Puget Energy (PSD) 10-K 21 Feb 20 2019 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2019	Jun. 30, 2017
Entity Information [Line Items]
Entity Registrant Name	PUGET ENERGY INC /WA
Entity Central Index Key	0001085392
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float		$ 0
Entity Common Stock, Shares Outstanding	200
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Subsidiaries [Member]
Entity Information [Line Items]
Entity Registrant Name	PUGET SOUND ENERGY INC
Entity Central Index Key	0000081100
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float		$ 0
Entity Common Stock, Shares Outstanding	85,903,791
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Document Period End Date	Dec. 31, 2019
Document Transition Report	false

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Electric	$ 2,497,041,000	$ 2,455,919,000	$ 2,420,663,000
Natural gas	875,371,000	850,748,000	997,759,000
Other	28,718,000	39,829,000	41,854,000
Total operating revenue	3,401,130,000	3,346,496,000	3,460,276,000
Purchased electricity	652,560,000	638,775,000	590,030,000
Electric generation fuel	282,864,000	204,174,000	206,275,000
Residential exchange	(79,187,000)	(77,454,000)	(75,933,000)
Purchased natural gas	290,976,000	296,699,000	360,009,000
Unrealized (gain) loss on derivative instruments, net	3,574,000	(41,662,000)	30,790,000
Utility operations and maintenance	596,676,000	602,638,000	592,277,000
Non-utility expense and other	47,907,000	54,519,000	53,864,000
Depreciation and amortization	656,323,000	666,432,000	481,969,000
Conservation amortization	96,571,000	111,714,000	121,216,000
Taxes other than income taxes	333,858,000	336,603,000	360,673,000
Total operating expenses	2,882,122,000	2,792,438,000	2,721,170,000
Operating income (loss)	519,008,000	554,058,000	739,106,000
Other income	59,905,000	52,957,000	49,283,000
Other Nonoperating Expense	(9,053,000)	(11,201,000)	(14,076,000)
AFUDC	14,559,000	13,695,000	10,826,000
Interest expense	(356,638,000)	(343,795,000)	(354,802,000)
Income (loss) before income taxes	227,781,000	265,714,000	430,337,000
Income tax (benefit) expense	17,073,000	30,092,000	255,143,000
Net Income (Loss) Attributable to Parent	210,708,000	235,622,000	175,194,000
Subsidiaries [Member]
Electric	2,497,041,000	2,455,919,000	2,420,663,000
Natural gas	875,371,000	850,748,000	997,759,000
Other	28,718,000	39,829,000	41,854,000
Total operating revenue	3,401,130,000	3,346,496,000	3,460,276,000
Purchased electricity	652,560,000	638,775,000	590,030,000
Electric generation fuel	282,864,000	204,174,000	206,275,000
Residential exchange	(79,187,000)	(77,454,000)	(75,933,000)
Purchased natural gas	290,976,000	296,699,000	360,009,000
Unrealized (gain) loss on derivative instruments, net	(3,574,000)	41,662,000	(30,790,000)
Utility operations and maintenance	596,676,000	602,638,000	592,277,000
Non-utility expense and other	44,403,000	51,549,000	52,389,000
Depreciation and amortization	656,220,000	666,324,000	481,955,000
Conservation amortization	96,571,000	111,714,000	121,216,000
Taxes other than income taxes	333,858,000	336,603,000	360,673,000
Total operating expenses	2,878,515,000	2,789,360,000	2,719,681,000
Operating income (loss)	522,615,000	557,136,000	740,595,000
Other income	47,766,000	39,847,000	34,867,000
Other Nonoperating Expense	(9,053,000)	(11,201,000)	(14,104,000)
AFUDC	14,559,000	13,695,000	10,826,000
Interest expense	(243,815,000)	(231,615,000)	(240,144,000)
Income (loss) before income taxes	332,072,000	367,862,000	532,040,000
Income tax (benefit) expense	39,148,000	50,700,000	211,986,000
Net Income (Loss) Attributable to Parent	$ 292,924,000	$ 317,162,000	$ 320,054,000

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net Income (Loss) Attributable to Parent	$ 210,708,000	$ 235,622,000	$ 175,194,000
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	(6,947,000)	(47,690,000)	9,430,000
Reclassification of stranded taxes to retained earnings due to tax reform	0	(5,230,000)	0
Other comprehensive income (loss)	(6,947,000)	(52,920,000)	9,430,000
Comprehensive income (loss)	203,761,000	182,702,000	184,624,000
Subsidiaries [Member]
Net Income (Loss) Attributable to Parent	292,924,000	317,162,000	320,054,000
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	2,022,000	(37,030,000)	18,288,000
Amortization of treasury interest rate swaps to earnings, net of tax	385,000	385,000	317,000
Reclassification of stranded taxes to retained earnings due to tax reform	0	27,333,000	0
Other comprehensive income (loss)	2,407,000	(63,978,000)	18,605,000
Comprehensive income (loss)	$ 295,331,000	$ 253,184,000	$ 338,659,000

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net unrealized gain (loss) from pension and postretirement plans, tax	$ (1,846)	$ (12,677)	$ 5,078
Subsidiaries [Member]
Net unrealized gain (loss) from pension and postretirement plans, tax	539	(9,844)	9,848
Reclassification of net unrealized loss on energy derivative instruments during the period, tax	0	0	0
Amortization of Financing Cash Flow Hedge Contracts to Earnings Tax	$ 102	$ 102	$ 171

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Utility Plant [Abstract]
Electric plant	$ 8,811,889,000	$ 8,515,482,000
Natural gas plant	3,916,040,000	3,598,732,000
Common plant	1,096,649,000	1,027,023,000
Less: Accumulated depreciation and amortization	(3,236,240,000)	(2,832,321,000)
Net utility plant	10,588,338,000	10,308,916,000
Other property and investments:
Goodwill	1,656,513,000	1,656,513,000
Other property and investments	286,975,000	244,444,000
Total other property and investments	1,943,488,000	1,900,957,000
Current assets:
Cash and cash equivalents	45,259,000	37,521,000
Restricted cash	20,887,000	18,041,000
Accounts receivable, net of allowance for doubtful accounts	316,352,000	338,782,000
Unbilled revenue	224,657,000	205,285,000
Purchased gas adjustment receivable	0	9,921,000
Materials and supplies, at average cost	115,684,000	116,180,000
Fuel and natural gas inventory, at average cost	52,083,000	53,351,000
Unrealized gain on derivative instruments	23,626,000	46,507,000
Prepaid expenses and other	27,504,000	25,674,000
Power contract acquisition adjustment gain	9,067,000	6,114,000
Total current assets	835,119,000	857,376,000
Other long-term and regulatory assets:
Power cost adjustment mechanism	41,745,000	4,735,000
purchase gas adjustment, long-term	132,766,000	0
Regulatory assets related to power contracts	14,146,000	16,693,000
Other regulatory assets	673,021,000	773,552,000
Unrealized gain on derivative instruments	7,682,000	2,512,000
Operating lease right-of-use asset	183,048,000	0
Power contract acquisition adjustment gain	147,530,000	156,597,000
Other	92,980,000	77,523,000
Total other long-term and regulatory assets	1,292,918,000	1,031,612,000
Total assets	14,659,863,000	14,098,861,000
Common shareholder’s equity:
Common stock	0	0
Additional paid-in capital	3,308,957,000	3,308,957,000
Retained earnings	775,491,000	629,003,000
Accumulated other comprehensive income (loss), net of tax	(84,149,000)	(77,202,000)
Total common shareholder’s equity	4,000,299,000	3,860,758,000
Long-term debt:
First mortgage bonds and senior notes	4,212,000,000	3,764,412,000
Pollution control bonds	161,860,000	161,860,000
Junior subordinated notes	0	0
Long-term debt	1,758,100,000	1,961,900,000
Debt discount, issuance costs and other	(211,635,000)	(215,681,000)
Total long-term debt	5,920,325,000	5,672,491,000
Total capitalization	9,920,624,000	9,533,249,000
Current liabilities:
Accounts payable	325,913,000	480,069,000
Short-term debt	176,000,000	379,297,000
Current maturities of long-term debt	452,412,000	0
Accrued expenses:
Taxes	99,979,000	118,112,000
Salaries and wages	50,091,000	50,785,000
Interest	74,855,000	70,099,000
Unrealized loss on derivative instruments	13,428,000	46,661,000
Power contract acquisition adjustment loss	2,418,000	2,547,000
Operating lease liabilities	15,862,000	0
Other	107,809,000	79,312,000
Total current liabilities	1,318,767,000	1,226,882,000
Other Long-term and regulatory liabilities:
Deferred income taxes	824,720,000	789,297,000
Unrealized loss on derivative instruments	12,693,000	11,095,000
Regulatory liabilities	730,879,000	747,203,000
Regulatory liability for deferred income taxes	946,179,000	975,974,000
Regulatory liabilities related to power contracts	156,597,000	162,711,000
Power contract acquisition adjustment loss	11,728,000	14,146,000
Operating lease liabilities	174,327,000	0
Other deferred credits	563,349,000	638,304,000
Total long-term and regulatory liabilities	3,420,472,000	3,338,730,000
Commitments and contingencies (Note 16)
Total capitalization and liabilities	14,659,863,000	14,098,861,000
Subsidiaries [Member]
Utility Plant [Abstract]
Electric plant	10,671,328,000	10,587,231,000
Natural gas plant	4,478,048,000	4,164,489,000
Common plant	1,121,568,000	1,052,544,000
Less: Accumulated depreciation and amortization	(5,682,606,000)	(5,495,348,000)
Net utility plant	10,588,338,000	10,308,916,000
Other property and investments:
Other property and investments	81,112,000	76,986,000
Total other property and investments	81,112,000	76,986,000
Current assets:
Cash and cash equivalents	44,004,000	35,452,000
Restricted cash	20,887,000	18,041,000
Accounts receivable, net of allowance for doubtful accounts	319,229,000	346,251,000
Unbilled revenue	224,657,000	205,285,000
Purchased gas adjustment receivable	0	9,921,000
Materials and supplies, at average cost	115,684,000	116,180,000
Fuel and natural gas inventory, at average cost	50,818,000	52,028,000
Unrealized gain on derivative instruments	23,626,000	46,507,000
Prepaid expenses and other	27,504,000	25,674,000
Total current assets	826,409,000	855,339,000
Other long-term and regulatory assets:
Power cost adjustment mechanism	41,745,000	4,735,000
purchase gas adjustment, long-term	132,766,000	0
Other regulatory assets	673,021,000	773,552,000
Unrealized gain on derivative instruments	7,682,000	2,512,000
Operating lease right-of-use asset	183,048,000	0
Other	90,924,000	75,483,000
Total other long-term and regulatory assets	1,129,186,000	856,282,000
Total assets	12,625,045,000	12,097,523,000
Common shareholder’s equity:
Common stock	859,000	859,000
Additional paid-in capital	3,485,105,000	3,275,105,000
Retained earnings	751,193,000	622,844,000
Accumulated other comprehensive income (loss), net of tax	(188,477,000)	(190,884,000)
Total common shareholder’s equity	4,048,680,000	3,707,924,000
Long-term debt:
First mortgage bonds and senior notes	4,212,000,000	3,764,417,000
Pollution control bonds	161,860,000	161,860,000
Junior subordinated notes	0	0
Debt discount, issuance costs and other	37,718,000	31,417,000
Total long-term debt	4,336,142,000	3,894,860,000
Total capitalization	8,384,822,000	7,602,784,000
Current liabilities:
Accounts payable	325,980,000	480,195,000
Short-term debt	176,000,000	379,297,000
Current maturities of long-term debt	2,412,000	0
Accrued expenses:
Taxes	99,977,000	117,993,000
Salaries and wages	50,091,000	50,785,000
Interest	48,917,000	43,951,000
Unrealized loss on derivative instruments	13,428,000	46,661,000
Operating lease liabilities	15,862,000	0
Other	107,809,000	79,312,000
Total current liabilities	840,476,000	1,198,194,000
Other Long-term and regulatory liabilities:
Deferred income taxes	977,163,000	926,403,000
Unrealized loss on derivative instruments	12,693,000	11,095,000
Regulatory liabilities	729,614,000	745,880,000
Regulatory liability for deferred income taxes	946,936,000	976,582,000
Operating lease liabilities	174,327,000	0
Other deferred credits	559,014,000	636,585,000
Total long-term and regulatory liabilities	3,399,747,000	3,296,545,000
Commitments and contingencies (Note 16)
Total capitalization and liabilities	$ 12,625,045,000	$ 12,097,523,000

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Assets
Construction work in progress	$ 591,199	$ 550,466
Current assets:
Allowance for doubtful accounts	$ 8,294	$ 8,408
Common shareholder’s equity:
Common stock, par value (in dollars per share)	$ 0	$ 0
Common stock, shares authorized (in shares)	1,000	1,000
Common stock, shares outstanding (in shares)	200	200
Subsidiaries [Member]
Assets
Construction work in progress	$ 591,199	$ 550,466
Current assets:
Allowance for doubtful accounts	$ 8,294	$ 8,408
Common shareholder’s equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	150,000,000	150,000,000
Common stock, shares outstanding (in shares)	85,903,791	85,903,791

