,588,338
Other property and investments:
Other property and investments	83,268	81,112
Total other property and investments	83,268	81,112
Current assets:
Cash and cash equivalents	21,028	44,004
Restricted cash	22,763	20,887
Accounts Receivable, after Allowance for Credit Loss, Current	237,969	319,229
Unbilled revenue	119,960	224,657
Materials and supplies, at average cost	120,049	115,684
Fuel and natural gas inventory, at average cost	55,108	50,818
Unrealized gain on derivative instruments	73,677	23,626
Prepaid expense and other	46,416	27,504
Total current assets	696,970	826,409
Other long-term and regulatory assets:
Power cost adjustment mechanism	65,169	41,745
Other regulatory assets	713,909	673,021
Unrealized gain on derivative instruments	20,428	7,682
Operating lease right-of-use asset	175,091	183,048
Other	89,037	90,924
Total other long-term and regulatory assets	1,165,541	1,129,186
Total assets	12,755,551	12,625,045
Capitalization
Common stock	859	859
Additional paid-in capital	3,485,105	3,485,105
Retained earnings	785,062	751,193
Accumulated other comprehensive income (loss), net of tax	(173,423)	(188,477)
Total common shareholder’s equity	4,097,603	4,048,680
Long-term debt:
First mortgage bonds and senior notes	4,212,000	4,212,000
Pollution control bonds	161,860	161,860
Debt discount issuance costs and other	(36,296)	(37,718)
Total long-term debt	4,337,564	4,336,142
Total capitalization	8,435,167	8,384,822
Current liabilities:
Accounts payable	308,935	325,980
Short-term debt	221,000	176,000
Accrued expenses:
Taxes	109,519	99,977
Salaries and wages	40,589	50,091
Interest	57,757	48,917
Unrealized loss on derivative instruments	25,146	13,428
Operating lease liabilities	19,400	15,862
Other	75,410	107,809
Total current liabilities	860,168	840,476
Other long-term and regulatory liabilities:
Unrealized loss on derivative instruments	28,389	12,693
Regulatory liabilities	775,544	729,614
Regulatory liability for deferred income taxes	923,262	946,936
Operating lease liabilities	163,453	174,327
Total long-term and regulatory liabilities	3,460,216	3,399,747
Commitments and Contingencies
Total capitalization and liabilities	12,755,551	12,625,045
purchase gas adjustment, long-term	101,907	132,766
Long-term Debt, Current Maturities	2,412	2,412
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	747,255	591,199
Allowance for doubtful accounts	$ 13,889	$ 8,294
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	85,903,791	85,903,791
Other Deferred Credits	$ 557,470	$ 559,014
Deferred Tax and Other Liabilities, Noncurrent	$ 1,012,098	$ 977,163

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2020	Dec. 31, 2019
ASSETS
Construction work in progress	$ 747,255	$ 591,199
Current assets:
Allowance for doubtful accounts	$ 13,889	$ 8,294
Common shareholder’s equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,000	1,000
Common Stock, Shares, Outstanding	200	200
Subsidiaries [Member]
ASSETS
Construction work in progress	$ 747,255	$ 591,199
Current assets:
Allowance for doubtful accounts	$ 13,889	$ 8,294
Common shareholder’s equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	150,000,000	150,000,000
Common Stock, Shares, Outstanding	85,903,791	85,903,791

CONSOLIDATED STATEMENTS OF COMM

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY Statement - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	AOCI Attributable to Parent [Member]	Subsidiaries [Member]	Subsidiaries [Member]Common Stock [Member]	Subsidiaries [Member]Additional Paid-in Capital [Member]	Subsidiaries [Member]Retained Earnings [Member]	Subsidiaries [Member]AOCI Attributable to Parent [Member]
Beginning Balance (in shares) at Dec. 31, 2018		200					85,903,791
Beginning Balance at Dec. 31, 2018	$ 3,860,758	$ 0	$ 3,308,957	$ 629,003	$ (77,202)	$ 3,707,924	$ 859	$ 3,275,105	$ 622,844	$ (190,884)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	132,154			132,154		147,302			147,302
Common stock dividend paid	(35,994)			(35,994)		(64,604)			(64,604)
Other comprehensive income (loss)	92				92	2,606				2,606
Ending Balance (in shares) at Mar. 31, 2019		200					85,903,791
Ending Balance at Mar. 31, 2019	3,957,010	$ 0	3,308,957	725,163	(77,110)	3,793,228	$ 859	3,275,105	705,542	(188,278)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Proceeds from Contributions from Parent								0
Beginning Balance (in shares) at Dec. 31, 2018		200					85,903,791
Beginning Balance at Dec. 31, 2018	3,860,758	$ 0	3,308,957	629,003	(77,202)	3,707,924	$ 859	3,275,105	622,844	(190,884)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	59,759					123,720
Other comprehensive income (loss)	(931)					6,651
Ending Balance (in shares) at Sep. 30, 2019		200					85,903,791
Ending Balance at Sep. 30, 2019	3,882,830	$ 0	3,308,957	652,006	(78,133)	3,934,433	$ 859	3,485,105	632,702	(184,233)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Proceeds from Contributions from Parent						210,000
Beginning Balance (in shares) at Mar. 31, 2019		200					85,903,791
Beginning Balance at Mar. 31, 2019	3,957,010	$ 0	3,308,957	725,163	(77,110)	3,793,228	$ 859	3,275,105	705,542	(188,278)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(32,952)			(32,952)		(8,325)			(8,325)
Common stock dividend paid	(83)			(83)		(19,384)			(19,384)
Other comprehensive income (loss)	91				91	2,608				2,608
Ending Balance (in shares) at Jun. 30, 2019		200					85,903,791
Ending Balance at Jun. 30, 2019	3,924,066	$ 0	3,308,957	692,128	(77,019)	3,768,127	$ 859	3,275,105	677,833	(185,670)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(39,443)			(39,443)		(15,257)			(15,257)
Common stock dividend paid	(679)			(679)		(29,874)			(29,874)
Other comprehensive income (loss)	(1,114)				(1,114)	1,437				1,437
Ending Balance (in shares) at Sep. 30, 2019		200					85,903,791
Ending Balance at Sep. 30, 2019	$ 3,882,830	$ 0	3,308,957	652,006	(78,133)	3,934,433	$ 859	3,485,105	632,702	(184,233)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Proceeds from Contributions from Parent						$ 210,000		210,000
Beginning Balance (in shares) at Dec. 31, 2019	200	200				85,903,791	85,903,791
Beginning Balance at Dec. 31, 2019	$ 4,000,299	$ 0	3,308,957	775,491	(84,149)	$ 4,048,680	$ 859	3,485,105	751,193	(188,477)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	94,936			94,936		111,321			111,321
Common stock dividend paid	(22,645)			(22,645)		(53,794)			(53,794)
Other comprehensive income (loss)	5,170				5,170	7,806				7,806
Ending Balance (in shares) at Mar. 31, 2020		200					85,903,791
Ending Balance at Mar. 31, 2020	$ 4,077,760	$ 0	3,308,957	847,782	(78,979)	$ 4,114,013	$ 859	3,485,105	808,720	(180,671)
Beginning Balance (in shares) at Dec. 31, 2019	200	200				85,903,791	85,903,791
Beginning Balance at Dec. 31, 2019	$ 4,000,299	$ 0	3,308,957	775,491	(84,149)	$ 4,048,680	$ 859	3,485,105	751,193	(188,477)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	81,699					159,420
Other comprehensive income (loss)	$ 7,890					$ 15,054
Ending Balance (in shares) at Sep. 30, 2020	200	200				85,903,791	85,903,791
Ending Balance at Sep. 30, 2020	$ 4,044,476	$ 0	3,308,957	811,778	(76,259)	$ 4,097,603	$ 859	3,485,105	785,062	(173,423)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Proceeds from Contributions from Parent						0
Beginning Balance (in shares) at Mar. 31, 2020		200					85,903,791
Beginning Balance at Mar. 31, 2020	4,077,760	$ 0	3,308,957	847,782	(78,979)	4,114,013	$ 859	3,485,105	808,720	(180,671)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(23,233)			(23,233)		15,037			15,037
Common stock dividend paid	(22,419)			(22,419)		(46,015)			(46,015)
Other comprehensive income (loss)	1,630				1,630	3,956				3,956
Ending Balance (in shares) at Jun. 30, 2020		200					85,903,791
Ending Balance at Jun. 30, 2020	4,033,738	$ 0	3,308,957	802,130	(77,349)	4,086,991	$ 859	3,485,105	777,742	(176,715)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	9,996			9,996		33,062			33,062
Common stock dividend paid	(348)			(348)		(25,742)			(25,742)
Other comprehensive income (loss)	$ 1,090				1,090	$ 3,292				3,292
Ending Balance (in shares) at Sep. 30, 2020	200	200				85,903,791	85,903,791
Ending Balance at Sep. 30, 2020	$ 4,044,476	$ 0	$ 3,308,957	$ 811,778	$ (76,259)	$ 4,097,603	$ 859	$ 3,485,105	$ 785,062	$ (173,423)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended				9 Months Ended		12 Months Ended
	Sep. 30, 2020	Mar. 31, 2020	Sep. 30, 2019	Mar. 31, 2019	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019
Operating activities:
Net Income (loss)	$ 9,996	$ 94,936	$ (39,443)	$ 132,154	$ 81,699	$ 59,759
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation & amortization	161,209		138,281		462,890	483,693
Conservation amortization	21,295		17,734		69,009	71,049
Deferred income taxes and tax credits, net					(1,922)	(3,559)
Net unrealized (gain) loss on derivative instruments					(3,563)	29,861
Gain (Loss) on Extinguishment of Debt					13,546	0
AFUDC - equity					(17,772)	(10,071)
Production tax credit utilization					(17,558)	(35,470)
Other non-cash					5,466	1,712
increase (decrease) in purchased gas					30,859	(155,711)
Other long term assets and liabilities					(17,094)	(3,075)
Regulatory assets and liabilities					(90,513)	(46,993)
Funding of pension liability					(18,000)	(18,000)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue					188,053	192,365
Materials and supplies					(4,365)	(3,963)
Fuel and natural gas inventory					(4,290)	(8,442)
Prepayments and other					(18,912)	(2,283)
Purchased gas adjustment					0	9,921
Accounts payable					(26,068)	(160,792)
Taxes payable					9,461	(43,141)
Other					(25,086)	(2,727)
Net cash provided by (used in) operating activities					615,840	354,133
Investing activities:
Construction expenditures - excluding equity AFUDC					(678,085)	(709,139)
Other					(925)	(5,914)
Net cash provided by (used in) investing activities					(679,010)	(715,053)
Financing activities:
Change in short-term debt, net					45,000	(310,297)
Dividends paid					(45,412)	(36,756)
Proceeds from long-term debt and bonds issued					644,690	682,151
Repayments of Debt					(150,200)	0
Redemption of bonds and notes					(450,000)	0
Other					(2,525)	10,386
Net cash provided by (used in) financing activities					41,553	345,484
Net increase (decrease) in cash, cash equivalents, and restricted cash					(21,617)	(15,436)
Cash, cash equivalents, and restricted cash at beginning of period		66,146		55,562	66,146	55,562	$ 55,562
Cash, cash equivalents, and restricted cash at end of period	44,529		40,126		44,529	40,126	66,146
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)					245,183	236,718
Cash payments (refunds) for income taxes					3,820	8,990
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows					67,321	65,023
Increase (Decrease) in Regulatory Assets and Liabilities					0	(47,534)
Subsidiaries [Member]
Operating activities:
Net Income (loss)	33,062	111,321	(15,257)	147,302	159,420	123,720
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation & amortization	161,155		138,253		462,742	483,623
Conservation amortization	21,295		17,734		69,009	71,049
Deferred income taxes and tax credits, net					7,259	(1,600)
Net unrealized (gain) loss on derivative instruments					(3,563)	29,861
AFUDC - equity					(17,772)	(10,071)
Production tax credit utilization					(17,558)	(35,470)
Other non-cash					(2,441)	(6,167)
increase (decrease) in purchased gas					30,859	(155,711)
Other long term assets and liabilities					(8,391)	4,972
Regulatory assets and liabilities					(90,513)	(46,993)
Funding of pension liability					18,000	18,000
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue					185,957	196,877
Materials and supplies					(4,365)	(3,963)
Fuel and natural gas inventory					(4,290)	(8,442)
Prepayments and other					(18,912)	(2,283)
Purchased gas adjustment					0	9,921
Accounts payable					(26,038)	(160,850)
Taxes payable					9,542	(40,178)
Other					(22,628)	794
Net cash provided by (used in) operating activities					690,317	431,089
Investing activities:
Construction expenditures - excluding equity AFUDC					(641,862)	(680,118)
Other					(925)	(5,916)
Net cash provided by (used in) investing activities					(642,787)	(686,034)
Financing activities:
Change in short-term debt, net					45,000	(310,297)
Dividends paid					(125,551)	(113,862)
Proceeds from long-term debt and bonds issued					0	443,151
Proceeds from Contributions from Parent			210,000		0	210,000
Other					11,921	11,048
Net cash provided by (used in) financing activities					(68,630)	240,040
Net increase (decrease) in cash, cash equivalents, and restricted cash					(21,100)	(14,905)
Cash, cash equivalents, and restricted cash at beginning of period		$ 64,891		$ 53,493	64,891	53,493	53,493
Cash, cash equivalents, and restricted cash at end of period	$ 43,791		$ 38,588		43,791	38,588	$ 64,891
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)					161,083	152,571
Cash payments (refunds) for income taxes					9,259	16,540
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows					67,321	65,023
Increase (Decrease) in Regulatory Assets and Liabilities					$ 0	$ (47,534)

Summary of Consolidation and Si

Summary of Consolidation and Significant Accounting Policy	3 Months Ended
	Sep. 30, 2020
Accounting Policies [Abstract]
Significant Accounting Policies	Summary of Consolidation and Significant Accounting Policy Basis of Presentation Puget Energy is an energy services holding company that owns PSE. PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC, (Puget LNG) which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma liquefied natural gas (LNG) facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that are incurred by PSE and allocated to Puget LNG are related party transactions by nature. In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations”, 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” 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. Allowance for Credit Losses On January 1, 2020, the Company adopted Accounting Standards Update (ASU) 2016-13 Financial Instruments – Credit Losses (ASC 326) which replaces the incurred loss methodology with an expected loss methodology that is referred to as the current expected credit loss (CECL) methodology. The measurement of expected credit losses under the CECL methodology is applicable to financial assets measured at amortized cost, including trade receivables, loan receivables, and held-to-maturity debt securities. It also applies to off-balance sheet credit exposures not accounted for as insurance (loan commitments, standby letters of credit, financial guarantees, and other similar instruments) and net investments in leases recognized by a lessor in accordance with Topic 842 on leases. The only financial assets within the scope of ASU 2016-13 for the Company are trade receivables. The Company adopted ASU 2016-13 using the modified retrospective method. Results for reporting periods beginning after January 1, 2020 are presented under ASC 326 while prior period amounts continue to be reported in accordance with previously applicable GAAP. The Company did not record an adjustment to retained earnings as of January 1, 2020, for the cumulative effect of adopting ASU 2016-13, as the impact was immaterial. Management measures expected credit losses on trade receivables on a collective basis by receivable type, which include electric retail receivables, gas retail receivables, and electric wholesale receivables. The estimate of expected credit losses considers historical credit loss information that is adjusted for current conditions and reasonable and supportable forecasts. The following table presents the activity in the allowance for credit losses for accounts receivable for the nine months ended September 30, 2020: Puget Energy and (Dollars in Thousands) September 30, Allowance for credit losses: Beginning balance $ 8,294 Provision for credit loss expense 14,660 Receivables charged-off (9,065) Total ending allowance balance $ 13,889 Tacoma LNG Facility In August 2015, PSE filed a proposal with the Washington Commission to develop an LNG facility at the Port of Tacoma. Currently under construction at the Port of Tacoma, the facility is expected to be operational in 2021. The Tacoma LNG facility is designed to provide peak-shaving services to PSE’s natural gas customers. By storing surplus natural gas, PSE is able to meet the requirements of peak consumption. LNG will also provide fuel to transportation customers, particularly in the marine market. On January 24, 2018, Puget Sound Clean Air Agency (PSCAA) determined a Supplemental Environmental Impact Statement (SEIS) was necessary in order to rule on the air quality permit for the facility. As a result of requiring a SEIS, the Company's construction schedule was impacted. PSE received the SEIS which concluded the LNG facility would result in a net decrease in greenhouse gas (GHG) emissions providing, in part, that the natural gas for the facility was sourced from British Columbia or Alberta. On December 10, 2019, the PSCAA approved the Notice of Construction permit, a decision which has been appealed to the Washington Pollution Control Hearings Board by each of the Puyallup Tribe of Indians and nonprofit law firm Earthjustice. If delayed, the construction schedule and costs may be adversely impacted. 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, $221.2 million and $199.9 million of construction work in progress related to Puget LNG's portion of the Tacoma LNG facility is reported in the Puget Energy "Other property and investments" line item as of September 30, 2020, and December 31, 2019, respectively. Additionally, $0.5 million and $1.0 million of operating costs are reported in the Puget Energy "Non-utility expense and other" financial statement line item for the nine months ended September 30, 2020:, and September 30, 2019, respectively. Additionally, $196.7 million and $162.8 million of construction work in progress related to PSE’s portion of the Tacoma LNG facility is reported in the PSE “Utility plant - Natural gas plant” financial statement line item as of September 30, 2020, and December 31, 2019, respectively, as PSE is a regulated entity.

New Accounting Pronouncements

New Accounting Pronouncements	9 Months Ended
	Sep. 30, 2020
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements	New Accounting Pronouncements 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 August 2018, the FASB issued ASU 2018-13, "Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement" . The amendments in this update modify the disclosure requirements on fair value measurements in Topic 820, Fair Value Measurement, based on the concepts in the Concepts Statement, including the consideration of costs and benefits. The amendments are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The Company adopted this update as of January 1, 2020, and it impacted Note 5, "Fair Value Measurements". As the amendment contemplates changes in disclosures only, it has no material impact on the Company's results of operations, cash flows, or consolidated balance sheets. Reference Rate Reform In March 2020, the FASB issued ASU 2020-04, "Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting ” (Issued March 2020): ASU 2020-04 provides temporary optional expedients and exceptions to the current guidance on contract modifications to ease the financial reporting burdens related to the expected market transition from London Interbank Offered Rate (LIBOR) and other interbank offered rates to alternative reference rates. The Company has term loans, credit agreements, and promissory notes that reference LIBOR. As of September 30, 2020, the Company has not utilized any of the expedients discussed within this ASU, however, it continues to assess other agreements to determine if LIBOR is included and if the expedients would be utilized through the allowed period of December 2022. Accounting Standards Issued but Not Yet Adopted Retirement Benefits In August 2018, the FASB issued ASU 2018-14, " Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans" . This update modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans through added, removed, and clarified requirements of relevant disclosures. The amendments in this update are effective for fiscal years ending after December 15, 2020, for public business entities and for fiscal years ending after December 15, 2021, for all other entities. Accordingly, the Company will implement this update as of December 31, 2020 on a retrospective basis to all periods presented. The Company is in the process of evaluating potential impacts of these amendments to the required annual retirement benefits disclosures.

Revenue

Revenue	9 Months Ended
	Sep. 30, 2020
Revenue from Contract with Customer [Abstract]
Revenue	Revenue The following table presents disaggregated revenue from contracts with customers, and other revenue by major source: Puget Energy and (Dollars in Thousands) Three Months Ended September 30, Nine Months Ended September 30, Revenue from contracts with customers: 2020 2019 2020 2019 Electric retail $ 458,573 $ 450,109 $ 1,499,378 $ 1,550,517 Natural gas retail 103,486 101,395 637,239 569,177 Other 46,111 72,691 125,227 245,285 Total revenue from contracts with customers 608,170 624,195 2,261,844 2,364,979 Alternative revenue programs 2,189 874 23,089 (20,006) Other non-customer revenue 10,067 1,938 33,302 67,803 Total operating revenue $ 620,426 $ 627,007 $ 2,318,235 $ 2,412,776 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 Revenue Transmission and transportation tariff contracts include the performance obligation to transmit and transport electricity or natural gas. Transfer of control and recognition of revenue occurs over time as the customer simultaneously receives the transmission and transportation services. Measurement of satisfaction of this performance obligation is determined using the output method. Similar to retail revenue, the Company utilizes the right to invoice practical expedient as PSE’s right to consideration is tied directly to the value of power and natural gas transmitted and transported each month. The price is based on the tariff rates that were approved by the Washington Commission or the FERC and, therefore, corresponds directly to the value to the customer for performance completed to date. Biogas Biogas is a renewable natural gas fuel that PSE purchases and sells along with the renewable green attributes derived from the renewable natural gas. Biogas contracts include the performance obligations of biogas and renewable credit delivery upon PSE receiving produced biogas from its supplier. Transfer of control and recognition of revenue occurs at a point in time as biogas is considered a storable commodity and may not be consumed as it is delivered. Wholesale Wholesale revenue at PSE includes sales of electric power and non-core natural gas to other utilities or marketers. Wholesale revenue contracts include the performance obligation of physical electric power or natural gas. There are typically no added fixed or variable amounts on top of the established rate for power or natural gas and contracts always have a stated, fixed quantity of power or natural gas delivered. Transfer of control and recognition of revenue occurs at a point in time when the customer takes physical possession of electric power or natural gas. Non-core gas consists of natural gas supply in excess of natural gas used for generation, sold to third parties to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. PSE reports non-core gas sold net of costs as PSE does not take control of the natural gas but is merely an agent within the market that connects a seller to a purchaser. Other Revenue

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	9 Months Ended
	Sep. 30, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Accounting for Derivative Instruments and Hedging Activities	Accounting for Derivative Instruments and Hedging ActivitiesPSE employs various energy portfolio optimization strategies but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the power cost adjustment (PCA). Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility of 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 September 30, 2020 December 31, 2019 (Dollars in Thousands) Volumes Assets 1 Liabilities 2 Volumes Assets 1 Liabilities 2 Electric portfolio derivatives * $ 48,876 $ 42,884 * $ 19,933 $ 17,504 Natural gas derivatives (MMBtus) 3 284.9 million 45,229 10,651 315.5 million 11,375 8,617 Total derivative contracts $ 94,105 $ 53,535 $ 31,308 $ 26,121 Current $ 73,677 $ 25,146 $ 23,626 $ 13,428 Long-term 20,428 28,389 7,682 12,693 Total derivative contracts $ 94,105 $ 53,535 $ 31,308 $ 26,121 _______________ 1 Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments. 2 Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments. 3 All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the purchased gas adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 212.3 million One Million British Thermal Units (MMBtu) and purchased electricity of 7.8 million Megawatt Hours (MWhs) at September 30, 2020, and 229.3 million MMBtus and 10.4 million MWhs at December 31, 2019. It is the Company's policy to record all derivative transactions on a gross basis at the contract level without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements, which standardize physical power contracts; International Swaps and Derivatives Association (ISDA) agreements, which standardize financial natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical natural gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as the right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount. For further details regarding the fair value of derivative instruments, see Note 5, "Fair Value Measurements," to the consolidated financial statements included in Item 1 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 At September 30, 2020 Gross Amount Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 94,105 $ — $ 94,105 $ (37,723) $ — $ 56,382 Liabilities: Energy derivative contracts $ 53,535 $ — $ 53,535 $ (37,723) $ (1,614) $ 14,198 Puget Energy and At December 31, 2019 Gross Amount Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position (Dollars in Thousands) Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 31,308 $ — $ 31,308 $ (14,922) $ — $ 16,386 Liabilities: Energy derivative contracts $ 26,121 $ — $ 26,121 $ (14,922) $ 2,000 $ 13,199 _______________ 1 All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off. The following table presents the effect and classification of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income: Puget Energy and Three Months Ended Nine Months Ended (Dollars in Thousands) Classification 2020 2019 2020 2019 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net $ 29,940 $ 8,143 $ 24,950 $ 5,914 Realized Electric generation fuel 358 (7,514) 911 4,481 Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 10,002 (22,859) (21,386) (35,775) Realized Purchased electricity 3,579 (335) (8,584) 40,918 Total gain (loss) recognized in income on derivatives $ 43,879 $ (22,565) $ (4,109) $ 15,538 The Company is exposed to credit risk primarily through buying and selling electricity and natural gas to serve its customers. Credit risk is the potential loss resulting from a counterparty's non-performance under an agreement. The Company manages credit risk with policies and procedures for, among other things, counterparty credit analysis, exposure measurement, and exposure monitoring and mitigation. The Company monitors counterparties for significant swings in credit default swap rates, credit rating changes by external rating agencies, ownership changes or financial distress. Where deemed appropriate, the Company may request collateral or other security from its counterparties to mitigate potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of September 30, 2020, approximately 98.8% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, is with counterparties that are rated investment grade by rating agencies and 1.2% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies. The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors in the determination of reserves, such as credit default swaps and bond spreads. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels. The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against the unrealized gain (loss) positions. 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 September 30, 2020, PSE had cash posted as collateral of $12.4 million related to contracts executed on the ICE platform. Also, as of September 30, 2020, PSE had $3.0 million in cash posted as collateral and $1.0 million in a 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 nine months ended September 30, 2020. 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 (Dollars in Thousands) At September 30, 2020 At December 31, 2019 Fair Value 1 Posted Contingent Fair Value 1 Posted Contingent Contingent Feature Liability Collateral Collateral Liability Collateral Collateral Credit rating 2 $ 23,792 $ — $ 23,792 $ 6,110 $ — $ 6,110 Requested credit for adequate assurance 5,116 — — 5,253 — — Forward value of contract 3 1,614 15,325 N/A — 14,827 N/A Total $ 30,522 $ 15,325 $ 23,792 $ 11,363 $ 14,827 $ 6,110 _______________ 1 Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable. 2 Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral. 3 . Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2020
Fair Value Disclosures [Abstract]
Fair Value Disclosures	(5) 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 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 totaling $52.4 million at September 30, 2020, and $51.5 million at December 31, 2019, 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 long-term notes was estimated using the discounted cash flow method with the U.S. Treasury yields and the 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 At September 30, 2020 At December 31, 2019 (Dollars in Thousands) Level Carrying Fair Carrying Fair Liabilities: Long-term debt (fixed-rate), net of discount 1 2 $ 5,664,898 $ 7,758,559 $ 5,512,225 $ 7,004,316 Long-term debt (variable-rate) 2 257,900 257,900 408,100 408,100 Total liabilities $ 5,922,798 $ 8,016,459 $ 5,920,325 $ 7,412,416 Puget Sound Energy At September 30, 2020 At December 31, 2019 (Dollars in Thousands) Level Carrying Fair Carrying Fair Liabilities: Long-term debt (fixed-rate), net of discount 2 2 $ 4,337,564 $ 6,127,167 $ 4,336,142 $ 5,571,818 Total liabilities $ 4,337,564 $ 6,127,167 $ 4,336,142 $ 5,571,818 _______________ 1 The carrying value includes debt issuances costs of $23.1 million and $24.1 million for September 30, 2020, and December 31, 2019, respectively, which are not included in fair value. 2 The carrying value includes debt issuances costs of $23.3 million and $24.4 million for September 30, 2020, and December 31, 2019, respectively, which are not included in fair value. Assets and Liabilities Measured at Fair Value on a Recurring Basis The following table presents 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: Puget Energy and Fair Value Fair Value (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 47,959 $ 917 $ 48,876 $ 19,282 $ 651 $ 19,933 Natural gas derivative instruments 44,966 263 45,229 9,852 1,523 11,375 Total assets $ 92,925 $ 1,180 $ 94,105 $ 29,134 $ 2,174 $ 31,308 Liabilities: Electric derivative instruments $ 19,720 $ 23,164 $ 42,884 $ 13,474 $ 4,030 $ 17,504 Natural gas derivative instruments 9,912 739 10,651 8,376 241 8,617 Total liabilities $ 29,632 $ 23,903 $ 53,535 $ 21,850 $ 4,271 $ 26,121 The following tables present the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy and Three Months Ended (Dollars in Thousands) 2020 2019 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ (28,609) $ 342 $ (28,267) $ (2,446) $ 2,398 $ (48) Changes during period: Realized and unrealized energy derivatives: Included in earnings 1 5,516 — 5,516 (4,611) — (4,611) Included in regulatory assets / liabilities — (471) (471) — 206 206 Settlements 846 (347) 499 2,529 (1,167) 1,362 Transferred into Level 3 — — — — — — Transferred out of Level 3 — — — — — — Balance at end of period $ (22,247) $ (476) $ (22,723) $ (4,528) $ 1,437 $ (3,091) Puget Energy and Nine Months Ended (Dollars in Thousands) 2020 2019 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ (3,378) $ 1,282 $ (2,096) $ 1,362 $ 1,673 $ 3,035 Changes during period: Realized and unrealized energy derivatives: Included in earnings 2 (21,321) — (21,321) 1,524 — 1,524 Included in regulatory assets / liabilities — (187) (187) — 2,485 2,485 Settlements 2,452 (1,571) 881 (10,380) (3,885) (14,265) Transferred into Level 3 — — — 4,390 (400) 3,990 Transferred out of Level 3 — — — (1,424) 1,564 140 Balance at end of period $ (22,247) $ (476) $ (22,723) $ (4,528) $ 1,437 $ (3,091) _______________ 1. Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $4.8 million and $(4.5) million for three months ended September 30, 2020 and 2019 , respectively. 2. Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(19.0) million and $(4.4) million for nine months ended September 30, 2020 and 2019 , respectively. 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. 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. The weighted average price is calculated as the total market value divided by the total volume of the Company's Level 3 electric and gas commodity contracts, respectively, as of the reporting date. The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of September 30, 2020: Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 917 $ 23,164 Discounted cash flow Power prices (per MWh) $ 23.80 $ 46.25 $ 32.85 Natural gas $ 263 $ 739 Discounted cash flow Natural gas prices (per MMBtu) $ 1.56 $ 3.61 $ 2.50 _______________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2019: Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 651 $ 4,030 Discounted cash flow Power prices (per MWh) $ 9.00 $ 43.85 $ 33.99 Natural gas $ 1,523 $ 241 Discounted cash flow Natural gas prices (per MMBtu) $ 1.25 $ 3.18 $ 2.47 ___________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently, significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. As of September 30, 2020, and December 31, 2019, a hypothetical 10.0% 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 $6.0 million and $2.5 million, respectively. 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. At March 31, 2020, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. These intangible assets exist as a result of the merger in 2009, at which time the consolidated assets and liabilities were revalued in accordance with ASC 805, "Business Combinations". Differences between the fair market value and the carrying value of assets held at PSE were recorded at PE. The Rocky Reach contract was determined to be impaired due to a decrease in forward prices for this contract of 7.6% from December 31, 2019, causing an impairment of $52.6 million. While this impairment of the intangible asset held at Puget Energy is the result of a decline in forward prices and the corresponding valuation impact, the underlying power purchase contract is included within rates at PSE. The following table presents the impairment recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability: 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 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. The unobservable input averages disclosed below represent the arithmetic average of the inputs and are not weighted by volume. A less significant input is the discount rate reflective of a market participant's cost of capital used in the valuation. The following table presents the significant unobservable inputs used in estimating the impaired long-term power purchase contracts' fair value: Puget Energy Valuation Date Unobservable Input Low High Average March 31, 2020 Power prices (per MWh) $ 10.23 $ 29.05 $ 21.27 Power contract costs per quarter (in thousands) $ 6,308 $ 7,085 $ 6,468 December 31, 2019 Power prices (per MWh) $ 11.75 $ 31.44 $ 22.53 Power contract costs per quarter (in thousands) $ 6,237 $ 7,087 $ 6,421