CONSOLIDATED STATEMENTS OF COMM

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY - USD ($)	Total	Common Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Subsidiaries [Member]	Subsidiaries [Member]Common Stock	Subsidiaries [Member]Additional Paid-in Capital	Subsidiaries [Member]Retained Earnings	Subsidiaries [Member]Accumulated Other Comprehensive Income (Loss)
Balance at Dec. 31, 2016	$ 3,688,713,000	$ 0	$ 3,308,957,000	$ 413,468,000	$ (33,712,000)	$ 3,490,248,000	$ 859,000	$ 3,275,105,000	$ 359,795,000	$ (145,511,000)
Balance (in shares) at Dec. 31, 2016		200					85,903,791
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	175,194,000			175,194,000		320,054,000			320,054,000
Dividends, Common Stock	(123,307,000)			(123,307,000)		(227,783,000)			(227,783,000)
Other comprehensive income (loss)	9,430,000				9,430,000	18,605,000				18,605,000
Proceeds from Contributions from Parent						0
Reclassification of stranded taxes to retained earnings due to tax reform	0					0
Balance at Dec. 31, 2017	3,750,030,000		3,308,957,000	465,355,000	(24,282,000)	3,601,124,000	$ 859,000	3,275,105,000	452,066,000	(126,906,000)
Balance (in shares) at Dec. 31, 2017		200					85,903,791
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	235,622,000			235,622,000		317,162,000			317,162,000
Dividends, Common Stock	(77,204,000)			(77,204,000)		(173,716,000)			(173,716,000)
Other comprehensive income (loss)	(52,920,000)				(52,920,000)	(63,978,000)				(63,978,000)
Proceeds from Contributions from Parent						0
Reclassification of stranded taxes to retained earnings due to tax reform	(5,230,000)					27,333,000			27,332,000
Other Comprehensive Income (Loss) Reclassification of Stranded Taxes to RE for Pension Plans	5,230,000			5,230,000
Balance at Dec. 31, 2018	$ 3,860,758,000		3,308,957,000	629,003,000	(77,202,000)	$ 3,707,924,000	$ 859,000	3,275,105,000	622,844,000	(190,884,000)
Balance (in shares) at Dec. 31, 2018	200	200				85,903,791	85,903,791
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 210,708,000			210,708,000		$ 292,924,000			292,924,000
Dividends, Common Stock	(64,220,000)			(64,220,000)		(164,575,000)			(164,575,000)
Other comprehensive income (loss)	(6,947,000)				(6,947,000)	2,407,000				2,407,000
Proceeds from Contributions from Parent						210,000,000		(210,000,000)
Reclassification of stranded taxes to retained earnings due to tax reform	0					0
Balance at Dec. 31, 2019	$ 4,000,299,000		$ 3,308,957,000	$ 775,491,000	$ (84,149,000)	$ 4,048,680,000	$ 859,000	$ 3,485,105,000	$ 751,193,000	$ (188,477,000)
Balance (in shares) at Dec. 31, 2019	200	200				85,903,791	85,903,791

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net Income (Loss) Attributable to Parent	$ 210,708,000	$ 235,622,000	$ 175,194,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	656,323,000	666,432,000	481,969,000
Conservation amortization	96,571,000	111,714,000	121,216,000
Deferred Income Taxes and Tax Credits	7,475,000	19,457,000	254,524,000
Unrealized Gain (Loss) on Derivatives	(3,574,000)	41,662,000	(30,650,000)
Afudc Equity	15,802,000	17,191,000	15,027,000
Production tax credits	(68,622,000)	(83,976,000)	(53,331,000)
Other non-cash	(4,639,000)	15,339,000	17,568,000
Payment for Pension Benefits	18,000,000	18,000,000	18,000,000
Increase (Decrease) in Other Regulatory Assets	79,233,000	71,348,000	88,875,000
increase (decrease) in purchased gas	132,766,000	0	0
Increase (Decrease) in Other Operating Assets	16,098,000	(2,695,000)	27,411,000
Change in certain current assets and liabilities:
Increase (Decrease) in Accounts and Other Receivables	(3,058,000)	(17,659,000)	(132,000)
Increase (Decrease) in Materials and Supplies	6,018,000	9,177,000	625,000
Increase Decrease In Fuel And Gas Inventories	(1,268,000)	3,443,000	(8,266,000)
increase (decrease) in purchased gas adjustment, short-term	(9,921,000)	25,972,000	(18,836,000)
Increase (Decrease) in Prepaid Expense and Other Assets	1,103,000	3,679,000	(21,050,000)
Increase (Decrease) in Accounts Payable	(116,311,000)	117,270,000	26,396,000
Increase (Decrease) in Income Taxes Payable	(18,133,000)	164,000	6,520,000
Increase (Decrease) in Other Accounts Payable and Accrued Liabilities	15,163,000	(7,723,000)	13,079,000
Net Cash Provided by (Used in) Operating Activities, Total	527,336,000	904,181,000	972,131,000
Net Cash Provided by (Used in) Investing Activities
Construction expenditures excluding equity allowance for funds used during construction	959,387,000	1,072,670,000	1,040,135,000
Payments for (Proceeds from) Other Investing Activities	(6,908,000)	(2,097,000)	195,000
Net Cash Provided by (Used in) Investing Activities, Total	(952,479,000)	(1,070,573,000)	(1,040,330,000)
Net Cash Provided by (Used in) Financing Activities
Proceeds from (Repayments of) Short-term Debt	(203,297,000)	49,834,000	83,700,000
Payments of Dividends	64,220,000	77,204,000	123,307,000
Proceeds from Issuance of Long-term Debt	689,351,000	804,050,000	90,120,000
Repayments of Long-term Debt	0	600,000,000	0
Proceeds from (Payments for) Other Financing Activities	13,893,000	8,513,000	13,151,000
Net Cash Provided by (Used in) Financing Activities, Total	435,727,000	185,193,000	63,664,000
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect	10,584,000	18,801,000	(4,535,000)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Beginning Balance	55,562,000	36,761,000	41,296,000
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Ending Balance	66,146,000	55,562,000	36,761,000
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	328,703,000	322,476,000	326,798,000
Income Taxes Paid, Net	10,616,000	8,303,000	1,649,000
Non-cash financing and investing activities:
Capital Expenditures Incurred but Not yet Paid	58,329,000	97,673,000	92,959,000
Increase (Decrease) in Regulatory Liabilities	0	0
Hydro Treasury Grants
Non-cash financing and investing activities:
Increase (Decrease) in Regulatory Liabilities			95,935,000
Subsidiaries [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net Income (Loss) Attributable to Parent	292,924,000	317,162,000	320,054,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	656,220,000	666,324,000	481,955,000
Conservation amortization	96,571,000	111,714,000	121,216,000
Deferred Income Taxes and Tax Credits	20,474,000	30,995,000	210,842,000
Unrealized Gain (Loss) on Derivatives	(3,574,000)	41,662,000	(30,790,000)
Afudc Equity	15,802,000	17,191,000	15,027,000
Production tax credits	(68,622,000)	(83,976,000)	(53,331,000)
Other non-cash	(15,154,000)	4,428,000	6,445,000
Payment for Pension Benefits	18,000,000	18,000,000	18,000,000
Increase (Decrease) in Other Regulatory Assets	79,173,000	71,348,000	88,875,000
increase (decrease) in purchased gas	132,766,000	0	0
Increase (Decrease) in Other Operating Assets	8,967,000	(16,917,000)	14,547,000
Change in certain current assets and liabilities:
Increase (Decrease) in Accounts and Other Receivables	(7,650,000)	(12,626,000)	(13,285,000)
Increase (Decrease) in Materials and Supplies	6,018,000	9,177,000	625,000
Increase Decrease In Fuel And Gas Inventories	(1,210,000)	3,443,000	(8,266,000)
increase (decrease) in purchased gas adjustment, short-term	(9,921,000)	25,972,000	(18,836,000)
Increase (Decrease) in Prepaid Expense and Other Assets	1,103,000	3,679,000	(21,050,000)
Increase (Decrease) in Accounts Payable	(116,370,000)	117,397,000	26,396,000
Increase (Decrease) in Income Taxes Payable	(18,016,000)	930,000	5,635,000
Increase (Decrease) in Other Accounts Payable and Accrued Liabilities	15,371,000	(8,141,000)	12,438,000
Net Cash Provided by (Used in) Operating Activities, Total	623,924,000	995,904,000	1,086,803,000
Net Cash Provided by (Used in) Investing Activities
Construction expenditures excluding equity allowance for funds used during construction	919,271,000	1,010,506,000	963,652,000
Payments for (Proceeds from) Other Investing Activities	(6,908,000)	(2,097,000)	(241,000)
Net Cash Provided by (Used in) Investing Activities, Total	(912,363,000)	(1,008,409,000)	(963,411,000)
Net Cash Provided by (Used in) Financing Activities
Proceeds from (Repayments of) Short-term Debt	(203,297,000)	49,834,000	83,700,000
Payments of Dividends	164,575,000	173,716,000	227,783,000
Proceeds from Contributions from Parent	210,000,000	0	0
Proceeds from Issuance of Long-term Debt	443,151,000	594,750,000	0
Repayments of Long-term Debt	0	450,000,000	0
Proceeds from (Payments for) Other Financing Activities	14,558,000	9,121,000	15,801,000
Net Cash Provided by (Used in) Financing Activities, Total	299,837,000	29,989,000	(128,282,000)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect	11,398,000	17,484,000	(4,890,000)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Beginning Balance	53,493,000	36,009,000	40,899,000
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Ending Balance	64,891,000	53,493,000	36,009,000
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	219,665,000	221,155,000	224,423,000
Income Taxes Paid, Net	19,269,000	18,124,000	3,058,000
Non-cash financing and investing activities:
Capital Expenditures Incurred but Not yet Paid	58,329,000	97,673,000	92,959,000
Subsidiaries [Member] | Hydro Treasury Grants
Non-cash financing and investing activities:
Increase (Decrease) in Regulatory Liabilities	0	0	95,935,000
Colstrip Units 1 – 4 Common Facilities
Non-cash financing and investing activities:
Increase (Decrease) in Regulatory Assets and Liabilities	$ 4,163,000	$ (3,086,000)	$ (49,177,000)