Retirement Benefits

Retirement Benefits	3 Months Ended
	Sep. 30, 2020
Subsidiaries [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension and Other Postretirement Benefits Disclosure [Text Block]	Retirement Benefits PSE has a defined benefit pension plan (Qualified Pension Benefits) covering a substantial majority of PSE employees. Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates. United Association of Plumbers and Pipefitters (UA) represented employees receive annual pay contributions of 4.0% of eligible pay each year in the cash balance formula plan of the defined benefit pension. Non-represented employees and employees represented by the International Brotherhood of Electrical Workers Union (IBEW), receive annual employer contributions of 4.0% of eligible pay each year in the cash balance formula of the defined benefit pension or 401k plan account. Those employees receiving contributions in the cash balance formula plan also receive interest credits, which are at least 1.0% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, they will have annuity and lump sum options for distribution. PSE also has a non-qualified Supplemental Executive Retirement Plan (SERP) for certain key senior management employees that closed to new participants in 2019. PSE has an officer restoration benefit for new officers who join PSE or are promoted beginning in 2019, such that company contributions under PSE’s applicable tax-qualified plan, which otherwise would have been earned if not for IRS limitations, are credited to an account with the Deferred Compensation Plan. In addition to providing pension benefits, PSE provides legacy group health care and life insurance benefits (Other Benefits) for certain retired employees. These benefits are provided principally through an insurance company. The insurance premiums, paid primarily by retirees, are based on the benefits provided during the prior year. On June 11, 2019, the Welfare Benefits Committee approved the termination of the Plan effective December 31, 2019, and the creation of a Retiree Health Reimbursement Account (HRA) Plan effective January 1, 2020. No eligible individual may become a participant or covered dependent in the Plan on or after January 1, 2020, and no benefits will be payable under insurance contracts or the Plan on or after January 1, 2020. Effective January 1, 2020, assets in the 401(h) account will be allocated to the Retiree HRA instead of the Plan to cover the Company's portion of premiums for health benefits for retiree and their beneficiaries. Puget Energy's retirement plans were remeasured as a result of the merger in 2009, which represents the difference between Puget Energy and PSE's retirement plans. In 2017, the FASB issued ASU 2017-07, requiring that an employer report the service cost component in the same line items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. Pursuant to the standard, the Company has retrospectively included in the consolidated statements of income: (i) the components of service cost within utility operations and maintenance for PSE and within non-utility expense and other for Puget Energy, and (ii) all non-service cost components in other income. The following tables summarize the Company’s net periodic benefit cost for the three and nine months ended September 30, 2020 and 2019: Puget Energy Qualified SERP Other Three Months Ended September 30, (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Components of net periodic benefit cost: Service cost $ 6,084 $ 6,418 $ 176 $ 256 $ 47 $ 13 Interest cost 6,295 7,252 362 578 92 84 Expected return on plan assets (12,476) (12,439) — — (97) (100) Amortization of prior service cost (393) (495) 87 83 — — Amortization of net loss (gain) 2,040 362 512 341 (20) (156) Net periodic benefit cost $ 1,550 $ 1,098 $ 1,137 $ 1,258 $ 22 $ (159) Puget Energy Qualified SERP Other Nine Months Ended September 30, (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Components of net periodic benefit cost: Service cost $ 18,253 $ 16,992 $ 580 $ 768 $ 142 $ 46 Interest cost 18,885 21,685 1,102 1,735 276 308 Expected return on plan assets (37,427) (37,686) — — (292) (295) Amortization of prior service cost (1,180) (1,485) 262 249 — — Amortization of net loss (gain) 6,120 863 1,610 1,024 (61) (281) Net periodic benefit cost $ 4,651 $ 369 $ 3,554 $ 3,776 $ 65 $ (222) Puget Sound Energy Qualified SERP Other Three Months Ended September 30, (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Components of net periodic benefit cost: Service cost $ 6,084 $ 6,418 $ 176 $ 256 $ 47 $ 13 Interest cost 6,295 7,252 362 578 92 84 Expected return on plan assets (12,478) (12,443) — — (97) (100) Amortization of prior service cost (393) (393) 87 83 — — Amortization of net loss (gain) 4,761 3,328 575 433 (34) (202) Net periodic benefit cost $ 4,269 $ 4,162 $ 1,200 $ 1,350 $ 8 $ (205) Puget Sound Energy Qualified SERP Other Nine Months Ended September 30, (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Components of net periodic benefit cost: Service cost $ 18,253 $ 16,992 $ 580 $ 768 $ 142 $ 46 Interest cost 18,885 21,685 1,102 1,735 276 308 Expected return on plan assets (37,433) (37,700) — — (292) (295) Amortization of prior service cost (1,180) (1,180) 262 250 — — Amortization of net loss (gain) 14,283 9,657 1,810 1,300 (103) (421) Net periodic benefit cost $ 12,808 $ 9,454 $ 3,754 $ 4,053 $ 23 $ (362) The following table summarizes the Company’s change in benefit obligation for the periods ended September 30, 2020 and December 31, 2019: Puget Energy and Qualified SERP Other Nine Months Ended Year Ended Nine Months Ended Year Ended Nine Months Ended Year Ended (Dollars in Thousands) September 30, December 31, September 30, December 31, September 30, December 31, Change in benefit obligation: Benefit obligation at beginning of period $ 774,305 $ 677,643 $ 63,000 $ 55,708 $ 11,627 $ 10,636 Amendments — — — — — 9,049 Service cost 18,253 22,656 580 1,023 142 61 Interest cost 18,885 28,913 1,102 2,314 276 410 Curtailment Loss / (Gain) — — — — — (7,486) Actuarial loss (gain) 1,134 84,272 (478) 6,756 34 (287) Benefits paid (35,984) (36,740) (18,140) (2,801) (740) (982) Medicare part D subsidy received — — — — 187 226 Administrative Expense — (2,439) — — — — Benefit obligation at end of period $ 776,593 $ 774,305 $ 46,064 $ 63,000 $ 11,526 $ 11,627 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, 2020, are expected to be at least $18.0 million, $26.1 million and $0.3 million, respectively. During the nine months ended September 30, 2020, the Company contributed $18.0 million and $18.1 million to fund the qualified pension plan and SERP, respectively. During the nine months ended September 30, 2019, the Company contributed $18.0 million and $2.3 million to fund the qualified pension plan and SERP, respectively. The Company contributed an immaterial amount to fund the other postretirement plans.