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Significant Accounting Policies	(1) Summary of Significant Accounting Policies Basis of Presentation Puget Energy is an energy services holding company that owns Puget Sound Energy (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma liquefied natural gas (LNG) facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that are incurred by PSE and allocated to Puget LNG are related party transactions by nature. In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805) purchase accounting adjustments. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. Utility Plant Puget Energy and PSE capitalize, at original cost, additions to utility plant, including renewals and betterments. Costs include indirect costs such as engineering, supervision, certain taxes, pension and other employee benefits and an allowance for funds used during construction (AFUDC). Replacements of minor items of property are included in maintenance expense. When the utility plant is retired and removed from service, the original cost of the property is charged to accumulated depreciation and costs associated with removal of the property, less salvage, are charged to the cost of removal regulatory liability. Planned Major Maintenance Planned major maintenance is an activity that typically occurs when PSE overhauls or substantially upgrades various systems and equipment on a scheduled basis. Costs related to planned major maintenance are deferred and amortized to the next scheduled major maintenance. This accounting method also follows the Washington Utilities and Transportation Commission (Washington Commission) regulatory treatment related to these generating facilities. Other Property and Investments For PSE, the costs of other property and investments (i.e., non-utility) are stated at historical cost. Expenditures for refurbishment and improvements that significantly add to productive capacity or extend useful life of an asset are capitalized. Replacements of minor items are expensed on a current basis. Gains and losses on assets sold or retired, which were previously recorded in utility plant, are apportioned between regulatory assets/liabilities and earnings. However, gains and losses on assets sold or retired, not previously recorded in utility plant, are reflected in earnings. Depreciation and Amortization The Company provides for depreciation and amortization on a straight-line basis. Amortization is recorded for intangibles such as regulatory assets and liabilities, computer software and franchises. The annual depreciation provision stated as a percent of a depreciable electric utility plant was 3.4%, 3.3%, and 2.8% in 2019, 2018, and 2017, respectively; depreciable natural gas utility plant was 2.8%, 2.8%, and 3.4% in 2019, 2018, and 2017, respectively; and depreciable common utility plant was 7.3%, 7.1% and 8.3% in 2019, 2018, and 2017, respectively. The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability. Tacoma LNG Facility In August 2015, PSE filed a proposal with the Washington Commission to develop an LNG facility at the Port of Tacoma. Currently under construction at the Port of Tacoma, the facility is expected to be operational in 2021. The Tacoma LNG facility is designed to provide peak-shaving services to PSE’s natural gas customers. By storing surplus natural gas, PSE is able to meet the requirements of peak consumption. LNG will also provide fuel to transportation customers, particularly in the marine market. On January 24, 2018, Puget Sound Clean Air Agency (PSCAA) determined a Supplemental Environmental Impact Statement (SEIS) was necessary in order to rule on the air quality permit for the facility. As a result of requiring a SEIS, the Company's construction schedule was impacted. PSE received the SEIS which concluded the LNG facility would result in a net decrease in GHG emissions providing, in part, that the natural gas for the facility was sourced from British Columbia or Alberta. On December 10, 2019, the PSCAA approved the Notice of Construction permit, a decision which has been appealed to the Washington Pollution Control Hearings Board by each of the Puyallup Tribe of Indians and nonprofit law firm Earthjustice. Pursuant to an order by the Washington Commission, PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility. The remaining 57.0% of common capital and operating costs of the Tacoma LNG facility will be allocated to Puget LNG. Per this allocation of costs, $199.9 million and $165.6 million of construction work in progress related to Puget LNG's portion of the Tacoma LNG facility is reported in the Puget Energy "Other property and investments" financial statement line item as of December 31, 2019, and December 31, 2018, respectively. Additionally, $1.2 million, $2.0 million, and $0.3 million of operating costs are reported in the Puget Energy "Non-utility expense and other" financial statement line item in 2019, 2018, and 2017, respectively. Additionally, $162.8 million and $130.8 million of construction work in progress related to PSE’s portion of the Tacoma LNG facility is reported in the PSE “Utility plant - Natural gas plant” financial statement line item as of December 31, 2019, and December 31, 2018, respectively, as PSE is a regulated entity. Cash and Cash Equivalents Cash and cash equivalents consist of demand bank deposits and short-term highly liquid investments with original maturities of three months or less at the time of purchase. The carrying amounts of cash and cash equivalents are reported at cost and approximate fair value, due to the short-term maturity. Restricted Cash Restricted cash amounts are primarily represent cash posted as collateral for derivative contracts as well as funds required to be set aside for contractual obligations related to transmission and generation facilities. Materials and Supplies Materials and supplies are used primarily in the operation and maintenance of electric and natural gas distribution and transmission systems as well as spare parts for combustion turbines used for the generation of electricity. The Company records these items at weighted-average cost. Fuel and Natural Gas Inventory Fuel and natural gas inventory is used in the generation of electricity and for future sales to the Company’s natural gas customers. Fuel inventory consists of coal, diesel and natural gas used for generation. Natural gas inventory consists of natural gas and LNG held in storage for future sales. The Company records these items at the lower of cost or net realizable value method. Regulatory Assets and Liabilities PSE accounts for its regulated operations in accordance with ASC 980, “Regulated Operations” (ASC 980). ASC 980 requires PSE to defer certain costs or losses that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. It similarly requires deferral of revenues or gains that are expected to be returned to customers in the future. Accounting under ASC 980 is appropriate as long as rates are established by or subject to approval by independent third-party regulators; rates are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that rates set at levels that will recover costs can be charged to and collected from customers. In most cases, PSE classifies regulatory assets and liabilities as long-term when amortization periods extend longer than one year. For further details regarding regulatory assets and liabilities, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report. Puget Energy recorded regulatory assets and liabilities at the time of the merger related to power purchase contracts. Allowance for Funds Used During Construction AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. The amount of AFUDC recorded in each accounting period varies depending primarily upon the level of construction work in progress and the AFUDC rate used. AFUDC is capitalized as a part of the cost of utility plant; the AFUDC debt portion is credited to interest expense, while the AFUDC equity portion is credited to other income. Cash inflow related to AFUDC does not occur until these charges are reflected in rates. The current AFUDC rate authorized by the Washington Commission for natural gas and electric utility plant additions through December 18, 2017, was 7.77%. Effective December 19, 2017, with the Washington Commission order, the new AFUDC rate authorized is 7.60%. The Washington Commission authorized the Company to calculate AFUDC using its allowed rate of return. To the extent amounts calculated using this rate exceed the AFUDC calculated rate using the Federal Energy Regulatory Commission (FERC) formula, PSE capitalizes the excess as a deferred asset, crediting other income. The deferred asset is being amortized over the average useful life of PSE’s non-project electric utility plant which is approximately 30 years. Revenue Recognition Operating utility revenue is recognized when the basis of services is rendered, which includes estimated unbilled revenue. Revenue from retail sales is billed based on tariff rates approved by the Washington Commission. PSE's estimate of unbilled revenue is based on a calculation using meter readings from its automated meter reading (AMR) system. The estimate calculates unbilled usage at the end of each month as the difference between the customer meter readings on the last day of the month and the last customer meter readings billed. The unbilled usage is then priced at published rates for each tariff rate schedule to estimate the unbilled revenues by customer. PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $236.5 million, $239.3 million and $257.1 million for 2019, 2018, and 2017, respectively. The Company reports the collection of such taxes on a gross basis in operation revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income. PSE's electric and natural gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, natural gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. The mechanism mitigates volatility in revenue and gross margin erosion due to weather and energy efficiency. Any differences in revenue are deferred to a regulatory asset for under recovery or regulatory liability for over recovery under alternative revenue recognition standard. Revenue is recognized under this program when deemed collectible within 24 months based on alternative revenue recognition guidance. Decoupled rate increases are effective May 1 of each year subject to a 3.0% cap of total revenue for decoupled rate schedules. Any excess revenue above 3.0% will be included in the following year's decoupled rate. The Company will be able to recognize revenue below the 3.0% cap of total revenue for decoupled rate schedules. For revenue deferrals exceeding the annual 3.0% rate cap of total revenue for decoupled rate schedules, the Company will assess the excess amount to determine its ability to be collected within 24 months. On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 general rate case (GRC) to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. The rate test which limits the amount of revenues PSE can collect in its annual filings increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The Company will not record any decoupling revenue that is expected to take longer than 24 months to collect following the end of the annual period in which the revenues would have otherwise been recognized. Once determined to be collectible within 24 months, any previously non-recognized amounts will be recognized. Revenues associated with energy costs under the power cost adjustment (PCA) mechanism and purchased gas adjustment (PGA) mechanism are excluded from the decoupling mechanism. Allowance for Doubtful Accounts Allowance for doubtful accounts are provided for electric and natural gas customer accounts based upon a historical experience rate of write-offs of energy accounts receivable along with information on future economic outlook. The allowance account is adjusted monthly for this experience rate. The allowance account is maintained until either receipt of payment or the likelihood of collection is considered remote at which time the allowance account and corresponding receivable balance are written off. The Company’s balance for allowance for doubtful accounts at December 31, 2019, and 2018, was $8.3 million and $8.4 million, respectively. Self-Insurance PSE is self-insured for storm damage and certain environmental contamination associated with current operations occurring on PSE-owned property. In addition, PSE is required to meet a deductible for a portion of the risk associated with comprehensive liability, workers’ compensation claims and catastrophic property losses other than those which are storm related. Under the December 5, 2017, Washington Commission order regarding PSE’s GRC, the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018. Additionally, costs may only be deferred if the outage meets the Institute of Electrical and Electronics Engineers (IEEE) outage criteria for system average interruption duration index. Federal Income Taxes For presentation in Puget Energy's and PSE’s separate financial statements, income taxes are allocated to the subsidiaries on the basis of separate company computations of tax, modified by allocating certain consolidated group limitations which are attributed to the separate company. Taxes payable or receivable are settled with Puget Holdings, which is the ultimate tax payer. Natural Gas Off-System Sales and Capacity Release PSE contracts for firm natural gas supplies and holds firm transportation and storage capacity sufficient to meet the expected peak winter demand for natural gas by its firm customers. Due to the variability in weather, winter peaking consumption of natural gas by most of its customers and other factors, PSE holds contractual rights to natural gas supplies and transportation and storage capacity in excess of its average annual requirements to serve firm customers on its distribution system. For much of the year, there is excess capacity available for third-party natural gas sales, exchanges and capacity releases. PSE sells excess natural gas supplies, enters into natural gas supply exchanges with third parties outside of its distribution area and releases to third parties excess interstate natural gas pipeline capacity and natural gas storage rights on a short-term basis to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. The proceeds from such activities, net of transactional costs, are accounted for as reductions in the cost of purchased natural gas and passed on to customers through the PGA mechanism, with no direct impact on net income. As a result, PSE nets the sales revenue and associated cost of sales for these transactions in purchased natural gas. As part of the Company’s electric operations, PSE purchases natural gas for its gas-fired generation facilities. The projected volume of natural gas for power is relative to the price of natural gas. Based on the market prices for natural gas, PSE may use the natural gas it has already purchased to generate power or PSE may sell the already purchased natural gas. The net proceeds from selling natural gas, previously purchased for power generation, are accounted for in electric operating revenue and are included in the PCA mechanism. Production Tax Credit Production Tax Credits (PTCs) represent federal income tax incentives available to taxpayers that generate energy from qualifying renewable sources during the first ten years of operation. Before the 2017 GRC, the tax savings from these credits were intended to be refunded by PSE to its customers when monetized, used on the income tax return, through its revenue requirement as initially approved by the Washington Commission. As the Company had not generated taxable income with which to monetize the credits, they had not been refunded to customers. Amounts to be refunded have been recorded as a regulatory liability with an offsetting reduction to revenue as it was intended to be refunded through the revenue requirement. A deferred tax asset and reduction to deferred tax expense were also recorded for the regulatory liability. These entries resulted in no net income impact. In connection with the GRC settlement in 2017, the Washington Commission authorized the Company to utilize the tax savings associated with the monetization of the PTCs to fund the following: (i) Colstrip Community Transition Fund, (ii) unrecovered Colstrip plant and (iii) incurred decommissioning and remediation costs for Colstrip. As PTCs will no longer be refunded to customers through the revenue requirement, a non-cash increase to revenue and deferred tax expense will be recorded as the PTCs are monetized. These entries will result in no net income impact. As of December 31, 2019 and 2018, $67.5 million and $84.0 million of PTCs were estimated to be monetized through tax filings, respectively. Accounting for Derivatives ASC 815, "Derivatives and Hedging" (ASC 815) requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value unless the contracts qualify for an exception. PSE enters into derivative contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts and swaps. Some of PSE’s physical electric supply contracts qualify for the normal purchase normal sale (NPNS) exception to derivative accounting rules. PSE may enter into financial fixed price contracts to economically hedge the variability of certain index-based contracts. Those contracts that do not meet the NPNS exception are marked-to-market to current earnings in the statements of income, subject to deferral under ASC 980, for natural gas related derivatives due to the PGA mechanism. For additional information, see Note 10, "Accounting for Derivative Instruments and Hedging Activities" to the consolidated financial statements included in Item 8 of this report. Fair Value Measurements of Derivatives ASC 820, “Fair Value Measurements and Disclosures” (ASC 820), defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). As permitted under ASC 820, the Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements as it believes that the approach is used by market participants for these types of assets and liabilities. Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company values derivative instruments based on daily quoted prices from an independent external pricing service. When external quoted market prices are not available for derivative contracts, the Company uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves. All derivative instruments are sensitive to market price fluctuations that can occur on a daily basis. For additional information, see Note 11, "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report. Debt Related Costs Debt premiums, discounts, expenses and amounts received or incurred to settle hedges are amortized over the life of the related debt for the Company. The premiums and costs associated with reacquired debt are deferred and amortized over the life of the related new issuance, in accordance with ratemaking treatment for PSE and presented net of long-term liabilities on the balance sheet. Leases PSE determines if an arrangement is, or contains, a lease at inception of the contract. If the arrangement is, or contains a lease, PSE assesses whether the lease is operating or financing for income statement and balance sheet classification. Operating leases are included in operating lease right-of-use (ROU) assets, operating lease current liabilities, and operating lease liabilities in our consolidated balance sheets. Finance leases are included in utility plant, other current liabilities, and other deferred credits in our consolidated balance sheets. ROU assets represent the right to use an underlying asset for the lease term, and consist of the amount of the initial measurement of the lease liability, any lease payments made to the lessor at or before the commencement date, minus any lease incentives received, and any initial direct costs incurred by the lessee. Lease liabilities represent our obligation to make lease payments arising from the lease and are measured at present value of the lease payments not yet paid, discounted using the discount rate for the lease, determined based on PSE's incremental borrowing rate, at commencement. As most of PSE's leases do not provide an implicit interest rate, PSE uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. For fleet, IT and wind farm leases, this rate is applied using a portfolio approach. The lease terms may include options to extend or terminate the lease when it is reasonably certain that PSE will exercise that option. On the statement of income, operating leases are generally accounted for under a straight-line expense model, while finance leases, which were previously referred to as capital leases, are generally accounted for under a financing model. Consistent with the previous lease guidance, however, the standard allows rate-regulated utilities to recognize expense consistent with the timing of recovery in rates.

New Accounting Pronouncements

New Accounting Pronouncements	12 Months Ended
	Dec. 31, 2019
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements	New Accounting Pronouncements Recently Adopted Accounting Guidance Lease Accounting In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" . The FASB issued this ASU to increase transparency and comparability among organizations by recognizing right-of-use lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. To meet that objective, the FASB amended the FASB ASC and created Topic 842, Leases. ASU 2016-02 requires lessees to recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The income statement recognition is similar to existing lease accounting and is based on lease classification. Under the new guidance, lessor accounting is largely unchanged. In January 2018, the FASB issued ASU 2018-01, "Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842" . In connection with the FASB’s transition support efforts, the amendments in this update provide an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current guidance in Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 upon adoption. Land easements (also commonly referred to as rights of way) represent the right to use, access, or cross another entity’s land for a specified purpose. The Company elected this practical expedient. In July 2018, the FASB issued both ASU 2018-10 and ASU 2018-11, "Leases (Topic 842): Codification Improvements" and "Leases (Topic 842): Targeted Improvements" . These ASUs provide entities with both clarification on existing guidance issued in ASU 2016-02, as well as an additional transition method to adopt the new leasing standard. Under the new transition method, the entity initially applies the new standard at the adoption date by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Consequently, an entity's reporting for the comparative periods presented in the financial statements will continue to be in accordance with Topic 840. The Company has elected to adopt the standard using this new modified transition method. In preparation for adoption of the standard, the Company assembled a project team that met bi-weekly to make key accounting assessments and perform pre-implementation controls related to the scoping and completeness of existing leases. Additionally, the Company implemented a new leasing system and drafted accounting policies including discount rate, variable pricing, power purchase agreements, and election of practical expedients. In addition to the land easement practical expedient, the Company has elected the practical expedient package. These amendments are effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company adopted ASU 2016-02 as of January 1, 2019, which resulted in the recognition of right-of-use asset and lease liability financial statement line items that have not previously been recorded and are material to the consolidated balance sheets. Adoption of the standard did not have a material impact on the income statement. The financial impact as of the date of adoption was not materially different than what has been disclosed as of December 31, 2019, in Note 9, "Leases", to the consolidated financial statements included in Item 8 of this report. Internal-Use Software In August 2018, the FASB issued ASU 2018-15, "Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract" . These amendments align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). The accounting for the service element of a hosting arrangement that is a service contract is not affected by these amendments. While the standard requires that the capitalized implementation costs be reported on the balance sheet in the same manner as a prepayment and the related amortization expense in the same expense line item on the income statement as the expense for the associated cloud computing arrangement, the Company capitalizes implementation costs associated with cloud computing arrangements as a utility plant asset and amortizes the costs in a consistent manner in accordance with FERC Docket Number AI90-1-000. The amendments in this update are effective for public business entities for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption of the amendments in this update is permitted, including adoption in any interim period, for all entities. The amendments in this update should be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. The Company adopted this update prospectively in 2019 for implementation costs incurred in hosting arrangements and application of the amendment did not have a material impact on the consolidated financial statements. Accounting Standards Issued but Not Yet Adopted Credit Losses In June 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 Company has analyzed its financial instruments within the scope of the guidance and does not expect a material impact to the consolidated financial statements.. 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 guidance in ASU No. 2018-13 eliminates such disclosures as the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy. The amendments in ASU No. 2018-13 add new disclosure requirements for Level 3 measurements. ASU No. 2018-13 is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted for any eliminated or modified disclosures. Certain disclosures in ASU No. 2018-13 are required to be applied on a retrospective basis and others on a prospective basis. As the amendment contemplates changes in disclosures only, it will have no material impact on the Company's results of operations, cash flows, or consolidated balance sheet. Retirement Benefits In August 2018, the FASB issued ASU 2018-14, " Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans" . This update modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans through added, removed, and clarified requirements of relevant disclosures. The amendments in this update are effective for fiscal years ending after December 15, 2020, for public business entities and for fiscal years ending after December 15, 2021, for all other entities. Early adoption is permitted for all entities. The Company is in the process of evaluating potential impacts of these amendments to Note 13, "Retirement Benefits" to the consolidated financial statements.

Revenue (Notes)

Revenue (Notes)	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer	Revenue The following table presents disaggregated revenue from contracts with customers, and other revenue by major source: Puget Energy and (Dollars in Thousands) Year Ended December 31, Revenue from Contracts with Customers: 2019 2018 Electric retail $ 2,132,522 $ 2,138,008 Natural gas retail 870,457 849,898 Other 308,111 234,187 Total revenue from contracts with customers 3,311,090 3,222,093 Alternative revenue programs (18,634) (22,852) Other non-customer revenue 108,674 147,255 Total operating revenue $ 3,401,130 $ 3,346,496 Revenue at PSE is recognized when performance obligations under the terms of a contract or tariff with our customers are satisfied. Performance obligations are satisfied generally through performance of PSE's obligation over time or with transfer of control of electric power, natural gas, and other revenue from contracts with customers. Revenue is measured as the amount of consideration expected to be received in exchange for transferring goods and services. Electric and Natural Gas Retail Revenue Electric and natural gas retail revenue consists of tariff-based sales of electricity and natural gas to PSE's customers. For tariff contracts, PSE has elected the portfolio approach practical expedient model to apply the revenue from contracts with customers to groups of contracts. The Company determined that the portfolio approach will not differ from considering each contract or performance obligation separately. Electric and natural gas tariff contracts include the performance obligation of standing ready to perform electric and natural gas services. The electricity and natural gas the customer chooses to consume is considered an option and is recognized over time using the output method when the customer simultaneously consumes the electricity or natural gas. PSE has elected the right to invoice practical expedient for unbilled retail revenue. The obligation of standing ready to perform electric service and the consumption of electricity and natural gas at market value implies a right to consideration for performance completed to date. The Company believes that tariff prices approved by the Washington Commission represent stand-alone selling prices for the performance obligations under ASC 606. PSE collects Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes and presents the taxes on a gross basis, as PSE is the taxpayer for those excise and municipal taxes. Other Revenue from Contracts with Customers Other revenue from contracts with customers is primarily comprised of electric transmission, natural gas transportation, biogas, and wholesale revenue sold on an intra-month basis. Electric Transmission and Natural Gas Transportation Transmission and transportation tariff contracts include the performance obligation to transmit and transport electricity or natural gas. Transfer of control and recognition of revenue occurs over time as the customer simultaneously receives the transmission and transportation services. Measurement of satisfaction of this performance obligation is determined using the output method. Similar to retail revenue, the Company utilizes the right to invoice practical expedient as PSE’s right to consideration is tied directly to the value of power and natural gas transmitted and transported each month. The price is based on the tariff rates that were approved by the Washington Commission or the FERC and, therefore, corresponds directly to the value to the customer for performance completed to date. Biogas Biogas is a renewable natural gas fuel that PSE purchases and sells along with the renewable green attributes derived from the renewable natural gas. Biogas contracts include the performance obligations of biogas and renewable credit delivery upon PSE receiving produced biogas from its supplier. Transfer of control and recognition of revenue occurs at a point in time as biogas is considered a storable commodity and may not be consumed as it is delivered. Wholesale Wholesale revenue at PSE includes sales of electric power and non-core natural gas to other utilities or marketers. Wholesale revenue contracts include the performance obligation of physical electric power or natural gas. There are typically no added fixed or variable amounts on top of the established rate for power or natural gas and contracts always have a stated, fixed quantity of power or natural gas delivered. Transfer of control and recognition of revenue occurs at a point in time when the customer takes physical possession of electric power or natural gas. Non-core gas consists of natural gas supply in excess of natural gas used for generation, sold to third parties to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. PSE reports non-core gas sold net of costs as PSE does not take control of the natural gas but is merely an agent within the market that connects a seller to a purchaser. Other Revenue In accordance with ASC 606, PSE separately presents revenue not collected from contracts with customers that falls under other accounting guidance.

Regulation and Rates

Regulation and Rates	12 Months Ended
	Dec. 31, 2019
Regulated Operations [Abstract]
Regulation and Rates Disclosure [Text Block]	Regulation and Rates Regulatory Assets and Liabilities Regulatory accounting allows PSE to defer certain costs that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. It similarly requires deferral of revenues or gains that are expected to be returned to customers in the future. The net regulatory assets and liabilities at December 31, 2019, and 2018, included the following: Puget Sound Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2019 2018 Storm damage costs electric 1 to 4 years $ 121,894 $ 118,331 Chelan PUD contract initiation 11.8 years 83,875 90,964 Environmental remediation (a) 68,486 76,345 Lower Snake River 17.4 years 62,899 67,021 Decoupling deferrals and interest Less than 2 years 43,509 65,779 Baker Dam licensing operating and maintenance costs N/A 56,427 55,607 Deferred Washington Commission AFUDC 30 years 57,553 52,029 Property tax tracker Less than 2 years 22,442 45,621 Unamortized loss on reacquired debt 2 to 48 years 40,177 42,378 Colstrip 1 & 2 Regulatory Asset N/A — 37,674 Energy conservation costs (a) 25,272 30,701 Get to zero depreciation expense deferral N/A 22,148 — Advanced metering infrastructure (a) 14,845 — Generation plant major maintenance, excluding Colstrip 3 to 10 years 12,744 15,027 PGA deferral of unrealized losses on derivative instruments N/A — 14,739 White River relicensing and other costs 1 year 6,399 12,966 Mint Farm ownership and operating costs 5.3 years 10,318 12,319 PGA receivable 2 years 132,766 9,922 Snoqualmie licensing operating and maintenance costs N/A 7,442 7,407 Colstrip major maintenance 0.0 years 2,929 6,841 PCA mechanism N/A 41,745 4,735 Colstrip common property 4.4 years 3,188 3,903 Ferndale 0.0 years — 3,316 Various other regulatory assets (a) 10,474 14,583 Total PSE regulatory assets $ 847,532 $ 788,208 Deferred income taxes (d) N/A (946,936) (976,582) Cost of removal (b) (469,922) (424,727) Treasury grants 18 years (101,981) (168,884) Production tax credits (c) (85,323) (93,616) Gain on Sale Shuffleton N/A (12,483) — Microsoft special contract regulatory liability N/A (12,661) — Repurposed production tax credits N/A (23,171) — Accumulated provision for rate refunds N/A — (34,579) Total decoupling liability Less than 2 years (8,500) (13,758) Various other regulatory liabilities (a) (15,573) (10,316) Total PSE regulatory liabilities (1,676,550) (1,722,462) PSE net regulatory assets (liabilities) $ (829,018) $ (934,254) __________________ (a) Amortization periods vary depending on timing of underlying transactions. (b) The balance is dependent upon the cost of removal of underlying assets and the life of utility plant. (c) Amortize as PTCs are utilized by PSE on its tax return. (d) For additional information, see Note 14,"Income Taxes" to the consolidated financial statements included in Item 8 of this report. Puget Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2019 2018 Total PSE regulatory assets (a) $ 847,532 $ 788,208 Puget Energy acquisition adjustments: Regulatory assets related to power contracts 6 to 33 years 14,146 16,693 Total Puget Energy regulatory assets 861,678 804,901 Total PSE regulatory liabilities (a) (1,676,550) (1,722,462) Puget Energy acquisition adjustments: Deferred income taxes 757 608 Regulatory liabilities related to power contracts 6 to 33 years (156,597) (162,711) Various other regulatory liabilities Varies (1,265) (1,323) Total Puget Energy regulatory liabilities (1,833,655) (1,885,888) Puget Energy net regulatory asset (liabilities) $ (971,977) $ (1,080,987) ____________________ (a) Puget Energy’s regulatory assets and liabilities include purchase accounting adjustments under ASC 805. If the Company determines that it no longer meets the criteria for continued application of ASC 980, the Company would be required to write-off its regulatory assets and liabilities related to those operations not meeting ASC 980 requirements. Discontinuation of ASC 980 could have a material impact on the Company's financial statements. In accordance with guidance provided by ASC 410, “Asset Retirement and Environmental Obligations (ARO),” PSE reclassified from accumulated depreciation to a regulatory liability $469.9 million and $424.7 million in 2019 and 2018, respectively, for the cost of removal of utility plant. These amounts are collected from PSE’s customers through depreciation rates. General Rate Case Filing PSE filed a GRC with the Washington Commission on June 20, 2019, requesting an overall increase in electric and natural gas rates of 6.9% and 7.9% respectively. PSE requested a return on equity of 9.8% with an overall rate of return of 7.62%. In addition to the traditional areas of focus (revenue requirements, cost allocation, rate design and cost of capital), the Company completed an attrition study and included a portion of the attrition revenue requirement in the overall request in order address the expected regulatory lag in the rate year. Additionally, as the non-plant related excess deferred taxes that resulted from the Tax Cuts and Jobs Act (TCJA) remained outstanding from PSE’s Expedited Rate Filing (ERF) as discussed below, PSE requested in its GRC to pass back the amounts over four years. On September 17, 2019, PSE filed a supplemental filing in the GRC, which provided updates as discussed in our original filing, but did not impact the requested overall electric and natural gas rate increases, return on equity or overall rate of return as originally filed. On January 15, 2020, PSE filed rebuttal testimony which included a reduction to the requested return on equity to 9.5%, which decreased the rate of return to 7.48%. The requested rate increase for both electric and natural gas remained at 6.9% and 7.9%, respectively. For both electric and natural gas PSE did not originally request its full attrition adjustment; therefore, the decrease in return on equity led to a reduction in the electric rate increase of only $1.5 million and did not have an impact on the natural gas rate increase. In January 2017, PSE filed its GRC with the Washington Commission. The GRC filing included a required plan to address Colstrip Units 1 and 2 closures, requested that electric energy supply fixed costs be included in PSE's decoupling mechanism, and contained requests for two new mechanisms to address regulatory lag. The Washington Commission entered a final order accepting the multi-party settlement agreement and determined the contested issues in the case on December 5, 2017, and new rates became effective December 19, 2017. The settlement agreement provided for a weighted cost of capital of 7.6%, or 6.55% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.5%. The settlement also resulted in a combined electric tariff change that resulted in a net increase of $20.2 million, or 0.9%, annually, and a combined natural gas tariff change that resulted in a net decrease of $35.5 million, or 3.8%, annually. The 2017 GRC also re-purposed the benefit of hydro-related treasury grants to fund and recover decommissioning and remediation costs for Colstrip Units 1 and 2. Expedited Rate Filing Rate Adjustment On November 7, 2018, PSE filed an expedited rate filing (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 for natural gas and no rate increase for electric which became effective March 1, 2019. As is discussed below, these rates include the offsetting effect of passing back to customers plant related excess deferred income taxes that resulted from the TCJA, using the average rate assumption method (ARAM) amounts to arrive at the settlement rate changes. The settlement agreement provides for the pass back of plant related excess deferred income taxes that resulted from the TCJA using the ARAM methodology based on 2018 amounts beginning March 1, 2019, in the amount of $6.1 million for natural gas customers and $25.9 million for electric customers. The settlement agreement left the determination for the regulatory treatment of the remaining items related to the TCJA, listed below, to PSE’s next GRC, filed June 20, 2019: 1) excess deferred taxes for non-plant-related book/tax differences for periods prior to March 1, 2019, 2) the deferred balance associated with the over-collection of income tax expense for the period January 1 through April 30, 2018 (the time period that encompasses the effective date of the TCJA to May 1, 2018, the effective date of the TCJA rate change); and 3) the turnaround of plant related excess deferred income taxes using the ARAM method for the period from January 2018 through February 2019, the rate effective date for the ERF. The agreement provides that PSE may defer the depreciation expense associated with PSE’s ongoing investment in its advanced metering infrastructure (AMI) investment and may defer the return on the AMI investment that was included in the test year of the filing. The agreement preserves the parties' rights to argue whether or not these deferrals should be recovered in the Company’s 2019 GRC. 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 must pass 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 began May 1, 2019. 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, 2019, 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. 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 July 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 (PCORC). 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 December 31, 2019, PSE performed an analysis to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980. If not, for GAAP purposes only, PSE would need to record a reserve against the decoupling revenue and regulatory asset balance. Once the reserve is probable of collection within 24 months from the end of the annual period, the reserve can be recognized as decoupling revenue. The analysis indicated that electric and natural gas deferred revenue will be collected within 24 months of the annual period; therefore, no adjustment was booked to 2019 decoupling revenue. The previously unrecognized decoupling deferrals of $0.8 million and $20.8 million at December 31, 2018, and December 31, 2016, were recognized as decoupling revenue in the year ended December 31, 2019, and December 31, 2017, respectively. 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 In September 2016, PSE filed an accounting petition with the Washington Commission which requested deferral of the variances, either positive or negative, between the fixed costs previously recovered in the PCA and the revenue received to cover the allowed fixed costs. The deferral period requested was January 1, 2017, through December 31, 2017, when rates were to go into effect from PSE's 2017 GRC. In November 2016, the Washington Commission issued Order No. 01 approving PSE’s accounting petition. With the final determination in PSE’s GRC, this deferral ceased with the rate effective date of December 19, 2017. For the year ended December 31, 2019, in its PCA mechanism, PSE under recovered its allowable costs by $67.2 million of which $36.0 million was apportioned to customers and $1.0 million of interest was accrued on the deferred customer balance. This compares to an under recovery of allowable costs of $3.5 million for the year ended December 31, 2018, of which no amounts were apportioned to customers and accrued $0.2 million of interest on the total deferred customer balance. Power costs have been higher than the allowed base line in 2019 which has led to an increase in the PCA deferral causing a higher under-collection compared to the prior year. Actual power costs were higher than baseline rates in 2018 also but by a narrower margin, resulting in lower under-collection. Power prices increased during 2019 as compared to the prior year due to: (i) Cold weather in February and early March, which drove regional loads and demand for power up; (ii) Westcoast pipeline capacity limitations, which contributed to higher natural gas and power prices; (iii) An outage on a transmission line, which contributed to a liquidity crisis at Mid-C and resulted in high market power prices; and (iv) The relative prices of natural gas and power, which reduced the supply of natural gas-fired generation and increased the demand for market power, increasing prices. Purchased Gas Adjustment For the year ended December 31, 2018, PSE had a beginning PGA payable balance of $16.1 million, incurred actual natural gas costs of $319.3 million, of which $292.0 million was recovered through rates. The difference between actual and allowed costs, less interest $1.3 million, resulted in a PGA receivable of $9.9 million. For the year ended December 31, 2019, PSE had incurred actual natural gas costs of $406.2 million, of which $289.9 million was recovered through rates. The difference between actual and allowed costs, plus interest of $6.6 million, resulted in a PGA receivable of $132.8 million. 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 amortization period will be from May 2019 through April 2020. On October 24, 2019, the Washington Commission approved PSE’s request for November 2019 PGA rates, with the rate change taking effect on November 1, 2019. As part of that filing, PSE requested PGA rates increase annual revenue by $17.8 million, while the new tracker rates increased by annual revenue of $100.6 million; this was in addition to continuing the collection on the remaining balance of $54.0 million from the out-of-cycle PGA. The tracker rates include deferral balances for the three separate amounts: (i) $114.4 million of under collected commodity balances deferred in February and March; (ii) a $10.8 million balance of over-collected commodity costs for the 2018 PGA, and (iii) a $4.1 million remaining balance from the $54.7 million credit to customers, caused by the 2017 over-collection, established in the 2018 tracker. The high commodity deferral balances for winter months through March 2019 were the result of three noteworthy events last winter experienced by PSE: the Enbridge pipeline rupture, unusually low temperatures in February and March, and a compressor failure in February at the Jackson Prairie storage facility. Additionally, to reduce customer impact, as part of the approved PGA filing, PSE will be collecting $114.4 million commodity deferrals and related interest over a two year period, instead of the historic one year period, from November 2019 through October 2021. Get to Zero Depreciation Deferral On April 10, 2019, PSE filed an accounting petition with the Washington Commission, requesting authorization to defer depreciation expense associated with Get To Zero (GTZ) projects that were placed in service after June 30, 2018. The GTZ project consists of a number of short-lived technology upgrades. The depreciation expense associated with the GTZ projects with lives of 10 years or less that were placed in service after June 30, 2018, were deferred beginning May 1 per the petition request. For the year ended December 31, 2019, PSE deferred $21.7 million of depreciation expense for GTZ. In addition to the deferral of depreciation expense, PSE had also requested to defer carrying charges on the GTZ deferral, to be calculated utilizing the Company’s currently authorized after tax rate of return, or 6.89% per the 2018 ERF. For the year ended December 31, 2019, PSE deferred $0.5 million of carrying charges on the deferral. The GTZ accounting petition was consolidated with PSE’s 2019 GRC and is currently being reviewed by the Washington Commission. If authorized, both the GTZ depreciation and interest on the deferral will be begin amortizing over three years in May 2020 Storm Damage Deferral Accounting The Washington Commission issued a GRC order that defined deferrable storm events and provided that costs in excess of the annual cost threshold may be deferred for qualifying storm damage costs that meet the modified Institute of Electrical and Electronics Engineers outage criteria for system average interruption duration index. For the year ended December 31, 2019, PSE incurred $39.3 million in storm-related electric transmission and distribution system restoration costs, of which the Company deferred $0.4 million and $28.5 million as regulatory assets related to storms that occurred in 2018 and 2019, respectively. This compares to $25.4 million incurred in storm-related electric transmission and distribution system restoration costs for the year ended December 31, 2018, of which the Company deferred $3.3 million and $11.9 million as regulatory assets related to storms that occurred in 2017 and 2018, respectively. Under the December 5, 2017, Washington Commission order regarding PSE’s GRC, the following changes to PSE’s storm deferral mechanism were approved: (i) the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018; and (ii) qualifying events where the total qualifying cost is less than $0.5 million will not qualify for deferral and these costs will also not count toward the $10.0 million annual cost threshold. Environmental Remediation The Company is subject to environmental laws and regulations by the federal, state and local authorities and is required to undertake certain environmental investigative and remedial efforts as a result of these laws and regulations. The Company has been named by the Environmental Protection Agency (EPA), the Washington State Department of Ecology and/or other third parties as potentially responsible at several contaminated sites and manufactured gas plant sites. In accordance with the guidance of ASC 450, “Contingencies,” the Company reviews its estimated future obligations and will record adjustments, if any, on a quarterly basis. Management believes it is probable and reasonably estimable that the impact of the potential outcomes of disputes with certain property owners and other potentially responsible parties will result in environmental remediation costs of $41.8 million for natural gas and $8.7 million for electric. The Company believes a significant portion of its past and future environmental remediation costs are recoverable from insurance companies, from third parties or from customers under a Washington Commission order. The Company is also subject to cost-sharing agreements with third parties regarding environmental remediation projects in Seattle, Washington and Bellingham, Washington. The Company has taken the lead for both projects, and as of December 31, 2019, the Company’s share of future remediation costs is estimated to be approximately $31.6 million. The Company's deferred electric environmental costs are $13.7 million and $14.1 million at December 31, 2019 and 2018, respectively, net of insurance proceeds. The Company's deferred natural gas environmental costs are $54.8 million and $62.2 million at December 31, 2019 and 2018, respectively, net of insurance proceeds. In the 2017 GRC, the Company had its third party recoveries and remediation costs incurred as of September 30, 2016, net of a portion of insurance, approved for amortization and inclusion in rates, effective December 19, 2017.