Regulated Operations

Regulated Operations	9 Months Ended
	Sep. 30, 2020
Regulation and Rates [Abstract]
Regulation and Rates Disclosure	Regulation and Rates General Rate Case PSE filed a general rate case (GRC) with the Washington Commission on June 20, 2019 requesting an overall increase in electric and natural gas rates of 6.9% and 7.9% respectively. PSE requested a return on equity of 9.8% with an overall rate of return of 7.62%. In addition to the traditional areas of focus (revenue requirements, cost allocation, rate design and cost of capital), the Company completed an attrition study and included a portion of the attrition revenue requirement in the overall request in order to address the expected regulatory lag in the rate year. Additionally, as the non-plant related excess deferred taxes that resulted from the Tax Cuts and Jobs Act (TCJA) remained outstanding from PSE’s Expedited Rate Filing (ERF) as discussed below, PSE requested in its GRC to pass back the amounts over four years. On September 17, 2019, PSE filed supplemental testimony, which provided certain updates to the original filing, but did not impact the requested overall electric and natural gas rate increases, return on equity or overall rate of return as originally filed. On January 15, 2020, PSE filed rebuttal testimony which included a reduction to the requested return on equity to 9.5%, which decreased the rate of return to 7.48%. The requested rate increase for both electric and natural gas remained at 6.9% and 7.9%, respectively. For both electric and natural gas PSE did not originally request its full attrition adjustment; therefore, the decrease in return on equity led to a reduction in the electric rate increase of only $1.5 million and did not have an impact on the natural gas rate increase. On July 8, 2020, the Washington Commission issued its order on PSE’s GRC. The ruling provided for a weighted cost of capital of 7.39% or 6.8% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.4%. The order also resulted in a combined net increase to electric of $29.5 million, or 1.6%, and to natural gas of $36.5 million, or 4.0%. However, the Washington Commission extended the amortization of certain regulatory assets, PSE’s electric decoupling deferral, and PSE’s PGA deferral to mitigate the impact of the rate increase in response to the economic instability created by the COVID-19 pandemic, which reduced the electric revenue increase to approximately $0.9 million, or 0.05% and the natural gas increase to $1.3 million, or 0.15%. The Washington Commission also determined that the Company’s proposed attrition adjustment of $23.9 million for electric and $16.2 million for natural gas was not in the public interest at this time. The order also effectively ends the deferral of PSE’s advanced metering infrastructure (AMI) investment while allowing the deferral on the return on AMI investments through December 31, 2019. Additional AMI investments will be evaluated in future proceedings for deferrals of return until the AMI project is complete. On July 17, 2020, PSE filed a motion for clarification with the Washington Commission seeking clarification on several items. On July 31, 2020, the Washington Commission issued an order granting PSE’s motion for clarification. The ruling adjusted certain items from the final order issued on July 8, 2020, which led to a combined net increase to electric of $59.6 million, or 2.9%, an increase of $30.1 million above the $29.5 million granted in the final order. The order also led to a combined net increase to natural gas of $42.9 million, or 5.6%, an increase of $6.4 million above the $36.5 million granted in the final order. The Washington Commission maintained adjustments which mitigated the impacts of the rate increases in response to the economic instability created by the COVID-19 pandemic, which reduced the electric revenue increase to approximately $27.7 million, or 1.3% and the natural gas increase to $0.2 million, or 0.02%. On August 6, 2020, PSE filed a petition for judicial review with the Superior Court of the State of Washington for King County (Superior Court) challenging the portion of the final order that requires PSE to pass back to customers the reversal of plant-related excess deferred income taxes in a manner that may deviate from the IRS normalization and consistency rules. On August 7, 2020, PSE filed a motion to stay with the Superior Court related to the portions of the final order under judicial review. On September 14, 2020, the Superior Court denied PSE's motion to stay. PSE reviewed the original Washington Commission order including the ramifications of certain tax issues and will file a Private Letter Ruling (PLR) with the IRS on this matter. PSE will continue to utilize the average rate assumption method (ARAM) in the turnaround of certain accelerated tax depreciation benefits on PSE assets. There is approximately $25.6 million in annual revenue requirement related to the 2019 GRC which PSE has requested it be allowed to track in order to allow the Washington Commission to decide if it is appropriate for PSE to recover, pending the outcome of the IRS ruling. On September 23, 2020, PSE filed a compliance filing. The natural gas tariffs became effective October 1, 2020 and the electric tariffs on October 15, 2020. On October 7, 2020, PSE, the Washington Commission and interveners agreed to dismiss the petition for judicial review. The agreement is based on a commitment from the Washington Commission that if the IRS ruling finds that the Washington Commission’s methodology for reversing plant-related excess deferred income taxes is impermissible, the Washington Commission will open a proceeding to review and enact the changes required by the IRS ruling. Expedited Rate Filing On November 7, 2018, PSE filed an ERF with the Washington Commission. The filing requested to change rates associated with PSE’s delivery and fixed production costs. It did not include variable power costs, purchased gas costs or natural gas pipeline replacement program costs, which are recovered in separate mechanisms. The filing was based on historical test year costs and rate base, and followed the reporting requirements of a Commission Basis Report, as defined by the Washington Administrative Code, but used end of period rate base and certain annualizing adjustments. It did not include any forward-looking or pro-forma adjustments. Included in the filing was a reduction to the overall authorized rate of return from 7.6% to 7.49% to recognize a reduction in debt costs associated with recent debt activity. PSE requested an overall increase in electric rates of $18.9 million annually, which is a 0.9% increase, and an overall increase in natural gas rates of $21.7 million annually, which is a 2.7% increase. On January 22, 2019, all parties in the proceeding reached an agreement on settlement terms that resolved all issues in the filing. The settlement agreement was filed on January 30, 2019. The parties agreed to a $21.5 million rate increase for natural gas and no rate increase for electric which became effective March 1, 2019. As is discussed below, these rates include the offsetting effect of passing back to customers plant related excess deferred income taxes that resulted from the TCJA, using the ARAM amounts to arrive at the settlement rate changes. The settlement agreement provides for the pass back of plant related excess deferred income taxes that resulted from the TCJA using the ARAM methodology based on 2018 amounts beginning March 1, 2019, in the amount of $6.1 million for natural gas customers and $25.9 million for electric customers. The settlement agreement left the determination for the regulatory treatment of the remaining items related to the TCJA, listed below, to PSE’s GRC that was filed June 20, 2019: 1) excess deferred taxes for non-plant-related book/tax differences for periods prior to March 1, 2019, 2) the deferred balance associated with the over-collection of income tax expense for the period January 1 through April 30, 2018, (the time period that encompasses the effective date of the TCJA to May 1, 2018, the effective date of the TCJA rate change); and 3) the turnaround of plant related excess deferred income taxes using the ARAM method for the period from January 2018 through February 2019, the rate effective date for the ERF. The settlement agreement provides that PSE may defer the depreciation expense associated with PSE’s ongoing investment in its AMI investment and may defer the return on the AMI investment that was included in the test year of the filing. As noted above, the 2019 GRC effectively ends all deferrals of AMI depreciation expense and deferrals of return on additional AMI investments will be evaluated in future proceedings. The rate of return adopted in the settlement for reporting and deferral purposes is 7.49%. On February 21, 2019, the Washington Commission approved the settlement with one condition: PSE passed back the deferred balance associated with the tax over-collection of $34.6 million for the period from January 1, 2018, through April 30, 2018, over a one-year period which ended May 1, 2020. Washington Commission Tax Deferral Filing The TCJA was signed into law in December 2017. As a result of this change, PSE re-measured its deferred tax balances under the new corporate tax rate. PSE filed an accounting petition on December 29, 2017, requesting deferred accounting treatment for the impacts of tax reform. The requested deferral accounting treatment resulted in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes for GAAP purposes. Additionally, on March 30, 2018, PSE filed for a rate change for electric and natural gas customers associated with TCJA to reflect the decrease in the federal corporate income tax rate from 35.0% to 21.0%. The overall impact of the rate change, based on the annual period from May 2018 through April 2019, is a revenue decrease of $72.9 million, or 3.4% for electric and $23.6 million, or 2.7% for natural gas and became effective May 1, 2018, by operation of law. The March 30, 2018, rate change filing did not address excess deferred taxes or the deferred balance associated with the over-collection of income tax expense of $34.6 million for the period January 1 through April 30, 2018, (the time period that encompasses the effective date of the TCJA through May 1, 2018, the effective date of the rate change). The $34.6 million tax over-collection decreased PSE's revenue and increased the regulatory liability for a refund to customers. As a result of the Washington Commission's final order in the ERF, the excess deferred taxes associated with non-plant-related book/tax differences and the treatment of the excess deferred taxes associated with plant related book/tax differences from January 1, 2018, through February 28, 2019, was addressed in PSE’s GRC, which was filed on June 20, 2019. The Washington Commission also required in the ERF order that PSE pass back the deferred balance associated with the tax over-collection for the period from January 1, 2018, through April 30, 2018, as discussed above, over a one-year period which began May 1, 2019. Per PSE’s Schedule 141Y tariff, following the May 2019 through April 2020 refund period, if the residual balance of credit owed to customers will be greater than $0.1 million, PSE would submit a filing no later than July 31, 2020 with a proposal of passing back the residual balance effective September 1, 2020 through August 31, 2021. As this balance was greater than $0.1 million, PSE filed tariff revisions on July 20, 2020 and the Washington Commission approved the filing on August 27, 2020. Finally, the GRC final order determined that PSE is required to pass back 2019 and 2020 protected excess deferred tax reversals totaling $70.8 million over the 12 months following the rate effective period. As noted above, PSE filed a motion for clarification with the Washington Commission seeking clarification on several items including administration of the required pass back of excess deferred tax reversals. On July 31, 2020, PSE received an order granting PSE’s motion for clarification which adjusted certain items within the final order, including treatment of protected excess deferred taxes. PSE reviewed the original Washington Commission order including the ramifications of certain tax issues and will file a PLR with the IRS on the matter. PSE filed a compliance filing on September 23, 2020. The natural gas tariffs became effective October 1, 2020 and electric tariffs on October 15, 2020. Decoupling Filings While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms assist in mitigating the impact of weather on operating revenue and net income. Since 2013, the Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs from most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues are recovered on a per customer basis regardless of actual consumption levels. PSE's energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. Following each calendar year, PSE will recover from, or refund to, customers the difference between allowed decoupling revenue and the corresponding actual revenue during the following May to April time period. On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with several changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues continue to be recovered on a per customer basis and electric fixed production energy costs are now decoupled and recovered on the basis of a fixed monthly amount. The allowed decoupling revenue for electric and natural gas customers will no longer increase annually each January 1 as occurred prior to December 19, 2017. Approved revenue per customer costs can only be changed in a GRC or ERF. Approved electric fixed production energy costs can also be changed in a power cost only rate case. Other changes to the decoupling methodology approved by the Washington Commission include regrouping of electric and natural gas non-residential customers and the exclusion of certain electric schedules from the decoupling mechanism going forward. The rate test, which limits the amount of revenues PSE can collect in its annual filings, increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The decoupling mechanism will be reviewed again in PSE’s first rate case filed in or after 2021, or in a separate proceeding, if appropriate. PSE’s decoupling mechanism over- and under- collections will still be collectible or refundable after this effective date even if the decoupling mechanism is not extended. On February 21, 2019, the Washington Commission approved the multi-party settlement agreement which was filed within PSE’s ERF filing. As part of this settlement agreement, electric and natural gas allowed delivery revenue per customer was updated to reflect changes in the approved revenue requirement. For electric, there were no changes to the annual allowed fixed power cost revenue. The changes took effect on March 1, 2019. On July 8, 2020, the Washington Commission issued the final order via 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 September 30, 2020, PSE performed an analysis to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980. If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and a corresponding 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 $4.1 million of electric deferred revenue will not be collected within 24 months of the annual period; therefore a reserve adjustment was booked to 2020 electric decoupling revenue. Natural gas deferred revenue will be collected within 24 months of the annual period; therefore, no reserve adjustment was booked to 2020 natural gas decoupling revenue. 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 nine months ended September 30, 2020, in its PCA mechanism, PSE under recovered its allowable costs by $51.5 million of which $21.9 million was apportioned to customers and $1.6 million of interest was accrued on the deferred customer balance. This compares to an under recovery of allowable costs of $48.9 million for the nine months ended September 30, 2019, of which $19.5 million was apportioned to customers and accrued $0.3 million interest on the total deferred customer balance. Purchased Gas Adjustment Mechanism On April 25, 2019, the Washington Commission approved PSE’s request for an out-of-cycle change to PGA rates with the rate change taking effect May 1, 2019. The out-of-cycle PGA filing was needed to begin amortizing a large PGA commodity deferral balance that had grown due to higher than projected commodity costs during the 2018/19 winter. These higher than projected commodity costs were primarily due to an October 9, 2018, rupture and subsequent explosion on Westcoast Pipeline which is one of the major pipelines feeding PSE’s distribution system. The pipeline was repaired in October 2018, however supply capacity on the pipeline was limited over the 2018/19 winter leading to higher prices. February weather was also much colder than normal which also increased the demand for natural gas. The out-of-cycle PGA rates were effective from May 1, 2019 through April 30, 2020 and on May 1, 2020 the rates were set to zero. At the end of the recovery period, an unamortized balance of $4.9 million remained which PSE requested to be amortized in its upcoming annual PGA filing for rates effective November 1, 2020. On October 24, 2019, the Washington Commission approved PSE’s request for November 2019 PGA rates, with the rate change taking effect on November 1, 2019. As part of that filing, PSE requested PGA rates increase annual revenue by $17.8 million, while the new tracker rates increased by annual revenue of $100.6 million; this was in addition to continuing the collection on the remaining balance of $54.0 million from the out-of-cycle PGA. The tracker rates include deferral balances for the three separate amounts: (i) $114.4 million of under collected commodity balances deferred in February and March; (ii) a $10.8 million balance of over-collected commodity costs for the 2018 PGA, and (iii) a $4.1 million remaining balance from the $54.7 million credit to customers, caused by the 2017 over-collection, established in the 2018 tracker. The high commodity deferral balances for winter months through March 2019 were the result of three noteworthy events last winter experienced by PSE: the Enbridge pipeline rupture, unusually low temperatures in February and March, and a compressor failure in February at the Jackson Prairie storage facility. Additionally, to reduce customer impact, as part of the approved PGA filing, PSE was approved to collect $114.4 million commodity deferrals and related interest over a two year period, instead of the historic one year period, from November 2019 through October 2021. On July 8, 2020, the Washington Commission issued the final order in Dockets UE-190529 and UG-190530, which instructed PSE to extend the collection of amortization balances for the portion of PGA amortization balances originally filed through the annual November 1, 2019 PGA filing under the Supplemental Schedule 106B. The extension requires PSE to move amortization balances for PGA Schedule 106B as of August 31, 2020 to be collected from customers for a three-year period, instead of the originally approved two-year period. The following table presents the PGA mechanism balances and activity at September 30, 2020 and December 31, 2019: (Dollars in Thousands) At September 30, At December 31 PGA receivable balance and activity 2020 2019 PGA receivable beginning balance $ 132,766 $ 9,922 Actual natural gas costs 214,772 406,162 Allowed PGA recovery (248,809) (289,876) Interest 3,177 6,558 PGA receivable ending balance $ 101,906 $ 132,766 Get to Zero Depreciation Deferral On April 10, 2019, PSE filed an accounting petition with the Washington Commission, requesting authorization to defer depreciation expense associated with Get To Zero (GTZ) projects that were placed in service after June 30, 2018. The GTZ project consists of a number of short-lived technology upgrades. The depreciation expense associated with the GTZ projects with lives of 10 years or less that were placed in service after June 30, 2018, were deferred beginning May 1 per the petition request. As of September 30, 2020, and December 31, 2019, PSE had deferred GTZ depreciation expense balances of $52.0 million and $21.7 million, respectively. In addition to the depreciation expense deferral, PSE requested to defer carrying charges on the GTZ deferral, to be calculated utilizing the Company’s currently authorized after tax rate of return, or 6.89% per the 2018 ERF. As of September 30, 2020, and December 31, 2019, PSE has a deferred carrying charge balance of $1.2 million and $0.5 million, respectively. The GTZ accounting petition was consolidated with PSE’s 2019 GRC and on July 8, 2020, the Washington Commission issued its order in PSE’s 2019 GRC. The ruling authorized PSE to amortize deferred GTZ expenses as proposed in the original general rate case 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 fully compatible with other low income programs. 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. The program was set to automatically end when all of the funds are disbursed or September 30, 2020, whichever occurred first. 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. Storm Damage Deferral Accounting

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	(8) Commitments and Contingencies Colstrip PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in each of Colstrip Units 3 and 4. In March 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. In July 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court in September 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and Talen Energy Corporation (Talen), agreed to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana no later than July 1, 2022. Depreciation rates were updated in the GRC effective December 19, 2017, where PSE's depreciation increased for Colstrip Units 1 and 2 to recover plant costs to the expected shutdown date. Additionally, PSE has accelerated the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027. The GRC also repurposed PTCs and hydro-related treasury grants to recover unrecovered plant costs and to fund and recover decommissioning and remediation costs for Colstrip Units 1 through 4. The final order in the 2019 GRC further shortened the depreciable life for Colstrip 3 and 4 to December 31, 2025 to align with the requirements of the Clean Energy Transformation Act. Consistent with a June 2019 announcement, Talen permanently shut down Units 1 and 2 at the end of 2019 due to operational losses associated with the Units. Colstrip Units 1 and 2 were retired effective December 31, 2019. The Washington Clean Energy Transition Act requires the Washington Commission to provide recovery of the investment, decommissioning, and remediation costs associated with the facilities that are not recovered through the repurposed PTC's and hydro-related treasury grants. The full scope of decommissioning activities and costs may vary from the estimates that are available at this time. On December 10, 2019, PSE announced its intention to sell its interest in Colstrip Unit 4 to NorthWestern Energy for $1. Under the agreement with NorthWestern Energy, PSE would retain its obligation to fund 25% of the environmental remediation and decommissioning costs associated with Unit 4 during PSE's operation. The agreement was subject to approval by the Washington Commission and the Montana Public Service Commission. Additionally, PSE entered into a power purchase agreement with NorthWestern Energy for 90 MW through 2025 to facilitate the transition, and sell a portion of its dedicated Colstrip transmission system, conditioned upon the same regulatory approval of the overall transaction. Other Colstrip owners and other external parties have intervened in the pending regulatory review of this transaction, and one Colstrip owner, Talen, has exercised its contractual right to purchase its pro rata share of the interest to be sold by PSE. On August 14, 2020, an amendment to the agreement was executed selling a portion of PSE’s interest in Colstrip Unit 4 to Talen, in addition to NorthWestern Energy. Following this, PSE submitted supplementary testimony related to this amendment in the proceeding with the Washington Commission. Both the Washington Commission and the Montana Public Service Commission issued new procedural calendars which were previously on hold until these supplemental filings were completed. The original purchase agreement was written such that the purchase must close by December 31, 2020. On October 29, 2020, PSE, NorthWestern Energy, and Talen mutually agreed to terminate the proposed sales agreement and relieve all claims against one another arising out of or relating to the sale agreement after evaluating the likelihood of the regulatory approval process in both Washington and Montana. The termination of the proposed sale resulted in the withdrawal of PSE's filing with the Washington Commission. Colstrip Unit 4 is classified as Electric Utility Plant on the balance sheet, see Note 6, "Utility Plant," to the consolidated financial statements in the Company's most recent Annual Report on Form 10-K for the year ended December 31, 2019. Other Commitments and Contingencies In addition to the contractual obligations and consolidated commercial commitments disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2019, during the nine months ended September 30, 2020, the Company entered into new Electric Portfolio and Electric Wholesale Market Transaction contracts with estimated payment obligations totaling $935.3 million through 2042. For further information, see Note 16, "Commitments and Contingencies" to the consolidated financial statements included in Item 8 of the Company's Form 10-K for the period ended December 31, 2019. COVID-19 The outbreak of the novel coronavirus (COVID-19) has become a global pandemic. The Company is monitoring the impact of the pandemic and taking steps to mitigate known risks. The full impact on the Company's business from the pandemic, including governmental and regulatory response actions, is unknown at this time and difficult to predict. The Company provides a critical and essential service to its customers and the health and safety of its employees and customers is its first priority. The Company is continuously monitoring its supply chain and is working closely with essential vendors to understand the impact of COVID-19 to its business and does not currently expect service disruptions. Government mandated stay at home orders and private work from home mandates due to COVID-19 have affected electric and gas loads for residential, commercial, and industrial customers. During the quarter ended September 30, 2020, the Company delivered lower electric and natural gas loads, 2.7% and 7.7%, respectively, when comparing weather-adjusted actual to forecast. Decreases in commercial and industrial loads were partially offset by increases in residential loads. Electric retail revenue reductions were partially offset by reduced electric supply costs and the effects of decoupling. The impact on natural gas revenue due to load was offset by gas supply cost and decoupling. The Company anticipates that electric and gas loads will continue to be impacted for the remainder of 2020, due to continued work place lock downs, work at home mandates, other government mandated quarantines, economic recession, and resurgence of the COVID-19 virus. At the date of this report, the Company is effectively managing operations during the pandemic in order to continue to provide critical service to its customers. The Company has flexibility with capital investments and other measures to maintain sufficient liquidity over the next twelve months. The situation remains fluid and future impacts to the Company that are presently unknown or unanticipated may occur. Furthermore, the severity of impact to the Company could increase the longer the global pandemic persists. On September 3, 2020, the Company filed an accounting petition with the Washington Commission, requesting authorization to defer the costs and foregone revenue net of offsets associated with the COVID-19 public health emergency. PSE anticipates receiving a ruling on the matter sometime in the fourth quarter of 2020.