Dividend Payment Restrictions

Dividend Payment Restrictions	12 Months Ended
	Dec. 31, 2019
Dividend Payment Restrictions [Abstract]
Dividend Payment Restrictions	Dividend Payment Restrictions The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s electric and natural gas mortgage indentures. At December 31, 2019, approximately $914.2 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant. Pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciation and amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3.0 to 1.0. The common equity ratio, calculated on a regulatory basis, was 48.4% at December 31, 2019, and the EBITDA to interest expense was 5.3 to 1.0 for the twelve months ended December 31, 2019. PSE’s ability to pay dividends is also limited by the terms of its credit facilities, pursuant to which PSE is not permitted to pay dividends during any Event of Default (as defined in the facilities), or if the payment of dividends would result in an Event of Default, such as failure to comply with certain financial covenants. Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission. Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than 2.0 to 1.0. Puget Energy's EBITDA to interest expense was 3.6 to 1.0 for the twelve months ended December 31, 2019. At December 31, 2019, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

Utility Plant

Utility Plant	12 Months Ended
	Dec. 31, 2019
Utility Plant [Abstract]
Utility Plant	Utility Plant The following table presents electric, natural gas and common utility plant classified by account: Puget Energy Puget Sound Energy Utility Plant Estimated Useful Life December 31, December 31, (Dollars in Thousands) (Years) 2019 2018 2019 2018 Distribution plant 20-65 $ 6,602,934 $ 6,122,739 $ 8,185,700 $ 7,722,024 Production plant 12-90 3,066,792 3,099,805 3,743,493 3,974,250 Transmission plant 43-75 1,463,288 1,442,854 1,571,186 1,550,950 General plant 5-75 698,275 682,976 731,279 718,105 Intangible plant (including capitalized software) 1 3-50 735,826 662,328 726,383 652,942 Plant acquisition adjustment N/A 242,826 242,826 282,792 282,792 Underground storage 25-60 37,511 35,404 50,963 48,874 Liquefied natural gas storage 25-60 12,628 12,628 14,498 14,498 Plant held for future use N/A 46,233 39,384 46,385 39,536 Recoverable Cushion Gas N/A 8,655 8,655 8,655 8,655 Plant not classified N/A 316,923 239,857 316,923 239,857 Finance leases, net of accumulated amortization 2 N/A 1,488 1,315 1,488 1,315 Less: accumulated provision for depreciation (3,236,240) (2,832,321) (5,682,606) (5,495,348) Subtotal $ 9,997,139 $ 9,758,450 $ 9,997,139 $ 9,758,450 Construction work in progress 591,199 550,466 591,199 550,466 Net utility plant $ 10,588,338 $ 10,308,916 $ 10,588,338 $ 10,308,916 _______________________ 1. Intangible assets include capitalized software and franchise agreements with useful lives ranging between 3-10 years and 10-50 years, respectively. 2. At December 31, 2019, and 2018, accumulated amortization of capital leases at Puget Energy and PSE was $1.0 million and $1.3 million, respectively. Jointly owned generating plant service costs are included in utility plant service cost at the Company's ownership share. The Company provides financing for its ownership interest in the jointly owned utility plants. The following tables indicate the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2019. These amounts are also included in the Utility Plant table above. The Company's share of fuel costs and operating expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income. Puget Energy Jointly Owned Generating Plants Energy Source (Fuel) Company’s Ownership Share Plant in Service at Cost Construction Work in Progress Accumulated Depreciation Colstrip Units 3 & 4 Coal 25.00% $ 323,100 $ — $ (138,827) Frederickson 1 Natural Gas 49.85 61,820 — (10,995) Jackson Prairie Natural Gas 33.34 36,837 119 (8,452) Tacoma LNG Natural Gas various — 362,684 — Puget Sound Energy Jointly Owned Generating Plants Energy Source (Fuel) Company’s Ownership Share Plant in Service at Cost Construction Work in Progress Accumulated Depreciation Colstrip Units 3 & 4 Coal 25.00% $ 582,372 $ — $ (398,099) Frederickson 1 Natural Gas 49.85 67,888 — (17,063) Jackson Prairie Natural Gas 33.34 50,963 119 (22,578) Tacoma LNG Natural Gas various — 162,820 — In June 2019, Talen, the plant operator of Colstrip 1&2, announced a plan to shut down as of December 31, 2019. The Company retired Colstrip 1&2 from Utility Plant and transferred the unrecovered plant amount of $126.5 million to regulatory assets. Consistent with the GRC settlement in 2017, monetization of the PTCs will fund the following: (i) Colstrip Community Transition Fund, (ii) unrecovered Colstrip plant and (iii) incurred decommissioning and remediation costs for Colstrip. At December 31, 2019, the unrecovered plant for Colstrip 1&2 was fully offset with PTCs. Asset Retirement Obligation The Company has recorded liabilities for steam generation sites, combustion turbine generation sites, wind generation sites, distribution and transmission poles, natural gas mains, and leased facilities where disposal is governed by ASC 410 “Asset Retirement and Environmental Obligations" (ARO). On April 17, 2015, the EPA published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCR) under the Resource Conservation and Recovery Act, Subtitle D. The CCR ruling requires the Company to perform an extensive study on the effects of coal ash on the environment and public health. The rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments. The CCR rule and two new legal agreements which include a consent decree with the Sierra Club and a settlement agreement with the Sierra Club and the National Wildlife Federation in 2016 make significant changes to the Company’s Colstrip operations and those changes were reviewed by the Company and the plant operator in 2015 and 2016. PSE had previously recognized a legal obligation in 2003 under the EPA rules to dispose of coal ash material at Colstrip. The actual ARO costs related to the CCR rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs. We will continue to gather additional data and coordinate with the plant operator to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, the Company will update the ARO obligation for these changes, which could be material. For the twelve months ended December 31, 2019, the Company reviewed the estimated remediation costs at Colstrip and increased the Colstrip ARO liability by $4.2 million for Colstrip Units 1 and 2 and $0.5 million for Colstrip Units 3 and 4. The 2019 increase to the Colstrip ARO liability are primarily due to accelerated timing of activities due to the closure of Colstrip Units 1 and 2 at the end of 2019. For the twelve months ended December 31, 2018, the company reduced the Colstrip ARO liability by $11.0 million for Colstrip Units 1 and 2, and increased $1.8 million for Colstrip Units 3 and 4. The 2018 change to the Colstrip ARO liability is primarily based on the plant site remedy report approved by the Montana Department of Environmental Quality. For the twelve months ended December 31, 2019 and 2018, the Company also recorded the Colstrip relief of liability of $12.4 million and $4.8 million, respectively. In addition, the Company recorded Tacoma LNG facility ARO liability of $3.0 million and $2.7 million for PSE and $4.3 million and $1.7 million for Puget LNG as of December 31, 2019 and December 31, 2018, respectively. The 2019 increase to the Tacoma LNG facility ARO liability is primarily due to continued construction of the plant. Puget Energy and Puget Sound Energy December 31, (Dollars in Thousands) 2019 2018 Asset retirement obligation at beginning of the period $ 182,203 $ 191,176 New asset retirement obligation recognized in the period — 501 Relief of liability (12,449) (4,750) Revisions in estimated cash flows 5,922 (10,512) Accretion expense 5,677 5,788 Asset retirement obligation at end of period 1 $ 181,353 $ 182,203 ___________________ 1. Asset retirement obligations include $4.3 million and $1.7 million for Puget LNG held only at PE as of December 31, 2019, and 2018, respectively. The Company has identified the following obligations, as defined by ASC 410, “ARO,” which were not recognized because the liability for these assets cannot be reasonably estimated at December 31, 2019: • A legal obligation under Federal Dangerous Waste Regulations to dispose of asbestos-containing material in facilities that are not scheduled for remodeling, demolition or sales. The disposal cost related to these facilities could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated; • An obligation under Washington state law to decommission the wells at the Jackson Prairie natural gas storage facility upon termination of the project. Since the project is expected to continue as long as the Northwest pipeline continues to operate, the liability cannot be reasonably estimated; • An obligation to pay its share of decommissioning costs at the end of the functional life of the major transmission lines. The major transmission lines are expected to be used indefinitely; therefore, the liability cannot be reasonably estimated; • A legal obligation under Washington state environmental laws to remove and properly dispose of certain under and above ground fuel storage tanks. The disposal costs related to under and above ground storage tanks could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated; • An obligation to pay decommissioning costs at the end of utility service franchise agreements to restore the surface of the franchise area. The decommissioning costs related to facilities at the franchise area could not be measured since the decommissioning date is indeterminable; therefore, the liability cannot be reasonably estimated; and • A potential legal obligation may arise upon the expiration of an existing FERC hydropower license if FERC orders the project to be decommissioned, although PSE contends that FERC does not have such authority. Given the value of ongoing generation, flood control and other benefits provided by these projects, PSE believes that the potential for decommissioning is remote and cannot be reasonably estimated.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2019
Long-term Debt, Unclassified [Abstract]
Long-term Debt	Long-Term Debt The following table presents outstanding long-term debt principal amounts and due dates as of 2019 and 2018: (Dollars in Thousands) December 31, Series Type Due 2019 2018 Puget Sound Energy: 5.500% Promissory Note 1 2020 $ — $ 2,412 7.150% First Mortgage Bond 2025 15,000 15,000 7.200% First Mortgage Bond 2025 2,000 2,000 7.020% Senior Secured Note 2027 300,000 300,000 7.000% Senior Secured Note 2029 100,000 100,000 3.900% Pollution Control Bond 2031 138,460 138,460 4.000% Pollution Control Bond 2031 23,400 23,400 5.483% Senior Secured Note 2035 250,000 250,000 6.724% Senior Secured Note 2036 250,000 250,000 6.274% Senior Secured Note 2037 300,000 300,000 5.757% Senior Secured Note 2039 350,000 350,000 5.795% Senior Secured Note 2040 325,000 325,000 5.764% Senior Secured Note 2040 250,000 250,000 4.434% Senior Secured Note 2041 250,000 250,000 5.638% Senior Secured Note 2041 300,000 300,000 4.300% Senior Secured Note 2045 425,000 425,000 4.223% Senior Secured Note 2048 600,000 600,000 3.250% Senior Secured Note 2049 450,000 — 4.700% Senior Secured Note 2051 45,000 45,000 * Debt discount, issuance cost and other * (37,718) (31,412) Total PSE long-term debt 4,336,142 3,894,860 Puget Energy: * Fair value adjustment of PSE long-term debt * (173,865) (182,372) * Revolving Credit Agreement 2023 24,100 11,900 * Term Loan Agreement 2021 174,000 150,000 * Term Loan Agreement 2022 210,000 — 6.500% Senior Secured Note 2 2020 — 450,000 6.000% Senior Secured Note 2021 500,000 500,000 5.625% Senior Secured Note 2022 450,000 450,000 3.650% Senior Secured Note 2025 400,000 400,000 * Debt discount, issuance cost and other * (52) (1,897) Total Puget Energy long-term debt $ 5,920,325 $ 5,672,491 ___________________ * Not Applicable. 1. 5.500% Promissory Note in the amount of $2.4 million was classified on the Balance Sheet as a current maturity of long-term debt as of August 12, 2019. 2. 6.500% Senior Secured Note in the amount of $450.0 million was classified on the Balance Sheet as a current maturity of long-term debt as of December 14,2019. PSE's senior secured notes will cease to be secured by the pledged first mortgage bonds on the date that all of the first mortgage bonds issued and outstanding under the electric or natural gas utility mortgage indenture have been retired. As of December 31, 2019, the latest maturity date of the first mortgage bonds, other than pledged first mortgage bonds, is December 22, 2025. Puget Energy Long-Term Debt On October 1, 2018, Puget Energy entered into a $150.0 million, three-year term loan agreement with a small group of banks. The agreement allows Puget Energy to borrow at either the banks' prime rate or at London Interbank Offered Rate (LIBOR) plus a spread based on credit rating. The Term Loan Agreement also includes an expansion feature, pursuant to which Puget Energy may request to increase the aggregate amount of the Term Loan Agreement, obtain incremental term loans or any combination of increases and incremental term loans in an amount up to $100.0 million. The proceeds from the term loan will be used to repay borrowings under the revolving credit facility, which carries a higher interest rate. In April 2019, Puget Energy entered into an additional $24.0 million of supplemental loans under the expansion feature of the term loan agreement with the existing lenders. All other terms and conditions of the agreement remain unchanged. The proceeds from the term loan and supplemental loans will be used to repay borrowings under the revolving credit facility, which carries a higher interest rate. On September 26, 2019, Puget Energy entered into a separate $210.0 million, three-year term loan agreement with a small group of banks. The agreement allows Puget Energy to borrow at either the banks' prime rate or LIBOR plus a spread, which will vary as those base rates fluctuate over the loan period. The Term Loan Agreement also includes an expansion feature, pursuant to which Puget Energy may request to increase the aggregate amount of the Term Loan Agreement, obtain incremental term loans or any combination of increases and incremental term loans in an amount up to $100.0 million. The proceeds from the term loan were contributed as equity to PSE and used to repay outstanding short term debt under the Company's commercial paper program. Puget Sound Energy Long-Term Debt On August 2, 2019, PSE filed a new shelf registration statement under which it may issue, up to $1.0 billion aggregate principal amount of senior notes secured by first mortgage bonds. As of the date of this report, $550.0 million was available under the registration. The shelf registration will expire in August 2022. Substantially all utility properties owned by PSE are subject to the lien of the Company’s electric and natural gas mortgage indentures. To issue additional first mortgage bonds under these indentures, PSE’s earnings available for interest must exceed certain minimums as defined in the indentures. At December 31, 2019, the earnings available for interest exceeded the required amount. On March 5, 2018, PSE commenced a tender offer and related consent solicitation to purchase any and all of the outstanding $250.0 million 6.974% Series A Enhanced Junior Subordinated Notes due June 1, 2067. Holders of the notes received $1,005 per $1,000 principal amount of notes plus accrued and unpaid interest for notes tendered and accepted by the early tender payment deadline of March 16, 2018. Holders of notes tendered after the early tender payment deadline, but prior to the tender offer expiration on April 2, 2018, were to receive the tender offer consideration of $975 per $1,000 of principal amount of the notes plus accrued but unpaid interest. A total of $193.4 million in principal amount of notes were tendered by the early payment deadline and no notes were tendered after the early payment deadline. On March 20, 2018, $194.9 million was paid to the holders of the tendered notes. This amount included the principal, early tender consideration and accrued interest up to, but not including March 20, 2018. Concurrently with the tender offer, PSE solicited consents from a majority (in principal amount) of the holders of PSE’s 6.274% Senior Notes due March 15, 2037 to terminate the replacement capital covenant granted to the holders of those notes. The termination of the covenant was necessary because it included restrictions related to repurchases, redemptions and repayments of the 6.974% Series A Enhanced Junior Subordinated Notes. PSE received consents from holders of 87.7% of the 6.274% Senior Notes and paid a consent fee totaling $2.6 million to those holders on March 19, 2018. On March 28, 2018, PSE issued a notice of redemption, effective April 27, 2018, for the remaining $56.6 million principal amount of the 6.974% Series A Enhanced Junior Subordinated Notes. The notes were redeemed at a price equal to 100% of their principal amount plus accrued and unpaid interest up to, but excluding the redemption date. On June 4, 2018, PSE issued $600.0 million of 30-year Senior Notes under its senior note indenture at an interest rate of 4.223% with a maturity date of June 15, 2048. The proceeds from the issuance were used to pay the principal and accrued interest on the Company’s $200.0 million Secured Notes that matured on June 15, 2018, outstanding commercial paper borrowings of $348.0 million and other general corporate expenses. On August 30, 2019, PSE issued $450.0 million of senior notes at an interest rate of 3.250%. The notes pay interest semi-annually and are due to mature on September 15, 2049. Proceeds from the sale of the notes were used to repay outstanding short term debt under the Company’s commercial paper program. Long-Term Debt Maturities The principal amounts of long-term debt maturities for the next five years and thereafter are as follows: (Dollars in Thousands) 2020 2021 2022 2023 2024 Thereafter Total Maturities of: PSE $ 2,412 $ — $ — $ — $ — $ 4,373,860 $ 4,376,272 Puget Energy 450,000 674,000 660,000 24,100 — 400,000 2,208,100 Total long-term debt $ 452,412 $ 674,000 $ 660,000 $ 24,100 $ — $ 4,773,860 $ 6,584,372

Liquidity Facilities and Other

Liquidity Facilities and Other Financing Arrangements	12 Months Ended
	Dec. 31, 2019
Liquidity Facilities and Other Financing Arrangements [Abstract]
Liquidity Facilities and Other Financing Arrangements	Liquidity Facilities and Other Financing Arrangements As of December 31, 2019, and 2018, PSE had $176.0 million and $379.3 million in short-term debt outstanding, respectively. Outside of the consolidation of PSE’s short-term debt, Puget Energy had no short-term debt outstanding in either year as borrowings under its credit facility are classified as long-term. PSE’s weighted-average interest rate on short-term debt, including borrowing rate, commitment fees and the amortization of debt issuance costs, during 2019 and 2018 was 3.4% and 3.4%, respectively. As of December 31, 2019, PSE and Puget Energy had several committed credit facilities that are described below. Puget Sound Energy Credit Facility In October 2017, PSE entered into a new $800.0 million credit facility which consolidates the two previous facilities into a single, smaller facility. All other features including fees, interest rate options, letter of credit, same day swingline borrowings, financial covenant and accordion feature remain substantially the same. The credit facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facility also has an expansion feature which, upon the banks' approval, would increase the total size of the facility to $1.4 billion. On September 25, 2019, with no changes to the size, terms or conditions, the maturity of the unsecured revolving credit facility was extended for one year. The facility now matures in October 2023. The credit agreement is syndicated among numerous lenders and contains usual and customary affirmative and negative covenants that, among other things, places limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreement also contains a financial covenant of total debt to total capitalization of 65% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of December 31, 2019, PSE was in compliance with all applicable covenant ratios. The credit agreement provides PSE with the ability to borrow at different interest rate options. The credit agreement allows PSE to borrow at the bank's prime rate or to make floating rate advances at the LIBOR plus a spread that is based upon PSE's credit rating. PSE must pay a commitment fee on the unused portion of the credit facility. The spreads and the commitment fee depend on PSE's credit ratings. As of the date of this report, the spread to the LIBOR is 1.25% and the commitment fee is 0.175%. As of December 31, 2019, no amounts were drawn and outstanding under PSE's credit facility. No letters of credit were outstanding and $176.0 million was outstanding under the commercial paper program. Outside of the credit agreement, PSE had a $2.8 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada. Demand Promissory Note In 2006, PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a demand promissory note (Note) pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy. Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lower of the weighted-average interest rates of PSE’s outstanding commercial paper interest rate or PSE’s senior unsecured revolving credit facility. Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. As of December 31, 2019, there was no outstanding balance under the Note. Puget Energy Credit Facility In October 2017, Puget Energy entered into a new $800.0 million credit facility to replace the existing facility. The terms and conditions, including fees, interest rate options, financial covenant, and expansion feature remain substantially the same. On September 25, 2019, with no changes to the size, terms or conditions, the maturity of the unsecured revolving credit facility was extended for one year. The facility now matures in October 2023. As of December 31, 2019, there was $24.1 million drawn and outstanding under the facility. The Puget Energy revolving senior secured credit facility also has an expansion feature which, upon the banks' approval, would increase the size of the facility to $1.3 billion. The revolving senior secured credit facility provides Puget Energy the ability to borrow at different interest rate options and includes variable fee levels. Interest rates may be based on the bank's prime rate or LIBOR plus a spread based on Puget Energy's credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of the date of this report, the spread over LIBOR was 1.75% and the commitment fee was 0.275%. The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains a maximum leverage ratio financial covenant as defined in the agreement governing the senior secured credit facility. As of December 31, 2019, Puget Energy was in compliance with all applicable covenants.

Leases

Leases	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Leases	Leases PSE has operating leases for buildings for corporate offices and operations, real estate for operating facilities and the PSE and PLNG LNG facility, land for our wind farms, and vehicles for PSE’s fleet. The finance leases are for office printers. The leases have remaining lease terms of less than a year to 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 Year Ended December 31, (Dollars in Thousands) 2019 Finance lease cost: Amortization of right-of-use asset $ 562 Interest on lease liabilities 40 Total finance lease cost $ 602 Operating lease cost 1 $ 20,639 _______________ 1. Includes $1.0 million allocated to PLNG at PE related to the Port of Tacoma lease. Supplemental cash flow information related to leases was as follows: Puget Energy and Year Ended December 31, (Dollars in Thousands) 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flow for operating leases $ 14,104 Investing cash flow for operating leases 1 6,535 Operating cash flow for finance leases 40 Financing cash flow for finance leases 562 Non-cash disclosure upon commencement of new lease Right-of-use assets obtained in exchange for new operating lease liabilities $ 5,976 Right-of-use assets obtained in exchange for new finance lease liabilities 745 Non-cash disclosure upon modification of existing lease Modification of operating lease right-of-use assets $ 14,712 _______________ 1 Includes $1.0 million allocated to PLNG at PE related to the Port of Tacoma lease. Supplemental balance sheet information related to leases was as follows: Puget Sound Energy (Dollars in Thousands) At December 31, Operating Leases 2019 Operating lease right-of-use asset $ 183,048 Operating leases liabilities current 15,862 Operating lease liabilities long-term 174,327 Total Operating lease liabilities: $ 190,189 Finance Leases Common Plant $ 1,488 Other current liabilities 669 Other deferred credits 811 Total finance lease liabilities $ 1,480 Weighted Average Remaining Lease Term Operating leases 19.24 Years Finance leases 2.76 Years Weighted Average Discount Rate Operating leases 3.59 % Finance leases 2.98 % The following tables summarize the Company’s estimated future minimum lease payments as of December 31, 2019, and December 31, 2018, respectively: Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2020 $ 22,500 $ 643 2021 22,527 508 2022 21,856 279 2023 21,415 98 2024 20,690 — Thereafter 160,410 — Total lease payments $ 269,398 $ 1,528 Less imputed interest (79,209) (48) Total net present value $ 190,189 $ 1,480 Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2019 $ 20,635 $ 495 2020 20,704 446 2021 20,630 311 2022 20,202 82 2023 19,223 — Thereafter 132,889 — Total lease payments $ 234,283 $ 1,334 PSE adopted ASU 2016-02 and elected the modified transition method practical expedient. Consequently, comparative period disclosures are presented in accordance with ASC 840. For further details see Note 2, "New Accounting Pronouncements" to the consolidated financial statements included in Item 8 of this report. Operating lease expense, which includes both cancellable and non-cancellable leases, net of sublease receipts are presented in the following table. (Dollars in Thousands) Operating Lease Expense Year Ended December 31, 2018 $ 34,093 2017 35,198