Leases (Notes)

Leases (Notes)	9 Months Ended
	Sep. 30, 2020
Leases [Abstract]
Leases	Leases PSE has operating leases for buildings for corporate offices and operations, real estate for operating facilities and the Tacoma LNG facility, land for our wind farms, and vehicles for PSE’s fleet. The finance leases are for office printers. The leases have remaining lease terms of less than a year to 50 years. PSE's ROU assets and lease liabilities include options to extend leases when it is reasonably certain that PSE will exercise that option. During the fourth quarter of 2019, PSE became reasonably certain to exercise an option to extend its lease at the Port of Tacoma for an additional 25 years as a result of the approval of the Notice of Construction permit for the Tacoma LNG facility. This remeasurement resulted in an increase of the Operating lease right-of-use asset and Operating lease liabilities of $14.7 million. The components of lease cost were as follows: Puget Energy and Three Months Ended Nine Months Ended (Dollars in Thousands) 2020 2019 2020 2019 Finance lease cost: Amortization of right-of-use asset $ 151 $ 128 $ 455 $ 410 Interest on lease liabilities 8 10 27 29 Total finance lease cost $ 159 $ 138 $ 482 $ 439 Operating lease cost 1 $ 4,902 $ 5,311 $ 16,051 $ 15,318 _______________ 1 Includes $0.3 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for each of the three months ended September 30, 2020 and 2019, respectively and $0.8 million for each of the nine months ended September 30, 2020 and 2019, respectively. Supplemental cash flow information related to leases was as follows: Puget Energy and Nine Months Ended (Dollars in Thousands) 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flow for operating leases $ 11,152 $ 10,437 Investing cash flow for operating leases 1 4,899 4,881 Operating cash flow for finance leases 27 29 Financing cash flow for finance leases 455 410 Non-cash disclosure upon commencement of new lease Right-of-use assets obtained in exchange for new operating lease liabilities 4,996 2,032 _______________ 1 Includes $0.8 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for each of the nine months ended September 30, 2020 and 2019, respectively. Supplemental balance sheet information related to leases was as follows: Puget Sound Energy (Dollars in Thousands) September 30, December 31, Operating Leases 2020 2019 Operating lease right-of-use asset $ 175,091 $ 183,048 Operating leases liabilities current 19,400 15,862 Operating lease liabilities long-term 163,453 174,327 Total Operating lease liabilities: $ 182,853 $ 190,189 Finance Leases Common Plant $ 1,033 $ 1,488 Other current liabilities 546 669 Other deferred credits 420 811 Total finance lease liabilities $ 966 $ 1,480 Weighted Average Remaining Lease Term Operating leases 19.00 Years 19.24 Years Finance leases 2.10 Years 2.76 Years Weighted Average Discount Rate Operating leases 3.59 % 3.59 % Finance leases 2.98 % 2.98 % The following tables summarize the Company’s estimated future minimum lease payments as of September 30, 2020, and December 31, 2019, respectively: Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At September 30, Operating Leases Finance Leases 2020 (remaining three months) $ 5,329 $ 160 2021 23,171 508 2022 22,522 279 2023 22,082 98 2024 21,349 — Thereafter 162,578 — Total lease payments $ 257,031 $ 1,045 Less imputed interest (74,178) (79) Total $ 182,853 $ 966 Maturities of lease liabilities Future Minimum Lease (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2020 $ 22,500 $ 643 2021 22,527 508 2022 21,856 279 2023 21,415 98 2024 20,690 — Thereafter 160,410 — Total lease payments $ 269,398 $ 1,528 Less imputed interest (79,209) (48) Total net present value $ 190,189 $ 1,480
Leases	Leases PSE has operating leases for buildings for corporate offices and operations, real estate for operating facilities and the Tacoma LNG facility, land for our wind farms, and vehicles for PSE’s fleet. The finance leases are for office printers. The leases have remaining lease terms of less than a year to 50 years. PSE's ROU assets and lease liabilities include options to extend leases when it is reasonably certain that PSE will exercise that option. During the fourth quarter of 2019, PSE became reasonably certain to exercise an option to extend its lease at the Port of Tacoma for an additional 25 years as a result of the approval of the Notice of Construction permit for the Tacoma LNG facility. This remeasurement resulted in an increase of the Operating lease right-of-use asset and Operating lease liabilities of $14.7 million. The components of lease cost were as follows: Puget Energy and Three Months Ended Nine Months Ended (Dollars in Thousands) 2020 2019 2020 2019 Finance lease cost: Amortization of right-of-use asset $ 151 $ 128 $ 455 $ 410 Interest on lease liabilities 8 10 27 29 Total finance lease cost $ 159 $ 138 $ 482 $ 439 Operating lease cost 1 $ 4,902 $ 5,311 $ 16,051 $ 15,318 _______________ 1 Includes $0.3 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for each of the three months ended September 30, 2020 and 2019, respectively and $0.8 million for each of the nine months ended September 30, 2020 and 2019, respectively. Supplemental cash flow information related to leases was as follows: Puget Energy and Nine Months Ended (Dollars in Thousands) 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flow for operating leases $ 11,152 $ 10,437 Investing cash flow for operating leases 1 4,899 4,881 Operating cash flow for finance leases 27 29 Financing cash flow for finance leases 455 410 Non-cash disclosure upon commencement of new lease Right-of-use assets obtained in exchange for new operating lease liabilities 4,996 2,032 _______________ 1 Includes $0.8 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for each of the nine months ended September 30, 2020 and 2019, respectively. Supplemental balance sheet information related to leases was as follows: Puget Sound Energy (Dollars in Thousands) September 30, December 31, Operating Leases 2020 2019 Operating lease right-of-use asset $ 175,091 $ 183,048 Operating leases liabilities current 19,400 15,862 Operating lease liabilities long-term 163,453 174,327 Total Operating lease liabilities: $ 182,853 $ 190,189 Finance Leases Common Plant $ 1,033 $ 1,488 Other current liabilities 546 669 Other deferred credits 420 811 Total finance lease liabilities $ 966 $ 1,480 Weighted Average Remaining Lease Term Operating leases 19.00 Years 19.24 Years Finance leases 2.10 Years 2.76 Years Weighted Average Discount Rate Operating leases 3.59 % 3.59 % Finance leases 2.98 % 2.98 % The following tables summarize the Company’s estimated future minimum lease payments as of September 30, 2020, and December 31, 2019, respectively: Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At September 30, Operating Leases Finance Leases 2020 (remaining three months) $ 5,329 $ 160 2021 23,171 508 2022 22,522 279 2023 22,082 98 2024 21,349 — Thereafter 162,578 — Total lease payments $ 257,031 $ 1,045 Less imputed interest (74,178) (79) Total $ 182,853 $ 966 Maturities of lease liabilities Future Minimum Lease (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2020 $ 22,500 $ 643 2021 22,527 508 2022 21,856 279 2023 21,415 98 2024 20,690 — Thereafter 160,410 — Total lease payments $ 269,398 $ 1,528 Less imputed interest (79,209) (48) Total net present value $ 190,189 $ 1,480

Other

Other	9 Months Ended
	Sep. 30, 2020
Other [Abstract]
Long-term Debt	Long-Term Debt On May 19, 2020, Puget Energy issued $650.0 million of senior secured notes (Notes) at an interest rate of 4.1%. The Notes pay interest semi-annually and are due to mature on June 15, 2030. The 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 September 30, 2020. At September 30, 2020, Puget Energy maintained an $800.0 million credit facility, of which $23.9 million was drawn and outstanding under the facility. For further information, see Note 7, "Long-Term Debt" and Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's most recent Annual Report on Form 10K for the year ended December 31, 2019.
Short-term Debt	Short-Term Debt During the nine months ended September 30, 2020, commercial paper markets were significantly impacted for a period of time due to COVID-19, during which time the Company drew short term funding from its credit facility. Commercial paper markets improved as of September 30, 2020, at which time no amount was drawn under PSE's credit facility and $221.0 million was outstanding under the commercial paper program at PSE. For further information, see Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's most recent Annual Report on Form 10K for the year ended December 31, 2019.

Accounting Policies (Tables)

Accounting Policies (Tables)	3 Months Ended
	Sep. 30, 2020
Accounting Policies [Abstract]
Accounts Receivable, Allowance for Credit Loss	The following table presents the activity in the allowance for credit losses for accounts receivable for the nine months ended September 30, 2020: Puget Energy and (Dollars in Thousands) September 30, Allowance for credit losses: Beginning balance $ 8,294 Provision for credit loss expense 14,660 Receivables charged-off (9,065) Total ending allowance balance $ 13,889

Revenue (Tables)

Revenue (Tables)	9 Months Ended
	Sep. 30, 2020
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	The following table presents disaggregated revenue from contracts with customers, and other revenue by major source: Puget Energy and (Dollars in Thousands) Three Months Ended September 30, Nine Months Ended September 30, Revenue from contracts with customers: 2020 2019 2020 2019 Electric retail $ 458,573 $ 450,109 $ 1,499,378 $ 1,550,517 Natural gas retail 103,486 101,395 637,239 569,177 Other 46,111 72,691 125,227 245,285 Total revenue from contracts with customers 608,170 624,195 2,261,844 2,364,979 Alternative revenue programs 2,189 874 23,089 (20,006) Other non-customer revenue 10,067 1,938 33,302 67,803 Total operating revenue $ 620,426 $ 627,007 $ 2,318,235 $ 2,412,776

Accounting for Derivative Ins_2

Accounting for Derivative Instruments and Hedging Activities (Tables)	9 Months Ended
	Sep. 30, 2020
Derivative [Line Items]
Offsetting Assets and Liabilities	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 At September 30, 2020 Gross Amount Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 94,105 $ — $ 94,105 $ (37,723) $ — $ 56,382 Liabilities: Energy derivative contracts $ 53,535 $ — $ 53,535 $ (37,723) $ (1,614) $ 14,198 Puget Energy and At December 31, 2019 Gross Amount Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position (Dollars in Thousands) Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 31,308 $ — $ 31,308 $ (14,922) $ — $ 16,386 Liabilities: Energy derivative contracts $ 26,121 $ — $ 26,121 $ (14,922) $ 2,000 $ 13,199 _______________ 1 All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off.
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance	The following table presents the effect and classification of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income: Puget Energy and Three Months Ended Nine Months Ended (Dollars in Thousands) Classification 2020 2019 2020 2019 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net $ 29,940 $ 8,143 $ 24,950 $ 5,914 Realized Electric generation fuel 358 (7,514) 911 4,481 Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 10,002 (22,859) (21,386) (35,775) Realized Purchased electricity 3,579 (335) (8,584) 40,918 Total gain (loss) recognized in income on derivatives $ 43,879 $ (22,565) $ (4,109) $ 15,538
Schedule of Credit Risk Related Contingent Features	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 (Dollars in Thousands) At September 30, 2020 At December 31, 2019 Fair Value 1 Posted Contingent Fair Value 1 Posted Contingent Contingent Feature Liability Collateral Collateral Liability Collateral Collateral Credit rating 2 $ 23,792 $ — $ 23,792 $ 6,110 $ — $ 6,110 Requested credit for adequate assurance 5,116 — — 5,253 — — Forward value of contract 3 1,614 15,325 N/A — 14,827 N/A Total $ 30,522 $ 15,325 $ 23,792 $ 11,363 $ 14,827 $ 6,110 _______________ 1 Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable. 2 Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral. 3 . Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.
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 September 30, 2020 December 31, 2019 (Dollars in Thousands) Volumes Assets 1 Liabilities 2 Volumes Assets 1 Liabilities 2 Electric portfolio derivatives * $ 48,876 $ 42,884 * $ 19,933 $ 17,504 Natural gas derivatives (MMBtus) 3 284.9 million 45,229 10,651 315.5 million 11,375 8,617 Total derivative contracts $ 94,105 $ 53,535 $ 31,308 $ 26,121 Current $ 73,677 $ 25,146 $ 23,626 $ 13,428 Long-term 20,428 28,389 7,682 12,693 Total derivative contracts $ 94,105 $ 53,535 $ 31,308 $ 26,121 _______________ 1 Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments. 2 Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments. 3 All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the purchased gas adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 212.3 million One Million British Thermal Units (MMBtu) and purchased electricity of 7.8 million Megawatt Hours (MWhs) at September 30, 2020, and 229.3 million MMBtus and 10.4 million MWhs at December 31, 2019.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2020
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis		The following table presents 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: Puget Energy and Fair Value Fair Value (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 47,959 $ 917 $ 48,876 $ 19,282 $ 651 $ 19,933 Natural gas derivative instruments 44,966 263 45,229 9,852 1,523 11,375 Total assets $ 92,925 $ 1,180 $ 94,105 $ 29,134 $ 2,174 $ 31,308 Liabilities: Electric derivative instruments $ 19,720 $ 23,164 $ 42,884 $ 13,474 $ 4,030 $ 17,504 Natural gas derivative instruments 9,912 739 10,651 8,376 241 8,617 Total liabilities $ 29,632 $ 23,903 $ 53,535 $ 21,850 $ 4,271 $ 26,121
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation	The following tables present the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy and Three Months Ended (Dollars in Thousands) 2020 2019 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ (28,609) $ 342 $ (28,267) $ (2,446) $ 2,398 $ (48) Changes during period: Realized and unrealized energy derivatives: Included in earnings 1 5,516 — 5,516 (4,611) — (4,611) Included in regulatory assets / liabilities — (471) (471) — 206 206 Settlements 846 (347) 499 2,529 (1,167) 1,362 Transferred into Level 3 — — — — — — Transferred out of Level 3 — — — — — — Balance at end of period $ (22,247) $ (476) $ (22,723) $ (4,528) $ 1,437 $ (3,091)	Puget Energy and Nine Months Ended (Dollars in Thousands) 2020 2019 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ (3,378) $ 1,282 $ (2,096) $ 1,362 $ 1,673 $ 3,035 Changes during period: Realized and unrealized energy derivatives: Included in earnings 2 (21,321) — (21,321) 1,524 — 1,524 Included in regulatory assets / liabilities — (187) (187) — 2,485 2,485 Settlements 2,452 (1,571) 881 (10,380) (3,885) (14,265) Transferred into Level 3 — — — 4,390 (400) 3,990 Transferred out of Level 3 — — — (1,424) 1,564 140 Balance at end of period $ (22,247) $ (476) $ (22,723) $ (4,528) $ 1,437 $ (3,091) _______________ 1. Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $4.8 million and $(4.5) million for three months ended September 30, 2020 and 2019 , respectively. 2. Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(19.0) million and $(4.4) million for nine months ended September 30, 2020 and 2019
Fair Value Inputs, Assets and Liabilities, Quantitative Information		The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of September 30, 2020: Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 917 $ 23,164 Discounted cash flow Power prices (per MWh) $ 23.80 $ 46.25 $ 32.85 Natural gas $ 263 $ 739 Discounted cash flow Natural gas prices (per MMBtu) $ 1.56 $ 3.61 $ 2.50 _______________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2019: Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 651 $ 4,030 Discounted cash flow Power prices (per MWh) $ 9.00 $ 43.85 $ 33.99 Natural gas $ 1,523 $ 241 Discounted cash flow Natural gas prices (per MMBtu) $ 1.25 $ 3.18 $ 2.47 ___________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.
Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets		The following table presents the significant unobservable inputs used in estimating the impaired long-term power purchase contracts' fair value: Puget Energy Valuation Date Unobservable Input Low High Average March 31, 2020 Power prices (per MWh) $ 10.23 $ 29.05 $ 21.27 Power contract costs per quarter (in thousands) $ 6,308 $ 7,085 $ 6,468 December 31, 2019 Power prices (per MWh) $ 11.75 $ 31.44 $ 22.53 Power contract costs per quarter (in thousands) $ 6,237 $ 7,087 $ 6,421
Details of Impairment of Long-Lived Assets Held and Used by Asset		The following table presents the impairment recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability: 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