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Accounting for Derivative Instruments and Hedging Activities	Accounting for Derivative Instruments and Hedging Activities PSE employs various energy portfolio optimization strategies, but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the PCA. Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility in costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. PSE's hedging strategy includes a risk-responsive component for the core natural gas portfolio, which utilizes quantitative risk-based measures with defined objectives to balance both portfolio risk and hedge costs. PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. Currently, the Company does not apply cash flow hedge accounting, and therefore records all mark-to-market gains or losses through earnings. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program, and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. The following table presents the volumes, fair values and classification of the Company's derivative instruments recorded on the balance sheets: Puget Energy and Year Ended December 31, (Dollars in Thousands) Volumes (millions) Assets 1 Liabilities² 2019 2018 2019 2018 2019 2018 Electric portfolio derivatives * * $ 19,933 $ 33,287 $ 17,504 $ 27,284 Natural gas derivatives (MMBtus) 3 316 337 11,375 15,732 8,617 30,472 Total derivative contracts $ 31,308 $ 49,019 $ 26,121 $ 57,756 Current 23,626 46,507 13,428 46,661 Long-term 7,682 2,512 12,693 11,095 Total derivative contracts $ 31,308 $ 49,019 $ 26,121 $ 57,756 __________ 1. Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments. 2. Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments. 3. All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 229.3 million One Million British Thermal Units (MMBtus) and purchased electricity of 10.4 million megawatt hours (MWhs) at December 31, 2019, and 194.8 million MMBtus and 6.6 million MWhs at December 31, 2018. It is the Company's policy to record all derivative transactions on a gross basis at the contract level without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements, which standardize physical power contracts; International Swaps and Derivatives Association (ISDA) agreements, which standardize financial natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical natural gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as the right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount. For further details regarding the fair value of derivative instruments, see Note 11, "Fair Value Measurements", to the consolidated financial statements included in Item 8 of this report. The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities: Puget Energy and December 31, 2019 (Dollars in Thousands) Gross Amount Recognized in the Consolidated Balance Sheet 1 Gross Amounts Offset in the Consolidated Balance Sheet Net of Amounts Presented in the Consolidated Balance Sheet Gross Amounts Not Offset in the Consolidated Balance Sheet Commodity Contracts 2 Cash Collateral Received/Pledged Net Amount Assets: Energy derivative contracts $ 31,308 $ — $ 31,308 $ (14,922) $ — $ 16,386 Liabilities: Energy derivative contracts 26,121 — 26,121 (14,922) 2,000 13,199 Puget Energy and December 31, 2018 (Dollars in Thousands) Gross Amount Recognized 1 Gross Amounts Offset in the Consolidated Balance Sheet Net of Amounts Presented in the Consolidated Balance Sheet Gross Amounts Not Offset in the Consolidated Balance Sheet Commodity Contracts 2 Cash Collateral Received/Pledged Net Amount Assets Energy Derivative Contracts $ 49,019 $ — $ 49,019 $ (25,388) $ — $ 23,631 Liabilities Energy Derivative Contracts 57,756 — 57,756 (25,388) — 32,368 __________ 1. All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of set-off. 2. Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments. The following tables present the effect and locations of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income: Puget Energy and Year Ended December 31, (Dollars in Thousands) Location 2019 2018 2017 Interest rate contracts 1 : Non-hedged interest rate swap (expense) income $ — $ — $ 28 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 16,970 23,186 (32,492) Realized Electric generation fuel 10,828 26,222 (23,195) Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net (20,544) 18,476 1,702 Realized Purchased electricity 48,686 12,240 (17,873) Total gain (loss) recognized in income on derivatives $ 55,940 $ 80,124 $ (71,830) _______________ 1. Interest rate swap contracts were held at Puget Energy, and matured January 2017. The Company is exposed to credit risk primarily through buying and selling electricity and natural gas to serve its customers. Credit risk is the potential loss resulting from a counterparty's non-performance under an agreement. The Company manages credit risk with policies and procedures for, among other things, counterparty credit analysis, exposure measurement, and exposure monitoring and mitigation. The Company monitors counterparties for significant swings in credit default rates, credit rating changes by external rating agencies, ownership changes or financial distress. Where deemed appropriate, the Company may request collateral or other security from its counterparties to mitigate potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of December 31, 2019, approximately 95.0% 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 5.0% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies. The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors, such as credit default swaps and bond spreads, in the determination of reserves. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels. The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against unrealized gain (loss) positions. As of December 31, 2019, the Company was in a net liability position with the majority of counterparties, so the default factors of counterparties did not have a significant impact on reserves for the period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. PSE also transacts power futures contracts on the Intercontinental Exchange (ICE), and natural gas contracts on the ICE NGX exchange platform. Execution of contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of December 31, 2019, PSE had cash posted as collateral of $14.8 million related to contracts executed on the ICE platform. Also, as of December 31, 2019, PSE has a $1.0 million letter of credit posted as collateral as a condition of transacting on the ICE NGX exchange. PSE did not trigger any collateral requirements with any of its counterparties during the twelve months ended December 31, 2019, nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades. The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post: Puget Energy and December 31, (Dollars in Thousands) 2019 2018 Contingent Feature Fair Value 1 Liability Posted Contingent Fair Value 1 Liability Posted Contingent Credit rating 2 $ 6,110 $ — $ 6,110 $ 574 $ — $ 574 Requested credit for adequate assurance 5,253 — — 18,495 — — Forward value of contract 3 — 14,827 N/A — — — Total $ 11,363 $ 14,827 $ 6,110 $ 19,069 $ — $ 574 _______________ 1. Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable. 2. Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral. 3. Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements ASC 820 established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy categorizes the inputs into three levels with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority given to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows: Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Equity securities that are also classified as cash equivalents are considered Level 1 if there are unadjusted quoted prices in active markets for identical assets or liabilities. Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options. Level 3 - Pricing inputs include significant inputs that have little or no observability as of the reporting date. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves, contract terms and prices, credit-risk adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs as substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service. The Company considers its electric and natural gas contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes are classified as Level 3 in the fair value hierarchy. Management's assessment is based on the trading activity in real-time and forward electric and natural gas markets. Each quarter, the Company confirms the validity of pricing-service quoted prices used to value Level 2 commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter. Assets and Liabilities with Estimated Fair Value The carrying values of cash and cash equivalents, restricted cash, and short-term debt as reported on the balance sheet are reasonable estimates of their fair value due to the short-term nature of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of other investments of $51.5 million and $49.5 million at December 31, 2019, and 2018, respectively, are included in "Other property and investments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions. The fair value of the junior subordinated and long-term notes were estimated using the discounted cash flow method with U.S. Treasury yields and Company's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows: Puget Energy December 31, 2019 December 31, 2018 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Financial liabilities: Long-term debt (fixed-rate), net of discount 1 2 $ 5,512,225 $ 7,004,316 $ 5,510,591 $ 6,443,742 Long-term debt (variable-rate), net of discount 2 408,100 408,100 161,900 161,900 Total $ 5,920,325 $ 7,412,416 $ 5,672,491 $ 6,605,642 Puget Sound Energy December 31, 2019 December 31, 2018 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Financial liabilities: Long-term debt (fixed-rate), net of discount 2 2 $ 4,336,142 $ 5,571,818 $ 3,894,860 $ 4,574,611 Total $ 4,336,142 $ 5,571,818 $ 3,894,860 $ 4,574,611 _______________ 1. The carrying value includes debt issuances costs of $24.1 million and $26.1 million for December 31, 2019, and 2018, respectively, which are not included in fair value. 2. The carrying value includes debt issuances costs of $24.4 million and $24.6 million for December 31, 2019, and 2018, respectively, which are not included in fair value. Assets and Liabilities Measured at Fair Value on a Recurring Basis The following tables present the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis and the reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy and Fair Value Fair Value December 31, 2019 December 31, 2018 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric Derivative Instruments $ 19,282 $ 651 $ 19,933 $ 28,765 $ 4,522 $ 33,287 Gas Derivative Instruments 9,852 1,523 11,375 12,247 3,485 15,732 Total derivative assets $ 29,134 $ 2,174 $ 31,308 $ 41,012 $ 8,007 $ 49,019 Liabilities: Electric Derivative Instruments $ 13,474 $ 4,030 $ 17,504 $ 24,124 $ 3,160 $ 27,284 Gas Derivative Instruments 8,376 241 8,617 28,660 1,812 30,472 Total derivative liabilities $ 21,850 $ 4,271 $ 26,121 $ 52,784 $ 4,972 $ 57,756 Puget Energy and Year Ended December 31, Level 3 Roll-Forward Net Asset(Liability) 2019 2018 2017 (Dollars in Thousands) Electric Natural Gas Total Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ 1,362 $ 1,673 $ 3,035 $ 1,098 $ 1,923 $ 3,021 $ 972 $ 625 $ 1,597 Changes during period Realized and unrealized energy derivatives: Included in earnings 1 3,558 — 3,558 34,604 — 34,604 2,781 — 2,781 Included in regulatory assets / liabilities — 3,151 3,151 — 6,075 6,075 — 6,346 6,346 Settlements 2 (11,265) (4,708) (15,973) (33,067) (7,197) (40,264) (6,549) (6,372) (12,921) Transferred into Level 3 4,390 (398) 3,992 (1,987) — (1,987) 523 (553) (30) Transferred out Level 3 (1,424) 1,564 140 714 872 $ 1,586 3,371 1,877 $ 5,248 Balance at end of period $ (3,379) $ 1,282 $ (2,097) $ 1,362 $ 1,673 $ 3,035 $ 1,098 $ 1,923 $ 3,021 __________________ 1. Income Statement classification: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(3.2) million, $1.1 million and $1.5 million for the years ended December 31, 2019, 2018, and 2017, respectively. 2. The Company had no purchases, sales or issuances during the reported periods. Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company's consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company's consolidated statements of income. In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company's commodity contracts extend beyond what is considered observable as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next, and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month and reported in the Level 3 Roll-forward table above. The Company did not have any transfers between Level 2 and Level 1 during the years ended December 31, 2019, 2018, and 2017. The Company does periodically transact at locations, or market price points, that are illiquid or for which no prices are available from the independent pricing service. In such circumstances the Company uses a more liquid price point and performs a 15-month regression against the illiquid locations to serve as a proxy for market prices. Such transactions are classified as Level 3. The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs. The only significant unobservable input into the fair value measurement of the Company's Level 3 assets and liabilities is the forward price for electric and natural gas contracts. Below are the forward price ranges for the Company's commodity contracts, as of December 31, 2019: Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Electricity $ 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. At December 31, 2019, a hypothetical 10% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $2.5 million. Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis Puget Energy records the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle. ASC 360 requires long-lived assets to be tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. One such triggering event is a significant decrease in the forward market prices of power. Puget Energy evaluated the triggering event criteria in ASC 360 during 2019 and determined there was no indication of impairment of its power purchase contracts. During 2018, decreases in forward power prices and decreases in forecasted revenue and cost estimates indicated the carrying value of Puget Energy’s power purchase contracts may not have been recoverable. Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. In 2018, the following impairments were recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability as follows: Puget Energy (Dollars in Thousands) Valuation Date Contract Name Carrying Value Fair Value Write Down March 31, 2018 Wells Hydro $ 4,302 $ 2,395 $ 1,907 Total 2018 Impairments $ 1,907 The valuations were measured using a discounted cash flow, income-based valuation methodology. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates classified as Level 3 within the fair value hierarchy. A less significant input is the discount rate reflective of PSE's cost of capital used in the valuation. Below are significant unobservable inputs used in estimating the impaired long-term power purchase contracts' fair value in 2019 and 2018: Puget Energy Valuation Date Contract Unobservable Input Low High Average March 31, 2018 Wells Hydro Power prices (per MWh) $ 9.69 $ 25.30 $ 17.50 Power contract costs per quarter (in thousands) 4,126 4,126 4,126

Employee Investment Plans

Employee Investment Plans	12 Months Ended
	Dec. 31, 2019
Employee Investment Plans [Abstract]
Employee Investment Plans	Employee Investment Plans The Company's Investment Plan is a qualified employee 401(k) plan, under which employee salary deferrals and after-tax contributions are used to purchase several different investment fund options. PSE’s contributions to the employee Investment Plan were $21.7 million, $20.7 million and $19.2 million for the years 2019, 2018, and 2017, respectively. The employee Investment Plan eligibility requirements are set forth in the plan documents. Non-represented employees and United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry (UA) represented employees hired before January 1, 2014, and International Brotherhood of Electrical Workers Local Union 77 (IBEW) represented employees hired before December 12, 2014, have the following company contributions: 1. For employees under the Cash Balance retirement plan formula, PSE will match 100% of an employee's contribution up to 6.0% of plan compensation each paycheck, and will make an additional year-end contribution equal to 1.0% of base pay. 2. For employees grandfathered under the Final Average Earning retirement plan formula, PSE will match 55.0% of an employee’s contribution up to 6.0% of plan compensation each paycheck. Non-represented and UA-represented employees hired on or after January 1, 2014 along with IBEW-represented employees hired on or after December 12, 2014, will have access to the 401(k) plan. The two contribution sources from PSE are below: 1. 401(k) Company Matching: For non-represented, UA-represented and IBEW-represented employees PSE will match: 100% match on the first 3.0% of pay contributed and 50.0% match on the next 3.0% of pay contributed, such that an employee who contributes 6.0% of pay will receive 4.5% of pay in company match. Company matching will be immediately vested. 2. Company Contribution: For UA-represented employees will receive an annual company contribution of 4.0% of eligible pay placed in the Cash Balance retirement plan. Non-represented and IBEW-represented employees will receive an annual company contribution of 4.0% of eligible pay, placed either in the Investment Plan 401(k) plan or in PSE’s Cash Balance retirement plan. Non-represented and IBEW-represented employees will make a one-time election within 30 days of hire and direct that PSE put the 4.0% contribution either into the 401(k) plan or into an account in the Cash Balance retirement plan. The Company's 4.0% contribution will vest after three years of service.