Retirement Benefits (Tables)

Retirement Benefits (Tables)	9 Months Ended
	Sep. 30, 2020
Retirement Benefits [Abstract]
Schedule of Net Benefit Costs	The following tables summarize the Company’s net periodic benefit cost for the three and nine months ended September 30, 2020 and 2019: Puget Energy Qualified SERP Other Three Months Ended September 30, (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Components of net periodic benefit cost: Service cost $ 6,084 $ 6,418 $ 176 $ 256 $ 47 $ 13 Interest cost 6,295 7,252 362 578 92 84 Expected return on plan assets (12,476) (12,439) — — (97) (100) Amortization of prior service cost (393) (495) 87 83 — — Amortization of net loss (gain) 2,040 362 512 341 (20) (156) Net periodic benefit cost $ 1,550 $ 1,098 $ 1,137 $ 1,258 $ 22 $ (159) Puget Energy Qualified SERP Other Nine Months Ended September 30, (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Components of net periodic benefit cost: Service cost $ 18,253 $ 16,992 $ 580 $ 768 $ 142 $ 46 Interest cost 18,885 21,685 1,102 1,735 276 308 Expected return on plan assets (37,427) (37,686) — — (292) (295) Amortization of prior service cost (1,180) (1,485) 262 249 — — Amortization of net loss (gain) 6,120 863 1,610 1,024 (61) (281) Net periodic benefit cost $ 4,651 $ 369 $ 3,554 $ 3,776 $ 65 $ (222) Puget Sound Energy Qualified SERP Other Three Months Ended September 30, (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Components of net periodic benefit cost: Service cost $ 6,084 $ 6,418 $ 176 $ 256 $ 47 $ 13 Interest cost 6,295 7,252 362 578 92 84 Expected return on plan assets (12,478) (12,443) — — (97) (100) Amortization of prior service cost (393) (393) 87 83 — — Amortization of net loss (gain) 4,761 3,328 575 433 (34) (202) Net periodic benefit cost $ 4,269 $ 4,162 $ 1,200 $ 1,350 $ 8 $ (205) Puget Sound Energy Qualified SERP Other Nine Months Ended September 30, (Dollars in Thousands) 2020 2019 2020 2019 2020 2019 Components of net periodic benefit cost: Service cost $ 18,253 $ 16,992 $ 580 $ 768 $ 142 $ 46 Interest cost 18,885 21,685 1,102 1,735 276 308 Expected return on plan assets (37,433) (37,700) — — (292) (295) Amortization of prior service cost (1,180) (1,180) 262 250 — — Amortization of net loss (gain) 14,283 9,657 1,810 1,300 (103) (421) Net periodic benefit cost $ 12,808 $ 9,454 $ 3,754 $ 4,053 $ 23 $ (362)
Schedule of Changes in Projected Benefit Obligations	The following table summarizes the Company’s change in benefit obligation for the periods ended September 30, 2020 and December 31, 2019: Puget Energy and Qualified SERP Other Nine Months Ended Year Ended Nine Months Ended Year Ended Nine Months Ended Year Ended (Dollars in Thousands) September 30, December 31, September 30, December 31, September 30, December 31, Change in benefit obligation: Benefit obligation at beginning of period $ 774,305 $ 677,643 $ 63,000 $ 55,708 $ 11,627 $ 10,636 Amendments — — — — — 9,049 Service cost 18,253 22,656 580 1,023 142 61 Interest cost 18,885 28,913 1,102 2,314 276 410 Curtailment Loss / (Gain) — — — — — (7,486) Actuarial loss (gain) 1,134 84,272 (478) 6,756 34 (287) Benefits paid (35,984) (36,740) (18,140) (2,801) (740) (982) Medicare part D subsidy received — — — — 187 226 Administrative Expense — (2,439) — — — — Benefit obligation at end of period $ 776,593 $ 774,305 $ 46,064 $ 63,000 $ 11,526 $ 11,627

Regulated Operations (Tables)

Regulated Operations (Tables)	9 Months Ended
	Sep. 30, 2020
Regulation and Rates [Line Items]
Schedule of Graduated Scale of Rate Adjustment Mechanism	Effective January 1, 2017, the following graduated scale is used in the PCA mechanism: Company’s Share Customers' Share Annual Power Cost Variability Over Under Over Under Over or Under Collected by up to $17 million 100 % 100 % — % — % Over or Under Collected by between $17 million - $40 million 35 50 65 50 Over or Under Collected beyond $40 + million 10 10 90 90
Subsidiaries [Member] | Natural Gas [Member] | Purchased Gas Adjustment [Member]
Regulation and Rates [Line Items]
Schedule of PGA Receivable Payable	The following table presents the PGA mechanism balances and activity at September 30, 2020 and December 31, 2019: (Dollars in Thousands) At September 30, At December 31 PGA receivable balance and activity 2020 2019 PGA receivable beginning balance $ 132,766 $ 9,922 Actual natural gas costs 214,772 406,162 Allowed PGA recovery (248,809) (289,876) Interest 3,177 6,558 PGA receivable ending balance $ 101,906 $ 132,766

Leases (Tables)

Leases (Tables)	3 Months Ended	9 Months Ended
	Mar. 31, 2020	Sep. 30, 2020
Leases [Abstract]
Schedule of lease cost		The components of lease cost were as follows: Puget Energy and Three Months Ended Nine Months Ended (Dollars in Thousands) 2020 2019 2020 2019 Finance lease cost: Amortization of right-of-use asset $ 151 $ 128 $ 455 $ 410 Interest on lease liabilities 8 10 27 29 Total finance lease cost $ 159 $ 138 $ 482 $ 439 Operating lease cost 1 $ 4,902 $ 5,311 $ 16,051 $ 15,318 _______________ 1 Includes $0.3 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for each of the three months ended September 30, 2020 and 2019, respectively and $0.8 million for each of the nine months ended September 30, 2020 and 2019, respectively.
Schedule of lease assets and liabilities		Supplemental balance sheet information related to leases was as follows: Puget Sound Energy (Dollars in Thousands) September 30, December 31, Operating Leases 2020 2019 Operating lease right-of-use asset $ 175,091 $ 183,048 Operating leases liabilities current 19,400 15,862 Operating lease liabilities long-term 163,453 174,327 Total Operating lease liabilities: $ 182,853 $ 190,189 Finance Leases Common Plant $ 1,033 $ 1,488 Other current liabilities 546 669 Other deferred credits 420 811 Total finance lease liabilities $ 966 $ 1,480 Weighted Average Remaining Lease Term Operating leases 19.00 Years 19.24 Years Finance leases 2.10 Years 2.76 Years Weighted Average Discount Rate Operating leases 3.59 % 3.59 % Finance leases 2.98 % 2.98 %
Schedule of maturity of operating lease liability	Maturities of lease liabilities Future Minimum Lease (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2020 $ 22,500 $ 643 2021 22,527 508 2022 21,856 279 2023 21,415 98 2024 20,690 — Thereafter 160,410 — Total lease payments $ 269,398 $ 1,528 Less imputed interest (79,209) (48) Total net present value $ 190,189 $ 1,480
Schedule of maturity of finance lease liability	Maturities of lease liabilities Future Minimum Lease (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2020 $ 22,500 $ 643 2021 22,527 508 2022 21,856 279 2023 21,415 98 2024 20,690 — Thereafter 160,410 — Total lease payments $ 269,398 $ 1,528 Less imputed interest (79,209) (48) Total net present value $ 190,189 $ 1,480
Leases, Cash Flow		Supplemental cash flow information related to leases was as follows: Puget Energy and Nine Months Ended (Dollars in Thousands) 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flow for operating leases $ 11,152 $ 10,437 Investing cash flow for operating leases 1 4,899 4,881 Operating cash flow for finance leases 27 29 Financing cash flow for finance leases 455 410 Non-cash disclosure upon commencement of new lease Right-of-use assets obtained in exchange for new operating lease liabilities 4,996 2,032 _______________ 1 Includes $0.8 million allocated to PLNG at Puget Energy related to the Port of Tacoma lease for each of the nine months ended September 30, 2020 and 2019, respectively.

Summary of Consolidation and _2

Summary of Consolidation and Significant Accounting Policy (Details) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2020USD ($)mi²	Sep. 30, 2020USD ($)mi²	Sep. 30, 2019USD ($)	Dec. 31, 2019USD ($)
Summary of Consolidation Policy
Allowance for Credit Losses, Beginning Balance				$ 8,294
Provision for Credit Loss		$ 14,660
Receivables Charged-Off	$ (9,065)
Allowance for Credit Loss, Ending Balance	$ 13,889	$ 13,889
Subsidiaries [Member]
Summary of Consolidation Policy
Area of Service Territory (in sqmi) | mi²	6,000	6,000
Subsidiaries [Member] | Tacoma LNG [Member]
Summary of Consolidation Policy
Jointly Owned Non-Utility Plant Share	43.00%	43.00%
Construction in Progress, Gross	$ 196,700	$ 196,700		162,800
Puget LNG [Member]
Summary of Consolidation Policy
Jointly Owned Non-Utility Plant Share	57.00%	57.00%
Construction in Progress, Gross	$ 221,200	$ 221,200		$ 199,900
Puget LNG [Member] | Non-Utility Expense And Other [Member]
Summary of Consolidation Policy
Operating Costs and Expenses		$ 500	$ 1,000

Revenue (Details)

Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	$ 7,093	$ 4,859	$ 18,806	$ 22,833
Revenues	620,426	627,007	2,318,235	2,412,776
Revenue from Contract with Customer, Including Assessed Tax	608,170	624,195	2,261,844	2,364,979
Electricity, US Regulated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	458,573	450,109	1,499,378	1,550,517
Natural Gas, US Regulated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	103,486	101,395	637,239	569,177
Other Revenue From Contracts with Customers [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	46,111	72,691	125,227	245,285
Decoupling over-collection [Domain]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	2,189	874	23,089	(20,006)
Other Non-606 Revenue [Member]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	10,067	1,938	33,302	67,803
Subsidiaries [Member]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	7,093	4,859	18,806	22,833
Revenues	$ 620,426	$ 627,007	$ 2,318,235	$ 2,412,776

Accounting for Derivative Ins_3

Accounting for Derivative Instruments and Hedging Activities Narrative (Details) MMBTU in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2020USD ($)MMBTU	Dec. 31, 2019MMBTU
Subsidiaries [Member]
Derivative [Line Items]
Hedging strategy number of years extended	3 years
Natural Gas Portfolio [Member]
Derivative [Line Items]
Posted Collateral	$ 3
Electric Generation Fuel [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	212.3	229.3
External Credit Rating, Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage	98.80%
External Credit Rating, Non Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage	1.20%
Credit Rating [Member]
Derivative [Line Items]
Posted Collateral	$ 12.4
Credit Rating [Member] | Natural Gas Portfolio [Member]
Derivative [Line Items]
Posted Collateral	$ 1

Accounting for Derivative Ins_4

Accounting for Derivative Instruments and Hedging Activities Derivative Assets and Liabilities (Details) $ in Thousands, MMBTU in Millions	Sep. 30, 2020USD ($)MMBTU	Dec. 31, 2019USD ($)MMBTU
Derivative [Line Items]
Current, Assets	$ 73,677	$ 23,626
Long-term, Assets	20,428	7,682
Current, Liabilities	25,146	13,428
Long-term, Liabilities	28,389	12,693
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Current, Assets	73,677	23,626
Long-term, Assets	20,428	7,682
Assets	94,105	31,308
Current, Liabilities	25,146	13,428
Long-term, Liabilities	28,389	12,693
Derivative Liability	$ 53,535	$ 26,121
Not Designated as Hedging Instrument [Member] | Natural Gas Derivatives [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	284.9	315.5
Not Designated as Hedging Instrument [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Assets	$ 48,876	$ 19,933
Derivative Liability	42,884	17,504
Not Designated as Hedging Instrument [Member] | Natural Gas Portfolio [Member]
Derivative [Line Items]
Assets	45,229	11,375
Derivative Liability	$ 10,651	$ 8,617
Not Designated as Hedging Instrument [Member] | Electric Generation Fuel [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	212.3	229.3
Not Designated as Hedging Instrument [Member] | Purchased Electricity [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	7.8	10.4
Designated as Hedging Instrument
Derivative [Line Items]
Derivative Liability		$ 26,121

Accounting for Derivative Ins_5

Accounting for Derivative Instruments and Hedging Activities Net Amount of Derivatives Reported in the Statement of Financial Position (Details) - Commodity Contract [Member] - USD ($) $ in Thousands	Sep. 30, 2020	Dec. 31, 2019
Assets:
Gross Amount Recognized in the Statement of Financial Position	$ 94,105	$ 31,308
Gross Amounts Offset in the Statement of Financial Position	0	0
Assets	94,105	31,308
Commodity Contracts	(37,723)	(14,922)
Cash Collateral Received	0	0
Net Amount	56,382	16,386
Liabilities:
Gross Amount Recognized in the Statement of Financial Position	53,535	26,121
Gross Amounts Offset in the Statement of Financial Position	0	0
Derivative Liability	53,535	26,121
Commodity Contracts	(37,723)	(14,922)
Cash Collateral Posted	(1,614)	2,000
Net Amount	$ 14,198	$ 13,199

Accounting for Derivative Ins_6

Accounting for Derivative Instruments and Hedging Activities Recognized in Statement of Income (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	$ 39,942	$ (14,716)	$ 3,563	$ (29,861)
Not Designated as Hedging Instrument [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	43,879	(22,565)	(4,109)	15,538
Not Designated as Hedging Instrument [Member] | Electric Generation Fuel [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	29,940	8,143	24,950	5,914
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Electric Generation Fuel [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	358	(7,514)	911	4,481
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Purchased Electricity [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	3,579	(335)	(8,584)	40,918
Not Designated as Hedging Instrument [Member] | Electricity, US Regulated [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	$ 10,002	$ (22,859)	$ (21,386)	$ (35,775)

Accounting for Derivative Ins_7

Accounting for Derivative Instruments and Hedging Activities Contractual Contingent Liability (Details) - USD ($) $ in Thousands	Sep. 30, 2020	Dec. 31, 2019
Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	$ 30,522	$ 11,363
Posted Collateral	15,325	14,827
Additional Collateral, Aggregate Fair Value	23,792	6,110
Credit Rating [Member]
Derivative [Line Items]
Posted Collateral	12,400
Credit Rating [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	23,792	6,110
Posted Collateral	0	0
Additional Collateral, Aggregate Fair Value	23,792	6,110
Requested Credit for Adequate Assurance [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	5,116	5,253
Posted Collateral	0	0
Additional Collateral, Aggregate Fair Value	0	0
Forward Value of Contract [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	1,614	0
Posted Collateral	$ 15,325	$ 14,827

Fair Value Measurements Debt at

Fair Value Measurements Debt at at Carrying and Fair Value (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2020	Sep. 30, 2020	Dec. 31, 2019
Liabilities:
Total long-term debt		$ 5,922,798	$ 5,920,325
Rocky Reach
Liabilities:
Finite-Lived Intangible Assets, Net	$ 147,168
Impairment of Intangible Assets (Excluding Goodwill)	52,565
Carrying Value [Member] | Rocky Reach
Liabilities:
Finite-Lived Intangible Assets, Net	$ 94,603
Carrying Value [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments, Fair Value Disclosure		52,400	51,500
Subsidiaries [Member]
Liabilities:
Total long-term debt		4,337,564	4,336,142
Discounted cash flow [Member] | Fair Value [Member]
Liabilities:
Total long-term debt		8,016,459	7,412,416
Discounted cash flow [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount		7,758,559	7,004,316
Long-term debt (variable-rate)		257,900	408,100
Discounted cash flow [Member] | Carrying Value [Member]
Liabilities:
Total long-term debt		5,922,798	5,920,325
Discounted cash flow [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount		5,664,898	5,512,225
Long-term debt (variable-rate)		257,900	408,100
Debt issuance costs		23,100	24,100
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member]
Liabilities:
Total long-term debt		6,127,167	5,571,818
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount		6,127,167	5,571,818
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member]
Liabilities:
Total long-term debt		4,337,564	4,336,142
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount		4,337,564	4,336,142
Debt issuance costs		$ 23,300	$ 24,400

Fair Value Measurements Assets

Fair Value Measurements Assets and Liabilities (Details) - USD ($) $ in Thousands	3 Months Ended				9 Months Ended		12 Months Ended
	Sep. 30, 2020		Sep. 30, 2019		Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	$ (28,267)		$ (48)		$ (2,096)
Balance at beginning of period						$ 3,035	$ 3,035
Included in earnings	5,516	[1]	(4,611)	[1]	(21,321)	1,524
Included in regulatory assets/liabilities	(471)		206		(187)	2,485
Settlements	499		1,362			(14,265)
Settlements					881
Transferred into Level 3						3,990
Transferred into Level 3	0		0		0
Transferred out of Level 3	0		0		0
Transferred out of Level 3						140
Balance at end of period	(22,723)		(3,091)		(22,723)	(3,091)	(2,096)
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value	(6,000)				(6,000)		$ (2,500)
Rocky Reach
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Change in forward prices							0.076%
Electric Portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	(28,609)		(2,446)		(3,378)
Balance at beginning of period						1,362	$ 1,362
Included in earnings	5,516		(4,611)		(21,321)	1,524
Included in regulatory assets/liabilities	0		0		0	0
Settlements	846					(10,380)
Settlements			2,529		2,452
Transferred into Level 3						4,390
Transferred into Level 3	0		0		0
Transferred out of Level 3	0		0		0	(1,424)
Balance at end of period	(22,247)		(4,528)		(22,247)	(4,528)	(3,378)
Gain (loss) on derivatives	4,800		(4,500)		(19,000)	(4,400)
Natural Gas Portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	342		2,398		1,282	1,673	1,673
Included in earnings	0		0		0	0
Included in regulatory assets/liabilities	(471)		206		(187)	2,485
Settlements	(347)		(1,167)		(1,571)	(3,885)
Transferred into Level 3	0		0		0	(400)
Transferred out of Level 3	0				0
Transferred out of Level 3			0			1,564
Balance at end of period	(476)		$ 1,437		(476)	$ 1,437	1,282
Level 2 [Member] | Carrying Value [Member] | Discounted cash flow [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt issuance costs	23,100				23,100		24,100
Level 2 [Member] | Carrying Value [Member] | Discounted cash flow [Member] | Subsidiaries [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt issuance costs	23,300				23,300		24,400
Fair Value, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	94,105				94,105		31,308
Derivative Liability	53,535				53,535		26,121
Fair Value, Recurring [Member] | Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	48,876				48,876		19,933
Derivative Liability	42,884				42,884		17,504
Fair Value, Recurring [Member] | Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	45,229				45,229		11,375
Derivative Liability	10,651				10,651		8,617
Fair Value, Recurring [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	92,925				92,925		29,134
Derivative Liability	29,632				29,632		21,850
Fair Value, Recurring [Member] | Level 2 [Member] | Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	47,959				47,959		19,282
Derivative Liability	19,720				19,720		13,474
Fair Value, Recurring [Member] | Level 2 [Member] | Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	44,966				44,966		9,852
Derivative Liability	9,912				9,912		8,376
Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	1,180				1,180		2,174
Derivative Liability	23,903				23,903		4,271
Fair Value, Recurring [Member] | Level 3 [Member] | Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	917				917		651
Derivative Liability	23,164				23,164		4,030
Fair Value, Recurring [Member] | Level 3 [Member] | Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	263				263		1,523
Derivative Liability	$ 739				$ 739		$ 241
[1]	Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $4.8 million and $(4.5) million for three months ended September 30, 2020 and 2019 , respectively. 2. Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(19.0) million and $(4.4) million for nine months ended September 30, 2020 and 2019 , respectively.

Fair Value Measurements Valuati

Fair Value Measurements Valuation Techniques for Measurement with Unobservable Inputs (Details)	3 Months Ended					9 Months Ended		12 Months Ended
	Sep. 30, 2020USD ($)		Mar. 31, 2020USD ($)$ / MWh	Sep. 30, 2019USD ($)		Sep. 30, 2020USD ($)	Sep. 30, 2019USD ($)	Dec. 31, 2019USD ($)$ / MWh	Jun. 30, 2020USD ($)	Jun. 30, 2019USD ($)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value measurement, sensitivity analysis, hypothetical increase or decrease of market prices, result on fair value	0.10%					0.10%
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value	$ (6,000,000)					$ (6,000,000)		$ (2,500,000)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability Value	(22,723,000)			$ (3,091,000)		(22,723,000)	$ (3,091,000)	(2,096,000)	$ (28,267,000)	$ (48,000)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Earnings	5,516,000	[1]		(4,611,000)	[1]	(21,321,000)	1,524,000
Included in regulatory assets/liabilities	(471,000)			206,000		(187,000)	2,485,000
Settlements	(499,000)			(1,362,000)			14,265,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3	0			0		0
Transferred out of Level 3	0			0		0
Rocky Reach
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Power Contract Costs								$ 6,421,000
Asset Impairment Charges			$ 52,600,000
Change in forward prices								0.076%
Discounted cash flow [Member] | Low [Member] | Rocky Reach
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh			10.23					11.75
Fair Value Inputs, Power Contract Costs			$ 6,308,000					$ 6,237,000
Discounted cash flow [Member] | High [Member] | Rocky Reach
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh			29.05					31.44
Fair Value Inputs, Power Contract Costs			$ 7,085,000					$ 7,087,000
Discounted cash flow [Member] | Weighted Average [Member] | Rocky Reach
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh			21.27					22.53
Fair Value Inputs, Power Contract Costs			$ 6,468,000
Fair Value, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	94,105,000					94,105,000		$ 31,308,000
Derivative Liability	53,535,000					53,535,000		26,121,000
Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	1,180,000					1,180,000		2,174,000
Derivative Liability	23,903,000					23,903,000		4,271,000
Electric Portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability Value	(22,247,000)			(4,528,000)		(22,247,000)	(4,528,000)	$ (3,378,000)	$ (28,609,000)	$ (2,446,000)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Earnings	5,516,000			(4,611,000)		(21,321,000)	1,524,000
Included in regulatory assets/liabilities	0			0		0	0
Settlements	(846,000)						10,380,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3	0			0		0
Transferred out of Level 3	0			0		$ 0	1,424,000
Electric Portfolio [Member] | Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh)						23.80
Price (per MMBtu)								9
Electric Portfolio [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh)						46.25
Price (per MMBtu)								43.85
Electric Portfolio [Member] | Discounted cash flow [Member] | Weighted Average [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh)						32.85
Price (per MMBtu)								33.99
Electric Portfolio [Member] | Fair Value, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	48,876,000					$ 48,876,000		$ 19,933,000
Derivative Liability	42,884,000					42,884,000		17,504,000
Electric Portfolio [Member] | Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	917,000					917,000		651,000
Derivative Liability	23,164,000					23,164,000		$ 4,030,000
Natural Gas Portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Earnings	0			0		0	0
Included in regulatory assets/liabilities	(471,000)			206,000		(187,000)	2,485,000
Settlements	347,000			1,167,000		1,571,000	3,885,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3	0			$ 0		0	$ (400,000)
Transferred out of Level 3	0					$ 0
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh)						1.56
Price (per MMBtu)								1.25
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh)						3.61
Price (per MMBtu)								3.18
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | Weighted Average [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh)						2.50
Price (per MMBtu)								2.47
Natural Gas Portfolio [Member] | Fair Value, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	45,229,000					$ 45,229,000		$ 11,375,000
Derivative Liability	10,651,000					10,651,000		8,617,000
Natural Gas Portfolio [Member] | Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	263,000					263,000		1,523,000
Derivative Liability	$ 739,000					$ 739,000		$ 241,000
[1]	Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $4.8 million and $(4.5) million for three months ended September 30, 2020 and 2019 , respectively. 2. Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(19.0) million and $(4.4) million for nine months ended September 30, 2020 and 2019 , respectively.

Retirement Benefits - Benefit O

Retirement Benefits - Benefit Obligations (Details) - Subsidiaries [Member]	9 Months Ended
	Sep. 30, 2020
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Interest Credit	1.00%
employer contribution [Member] | Collective Bargaining Arrangement [Member] | UA represented [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	4.00%

Retirement Benefits Net Periodi

Retirement Benefits Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019
Parent Company [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	$ 6,084	$ 6,418	$ 18,253	$ 16,992	$ 22,656
Interest cost	6,295	7,252	18,885	21,685	28,913
Expected return on plan assets	(12,476)	(12,439)	(37,427)	(37,686)
Amortization of prior service cost	(393)	(495)	(1,180)	(1,485)
Amortization of net loss (gain)	2,040	362	6,120	863
Net periodic benefit cost	1,550	1,098	4,651	369
Parent Company [Member] | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	176	256	580	768	1,023
Interest cost	362	578	1,102	1,735	2,314
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	87	83	262	249
Amortization of net loss (gain)	512	341	1,610	1,024
Net periodic benefit cost	1,137	1,258	3,554	3,776
Parent Company [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	47	13	142	46	61
Interest cost	92	84	276	308	$ 410
Expected return on plan assets	(97)	(100)	(292)	(295)
Amortization of prior service cost	0	0	0	0
Amortization of net loss (gain)	(20)	(156)	(61)	(281)
Net periodic benefit cost	22	(159)	65	(222)
Subsidiaries [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	6,084	6,418	18,253	16,992
Interest cost	6,295	7,252	18,885	21,685
Expected return on plan assets	(12,478)	(12,443)	(37,433)	(37,700)
Amortization of prior service cost	(393)	(393)	(1,180)	(1,180)
Amortization of net loss (gain)	4,761	3,328	14,283	9,657
Net periodic benefit cost	4,269	4,162	12,808	9,454
Subsidiaries [Member] | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	176	256	580	768
Interest cost	362	578	1,102	1,735
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	87	83	262	250
Amortization of net loss (gain)	575	433	1,810	1,300
Net periodic benefit cost	1,200	1,350	3,754	4,053
Subsidiaries [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	47	13	142	46
Interest cost	92	84	276	308
Expected return on plan assets	(97)	(100)	(292)	(295)
Amortization of prior service cost	0	0	0	0
Amortization of net loss (gain)	(34)	(202)	(103)	(421)
Net periodic benefit cost	$ 8	$ (205)	$ 23	$ (362)

Retirement Benefits Change in N

Retirement Benefits Change in Net Benefit Obligation (Details) - Parent Company [Member] - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019
Qualified Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period			$ 774,305	$ 677,643	$ 677,643
Service cost	$ 6,084	$ 6,418	18,253	16,992	22,656
Interest cost	6,295	7,252	18,885	21,685	28,913
Actuarial loss (gain)			1,134		84,272
Benefits paid			(35,984)		(36,740)
Medicare part D subsidy received			0		0
Administrative Expense			0		(2,439)
Benefit obligation at end of period	776,593		776,593		774,305
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period			63,000	55,708	55,708
Service cost	176	256	580	768	1,023
Interest cost	362	578	1,102	1,735	2,314
Actuarial loss (gain)			(478)		6,756
Benefits paid			(18,140)		(2,801)
Medicare part D subsidy received			0		0
Administrative Expense			0		0
Benefit obligation at end of period	46,064		46,064		63,000
Other Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period			11,627	10,636	10,636
Amendments			0		(9,049)
Service cost	47	13	142	46	61
Interest cost	92	$ 84	276	$ 308	410
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment			0		(7,486)
Actuarial loss (gain)			34		(287)
Benefits paid			(740)		(982)
Medicare part D subsidy received			187		226
Administrative Expense			0		0
Benefit obligation at end of period	$ 11,526		11,526		11,627
Qualified Plan [Member] | Qualified Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Amendments			0		0
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment			0		0
Nonqualified Plan [Member] | Qualified Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment			0		0
Nonqualified Plan [Member] | Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Amendments			$ 0		$ 0

Retirement Benefits Activity (D

Retirement Benefits Activity (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2020
Qualified Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer contributions	$ 18	$ 18
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer contributions	$ 18.1	$ 2.3
Forecast [Member] | Qualified Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			$ 18
Forecast [Member] | Supplemental Employee Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			26.1
Forecast [Member] | Other Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			$ 0.3

Regulation and Rates (Details)

Regulation and Rates (Details) - USD ($) $ in Thousands	Sep. 30, 2020	Jul. 31, 2020	Jul. 08, 2020	Apr. 06, 2020	Jan. 15, 2020	Nov. 01, 2019	Jun. 20, 2019	Apr. 10, 2019	Mar. 01, 2019	Nov. 07, 2018	May 01, 2018	Mar. 01, 2018	Dec. 19, 2017	Dec. 18, 2017	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019	Apr. 30, 2019	Jul. 21, 2020	May 01, 2020	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
Regulation and Rates [Line Items]
Income tax (benefit) expense															$ (559)	$ (6,312)	$ 2,237	$ 3,597
Depreciation & amortization															161,209	138,281	462,890	483,693
Other regulatory assets	$ 713,909														713,909		713,909		$ 673,021
Subsidiaries [Member]
Regulation and Rates [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities										7.49%
Income tax (benefit) expense											$ 34,600				1,649	(5,085)	16,913	16,072
Annual Power Cost Variability, Interest																	1,600	300
PGA payable	101,906														101,906		101,906		132,766				$ 9,922
Depreciation & amortization															161,155	$ 138,253	462,742	483,623
Liabilities, Other than Long-term Debt, Noncurrent				$ 11,000																	$ 4,500
Customer Bill Assistance				$ 1
Other regulatory assets	713,909														713,909		713,909		673,021
Subsidiaries [Member] | Companys share [Member] | Under-collection [Member]
Regulation and Rates [Line Items]
Annual Power Cost Variability, Amount																	51,500	48,900
Subsidiaries [Member] | Customer's share [Member] | Under-collection [Member]
Regulation and Rates [Line Items]
Annual Power Cost Variability, Amount																	21,900	19,500
Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Storm Damage Costs Incurred During Period																	15,500	39,300
Public Utilities, Rate Case, Deferred Storm Costs Threshold																								$ 10,000	$ 8,000
Public Utilities, Rate Case, Deferred Storm Qualifying Costs																								$ 500
General Rate Case [Member] | Subsidiaries [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Return on Equity, Percentage					7.48%		7.62%
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities										7.49%			7.60%
Annual Revenue Requirement	25,600
General Rate Case [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage							6.90%
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 1,500
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 27,700	$ 900
Public Utilities, Approved Rate Increase (Decrease), Percentage		1.30%	0.05%
Public Utilities, Interim Rate Increase (Decrease), Amount		$ 59,600	$ 29,500
Public Utilities, Interim Rate Increase (Decrease), Percentage		2.90%	1.60%
Public Utilities Attrition Adjustment Increase Decrease Amount			$ 23,900
PublicUtilitiesIncremenalRateIncreaseDecreaseAmount		$ 30,100
General Rate Case [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage							7.90%
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 200	$ 1,300
Public Utilities, Approved Rate Increase (Decrease), Percentage		0.02%	0.15%
Public Utilities, Interim Rate Increase (Decrease), Amount		$ 42,900	$ 36,500
Public Utilities, Interim Rate Increase (Decrease), Percentage		5.60%	4.00%
Public Utilities Attrition Adjustment Increase Decrease Amount			$ 16,200
PublicUtilitiesIncremenalRateIncreaseDecreaseAmount		$ 6,400
General Rate Case [Member] | Maximum [Member] | Subsidiaries [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Return on Equity, Percentage					9.50%		9.80%
Public Utilities, Approved Return on Equity, Percentage			9.40%
Public Utilities, Approved Equity Capital Structure, Percentage			48.50%
Public Utilities, Approved Debt Capital Structure, Percentage			7.39%
Public Utilities, Approved Debt Capital Structure, Net of Tax, Percentage			6.80%
Expedited Rate Filing (ERF) [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage										0.90%
Public Utilities, Requested Rate Increase (Decrease), Amount										$ 18,900
Expedited Rate Filing (ERF) [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage										2.70%
Public Utilities, Requested Rate Increase (Decrease), Amount										$ 21,700		$ 6,100
Public Utilities, Approved Rate Increase (Decrease), Amount									$ 21,500			$ 25,900
Tax Cuts and Jobs Act [Member] | Subsidiaries [Member]
Regulation and Rates [Line Items]
Income tax (benefit) expense			$ 70,800
Tax Cuts and Jobs Act [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount																				$ (72,900)
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage																				(3.40%)
Contract with Customer, Refund Liability	$ 100														$ 100		100
Tax Cuts and Jobs Act [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount																				$ (23,600)
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage																				(2.70%)
Decoupling Mechanism [Member]
Regulation and Rates [Line Items]
Deferred Revenue, Revenue Recognized																	0
Decoupling Mechanism [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Contract with Customer, Liability, Revenue Recognized																	4,100
Decoupling Mechanism [Member] | Maximum [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage													3.00%
Decoupling Mechanism [Member] | Maximum [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage													5.00%	3.00%
Purchased Gas Adjustment [Member] | Subsidiaries [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount						$ 17,800
Purchased natural gas costs																	214,772		406,162
Purchased natural gas costs, recoverable																	(248,809)		(289,876)
Purchased natural gas adjustment, interest																	3,177		$ 6,558
Annual revenue						100,600
Out of Cycle PGA						54,000
Under collected commodity balances						114,400
Commodity Costs						10,800
Refund to Customers, remaining balance						4,100
Refund to Customers						$ 54,700
Other regulatory assets																						$ 4,900
Get to Zero Deferral Filing [Member] | Subsidiaries [Member]
Regulation and Rates [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities																			6.89%
Depreciation & amortization																	52,000		$ 21,700
Public Utilities, Property, Plant and Equipment, Equipment, Useful Life								10 years
Carrying charges on deferral																	1,200		$ 500
Storm That Occurred In 2018 [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Storm Damage Costs Deferred During Period																		400
Storm That Occurred In 2019 [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Storm Damage Costs Deferred During Period																	$ 5,300	$ 28,500

Schedule of Power Cost Adjustme

Schedule of Power Cost Adjustment Mechanism (Details) - Subsidiaries [Member] - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability, Interest	$ 1.6	$ 0.3
Customer's share [Member] | Under-collection [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability, Amount	21.9	19.5
Companys share [Member] | Under-collection [Member]
Regulatory Assets and Liabiliaties [Line Items]
Annual Power Cost Variability, Amount	$ 51.5	$ 48.9

Regulation and Rates (Details_2

Regulation and Rates (Details) - Subsidiaries [Member] - Purchased Gas Adjustment [Member] - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2019
Regulation and Rates [Line Items]
Purchased natural gas costs	$ 214,772	$ 406,162
Purchased natural gas costs, recoverable	(248,809)	(289,876)
Purchased natural gas adjustment, interest	$ 3,177	$ 6,558

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	Sep. 30, 2020USD ($)
Loss Contingencies [Line Items]
Purchase Obligation	$ 935.3
Colstrip Units 1 and 2 [Member]
Loss Contingencies [Line Items]
Ownership interest (percent)	50.00%
Jointly owned utility plant	2
Colstrip Units 3 and 4 [Member]
Loss Contingencies [Line Items]
Ownership interest (percent)	25.00%

Leases (Details)

Leases (Details)	9 Months Ended
	Sep. 30, 2020
Leases [Abstract]
Remaining lease term (less than)	25 years
Lessee, lease, renewal term (up to)	50 years

Leases - Schedule of the compon

Leases - Schedule of the components of lease expense (Details) - USD ($) $ in Thousands	3 Months Ended			9 Months Ended
	Sep. 30, 2020	Mar. 31, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Related Party Transaction [Line Items]
Amortization of right-of-use asset	$ 151		$ 128	$ 455	$ 410
Interest on lease liabilities	8		10	27	29
Total finance lease cost	159		138	482	439
Operating lease cost	$ 4,902		$ 5,311	$ 16,051	$ 15,318
Subsidiaries
Related Party Transaction [Line Items]
Right-of-Use, Modification, Operating		$ 14,700

Leases - Supplemental cash flow

Leases - Supplemental cash flow information related to leases (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019
Related Party Transaction [Line Items]
Operating cash flow for operating leases	$ 11,152	$ 10,437
Investing cash flow for operating leases	4,899	4,881
Operating cash flow for finance leases	27	29
Financing cash flow for finance leases	455	410
Subsidiaries
Related Party Transaction [Line Items]
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	4,996	2,032
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	$ 4,996	$ 2,032

Leases - Supplemental balance s

Leases - Supplemental balance sheet information related to leases (Details) - USD ($) $ in Thousands	Sep. 30, 2020	Dec. 31, 2019
Operating Leases
Operating lease right-of-use asset	$ 175,091	$ 183,048
Operating leases liabilities current	19,400	15,862
Operating lease liabilities long-term	163,453	174,327
Total Operating lease liabilities:	182,853	190,189
Finance Leases
Common Plant	1,033	1,488
Other current liabilities	546	669
Other deferred credits	420	811
Total finance lease liabilities	$ 966	$ 1,480
Weighted Average Remaining Lease Term
Operating leases	19 years	19 years 2 months 26 days
Finance leases	2 years 1 month 6 days	2 years 9 months 3 days
Weighted Average Discount Rate
Operating leases	3.59%	3.59%
Finance leases	2.98%	2.98%

Leases - Schedule of future min

Leases - Schedule of future minimum lease payments (Details) - USD ($) $ in Thousands	Sep. 30, 2020	Dec. 31, 2019
Operating Leases
Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year	$ 5,329
Operating Leases, Future Minimum Payments Due, Next Twelve Months		$ 22,500
Lessee, Operating Lease, Liability, Payments, Due Year Two	23,171	22,527
Lessee, Operating Lease, Liability, Payments, Due Year Three	22,522	21,856
Lessee, Operating Lease, Liability, Payments, Due Year Four	22,082	21,415
Lessee, Operating Lease, Liability, Payments, Due Year Five	21,349	20,690
Lessee, Operating Lease, Liability, Payments, Due after Year Five	162,578	160,410
Lessee, Operating Lease, Liability, Payments, Due	257,031	269,398
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(74,178)	(79,209)
Operating Lease, Liability	182,853	190,189
Finance Leases
Finance Lease, Liability, Payments, Remainder of Fiscal Year	160
Finance Lease, Liability, Payments, Due Next Twelve Months		643
Finance Lease, Liability, Payments, Due Year Two	508	508
Finance Lease, Liability, Payments, Due Year Three	279	279
Finance Lease, Liability, Payments, Due Year Four	98	98
Finance Lease, Liability, Payments, Due Year Five	0	0
Finance Lease, Liability, Payments, Due after Year Five	0	0
Finance Lease, Liability, Payment, Due	1,045	1,528
Finance Lease, Liability, Undiscounted Excess Amount	(79)	(48)
Finance Lease, Liability	$ 966	$ 1,480

Other (Details)

Other (Details) - USD ($)	Sep. 30, 2020	Sep. 30, 2020	Sep. 30, 2019	Jun. 18, 2020	May 19, 2020
Short-term Debt [Line Items]
Repayments of Debt		$ 150,200,000	$ 0
Gain (Loss) on Extinguishment of Debt		(13,546,000)	$ 0
Line of Credit Facility, Maximum Borrowing Capacity	$ 800,000,000	800,000,000
Line of Credit Facility, Maximum Amount Outstanding During Period		23,900,000
term-loan [Member]
Short-term Debt [Line Items]
Repayments of Debt		150,000,000
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Repayments of Debt		31,600,000
4.100% Senior Secured Note Due 2030 [Member] | Senior Secured Note [Member]
Short-term Debt [Line Items]
Long-term Debt, Gross					$ 650,000,000
Debt Instrument, Interest Rate, Stated Percentage					4.10%
6.500% Senior Secured Note Due 2020 [Member] | Senior Secured Note [Member]
Short-term Debt [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				6.50%
Extinguishment of Debt, Amount		463,200,000
Long-term debt, Principal				$ 450,000,000
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net				$ 300,000
Gain (Loss) on Extinguishment of Debt		13,500,000
Debt Instrument, Increase, Accrued Interest		400,000
Subsidiaries [Member]
Short-term Debt [Line Items]
Commercial Paper	221,000,000	$ 221,000,000
Subsidiaries [Member] | Working Capital Needs [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Amount Outstanding During Period	$ 0