Retirement Benefits

Retirement Benefits	12 Months Ended
	Dec. 31, 2019
Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Retirement Benefits	Retirement BenefitsPSE has a defined benefit pension plan (Qualified Pension Benefits) covering a substantial majority of PSE employees. Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates. Starting with January 1, 2014, all UA represented employees will receive annual pay contributions of 4.0% of eligible pay each year in the cash balance formula plan of the defined benefit pension. Starting January 1, 2014, for non-represented employees, and December 12, 2014 for employees represented by the IBEW, participants will receive annual employer contributions of 4.0% of eligible pay each year in the cash balance formula of the defined benefit pension or 401k plan account. Those employees receiving contributions in the cash balance formula plan also receive interest credits, which are at least 1.0% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, they will have annuity and lump sum options for distribution. PSE also has a non-qualified Supplemental Executive Retirement Plan (SERP) for certain key senior management employees that closed to new participants in 2019. PSE has an officer restoration benefit for new officers who join PSE or are promoted beginning in 2019, such that company contributions under PSE’s applicable tax-qualified plan, which otherwise would have been earned if not for IRS limitations, are credited to an account with the Deferred Compensation Plan. In addition to providing pension benefits, PSE provides legacy group health care and life insurance benefits (Other Benefits) for certain retired employees. These benefits are provided principally through an insurance company. The insurance premiums, paid primarily by retirees, are based on the benefits provided during the prior year. On June 11, 2019, the Welfare Benefits Committee approved the termination of 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 March 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 change in benefit obligation, change in plan assets and amounts recognized in the Statements of Financial Position for the years ended December 31, 2019, and 2018: Puget Energy and Qualified SERP Other (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Change in benefit obligation: Benefit obligation at beginning of period $ 677,643 $ 700,481 $ 55,708 $ 55,754 $ 10,636 $ 11,454 Amendments — — — 1,446 9,049 — Service cost 22,656 22,757 1,023 847 61 69 Interest cost 28,913 27,303 2,314 2,120 410 444 Curtailment Loss / (Gain) — — — — (7,486) — Actuarial loss (gain) 84,272 (29,067) 6,756 1,122 (287) (379) Benefits paid (36,740) (42,662) (2,801) (5,581) (982) (1,037) Medicare part D subsidy received — — — — 226 85 Administrative expense (2,439) (1,169) — — — — Benefit obligation at end of period $ 774,305 $ 677,643 $ 63,000 $ 55,708 $ 11,627 $ 10,636 Puget Energy and Qualified SERP Other (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Change in plan assets: Fair value of plan assets at beginning of period $ 640,242 $ 704,360 $ — $ — $ 5,960 $ 7,138 Actual return on plan assets 133,939 (38,379) — — 1,006 (395) Employer contribution 18,000 18,000 2,801 5,581 305 254 Benefits paid (36,740) (42,662) (2,801) (5,581) (982) (1,037) Administrative expense (2,399) (1,077) — — — — Fair value of plan assets at end of period $ 753,042 $ 640,242 $ — $ — $ 6,289 $ 5,960 Funded status at end of period $ (21,263) $ (37,401) $ (63,000) $ (55,708) $ (5,338) $ (4,676) Puget Energy and Qualified SERP Other (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Amounts recognized in Consolidated Balance Sheet consist of: Noncurrent assets $ — $ — $ — $ — $ — $ — Current liabilities — — (22,604) (6,249) (308) (332) Noncurrent liabilities (21,263) (37,401) (40,396) (49,459) (5,030) (4,344) Net assets (liabilities) $ (21,263) $ (37,401) $ (63,000) $ (55,708) $ (5,338) $ (4,676) Puget Energy and Qualified SERP Other (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets: Projected benefit obligation $ 774,305 $ 677,643 $ 63,000 $ 55,708 $ 11,627 $ 10,636 Accumulated benefit obligation 762,838 668,469 59,988 51,031 11,604 10,557 Fair value of plan assets 753,042 640,242 — — 6,289 5,960 The following tables summarize Puget Energy's and PSE's pension benefit amounts recognized in AOCI for the years ended December 31, 2019, and 2018: Puget Energy Qualified SERP Other (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 94,319 $ 94,929 $ 15,003 $ 9,612 $ (197) $ (2,564) Prior service cost (credit) (3,884) (5,863) 1,276 1,607 — — Total $ 90,435 $ 89,066 $ 16,279 $ 11,219 $ (197) $ (2,564) Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 217,502 $ 229,819 $ 16,473 $ 11,450 $ (364) $ (3,857) Prior service cost (credit) (3,086) (4,659) 1,276 1,609 — — Total $ 214,416 $ 225,160 $ 17,749 $ 13,059 $ (364) $ (3,857) The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, 2019, 2018, and 2017. Puget Energy Qualified SERP Other (Dollars in Thousands) 2019 2018 2017 2019 2018 2017 2019 2018 2017 Components of net periodic benefit cost: Service cost $ 22,656 $ 22,757 $ 20,081 $ 1,023 $ 847 $ 913 $ 61 $ 69 $ 72 Interest cost 28,913 27,303 28,373 2,314 2,120 2,285 410 444 500 Expected return on plan assets (50,249) (50,202) (47,784) — — — (393) (472) (461) Amortization of prior service cost (credit) (1,980) (1,980) (1,980) 331 1,580 42 — — — Amortization of net loss (gain) 1,151 2,187 — 1,365 42 1,077 (374) (335) (402) Net periodic benefit cost $ 491 $ 65 $ (1,310) $ 5,033 $ 4,589 $ 4,317 $ (296) $ (294) $ (291) Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2019 2018 2017 2019 2018 2017 2019 2018 2017 Components of net periodic benefit cost: Service cost $ 22,656 $ 22,757 $ 20,081 $ 1,023 $ 847 $ 913 $ 61 $ 69 $ 72 Interest cost 28,913 27,303 28,373 2,314 2,120 2,285 410 444 500 Expected return on plan assets (50,267) (50,240) (47,862) — — — (393) (472) (461) Amortization of prior service cost (credit) (1,573) (1,573) (1,573) 333 44 44 — — — Amortization of net loss (gain) 12,877 14,917 13,048 1,733 2,069 1,565 (562) (556) (641) Net periodic benefit cost $ 12,606 $ 13,164 $ 12,067 $ 5,403 $ 5,080 $ 4,807 $ (484) $ (515) $ (530) The following tables summarize Puget Energy's and PSE's benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, 2019, and 2018: Puget Energy Qualified SERP Other (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 541 $ 59,422 $ 6,756 $ 1,122 $ (900) $ 488 Amortization of net (loss) gain (1,151) (2,187) (1,365) (1,580) 374 335 Settlements, mergers, sales, and closures — — — (619) 2,892 — Prior service cost (credit) — — — 1,446 — — Amortization of prior service (cost) credit 1,980 1,980 (331) (42) — — Total change in other comprehensive income for year $ 1,370 $ 59,215 $ 5,060 $ 327 $ 2,366 $ 823 Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 559 $ 59,460 $ 6,756 $ 1,122 $ (900) $ 488 Amortization of net (loss) gain (12,877) (14,917) (1,733) (2,069) 562 556 Settlements, mergers, sales, and closures — — — (737) 3,832 — Prior service cost (credit) — — — 1,446 — — Amortization of prior service (cost) credit 1,573 1,573 (333) (44) — — Total change in other comprehensive income for year $ (10,745) $ 46,116 $ 4,690 $ (282) $ 3,494 $ 1,044 The estimated net (loss) gain and prior service cost (credit) for the pension plans that will be amortized from AOCI into net periodic benefit cost in 2020 by PSE include a $18.6 million net loss and a $1.6 million credit, respectively. The estimated net (loss) gain and prior service cost (credit) for the SERP that will be amortized from AOCI into net periodic benefit cost in 2020 is a $2.6 million net loss and a $0.3 million net loss, respectively. The estimated net (loss) gain and prior service cost (credit) for the other postretirement plans that will be amortized from AOCI into net periodic benefit cost in 2020 is a net loss of $0.2 million. For Puget Energy, the overall amounts expected to be amortized from AOCI into net period benefit cost in 2020 is a net loss of $8.4 million. 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, $22.6 million and $0.1 million, respectively. Assumptions In accounting for pension and other benefit obligations and costs under the plans, the following weighted-average actuarial assumptions were used by the Company: Qualified SERP Other Benefit Obligation Assumptions 2019 2018 2017 2019 2018 2017 2019 2018 2017 Discount rate 3.35 % 4.40 % 4.00 % 3.35 % 4.40 % 4.00 % 3.35 % 4.40 % 4.00 % Rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Medical trend rate 1 — — — — — — N/A 7.60 6.80 Benefit Cost Assumptions Discount rate 4.40 4.40 4.50 4.40 4.40 4.50 4.40 4.40 4.50 Return on plan assets 7.50 7.50 7.45 — — — 7.00 7.00 6.75 Rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Medical trend rate 1 — — — — — — N/A 7.60 9.50 ________________________ 1. As of December 31,2019, PSE terminated the previous group retiree medical plan and created an HRA. As a result, medical inflation is no longer applicable in accounting for the related benefit obligation. The Company has selected the expected return on plan assets based on a historical analysis of rates of return and the Company’s investment mix, market conditions, inflation and other factors. The expected rate of return is reviewed annually based on these factors. The Company’s accounting policy for calculating the market-related value of assets for the Company’s retirement plan is based on a five-year smoothing of asset gains (losses) measured from the expected return on market-related assets. This is a calculated value that recognizes changes in fair value in a systematic and rational manner over five years. The same manner of calculating market-related value is used for all classes of assets, and is applied consistently from year to year. Puget Energy’s pension and other postretirement benefits income or costs depend on several factors and assumptions, including plan design, timing and amount of cash contributions to the plan, earnings on plan assets, discount rate, expected long-term rate of return, and mortality trends. Changes in any of these factors or assumptions will affect the amount of income or expense that Puget Energy records in its financial statements in future years and its projected benefit obligation. Puget Energy has selected an expected return on plan assets based on a historical analysis of rates of return and Puget Energy’s investment mix, market conditions, inflation and other factors. As required by merger accounting rules, market-related value was reset to market value effective with the merger. The discount rates were determined by using market interest rate data and the weighted-average discount rate from Citigroup Pension Liability Index Curve. The Company also takes into account in determining the discount rate the expected changes in market interest rates and anticipated changes in the duration of the plan liabilities. Plan Benefits The expected total benefits to be paid during the next five years and the aggregate total to be paid for the five years thereafter are as follows: (Dollars in Thousands) 2020 2021 2022 2023 2024 2025-2029 Qualified Pension total benefits $ 45,000 $ 45,200 $ 46,200 $ 47,900 $ 48,800 $ 253,400 SERP Pension total benefits 22,604 1,940 5,792 3,663 6,290 21,283 Other Benefits total with Medicare Part D subsidy 843 826 972 937 901 4,053 Other Benefits total without Medicare Part D subsidy 1,055 1,007 972 937 901 4,053 Plan Assets Plan contributions and the actuarial present value of accumulated plan benefits are prepared based on certain assumptions pertaining to interest rates, inflation rates and employee demographics, all of which are subject to change. Due to uncertainties inherent in the estimations and assumptions process, changes in these estimates and assumptions in the near term may be material to the financial statements. The Company has a Retirement Plan Committee that establishes investment policies, objectives and strategies designed to balance expected return with a prudent level of risk. All changes to the investment policies are reviewed and approved by the Retirement Plan Committee prior to being implemented. The Retirement Plan Committee invests trust assets with investment managers who have historically achieved above-median long-term investment performance within the risk and asset allocation limits that have been established. Interim evaluations are routinely performed with the assistance of an outside investment consultant. To obtain the desired return needed to fund the pension benefit plans, the Retirement Plan Committee has established investment allocation percentages by asset classes as follows: Allocation Asset Class Minimum Target Maximum Domestic large cap equity 25 % 31 % 40 % Domestic small cap equity — 9 15 Non-U.S. equity 10 25 30 Fixed income 15 25 30 Real estate — — 10 Absolute return 5 10 15 Cash — — 5 Plan Fair Value Measurements ASC 715, “Compensation – Retirement Benefits” (ASC 715) directs companies to provide additional disclosures about plan assets of a defined benefit pension or other postretirement plan. The objectives of the disclosures are to disclose the following: (i) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies; (ii) major categories of plan assets; (iii) inputs and valuation techniques used to measure the fair value of plan assets; (iv) effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period; and (v) significant concentrations of risk within plan assets. ASC 820 allows the reporting entity, as a practical expedient, to measure the fair value of investments that do not have readily determinable fair values on the basis of the net asset value per share of the investment if the net asset value of the investment is calculated in a matter consistent with ASC 946, “Financial Services – Investment Companies”. The standard requires disclosures about the nature and risk of the investments and whether the investments are probable of being sold at amounts different from the net asset value per share. The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, 2019, and 2018: Recurring Fair Value Measures Recurring Fair Value Measures December 31, 2019 December 31, 2018 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual Funds $ 91,658 $ — $ 91,658 $ 103,661 $ — $ 103,661 Common Stock 224,146 — 224,146 177,949 — 177,949 Government Securities 34,916 — 34,916 — — — Corporate Bonds — — — — — — Cash and cash equivalents — 150 150 — 702 702 Subtotal $ 350,720 $ 150 $ 350,870 $ 281,610 $ 702 $ 282,312 Investments measured at NAV 1 401,668 356,586 Net (payable) receivable 505 1,345 Total assets $ 753,043 $ 640,243 ________________________ 1. In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that are measured at NAV per share (or its equivalent) are not classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV primarily consist of common/collective trust funds and two partnerships held as of December 31, 2019, and 2018. Mesirow Institutional Multi-Strategy Fund Partnership, L.P. utilizes a combination of long and short strategies through investments in investment funds. The major strategy allocations of the investment funds include (1) Investments in debt obligations of public and private entities; typically, in financial duress, and (2) Investments in equity positions on a global basis utilizing fundamental analysis. Grosvenor Institutional Partners Fund, L.P invests substantially all of the fund assets available in the Grosvenor Master Fund, a Cayman Islands exempted company which is sponsored, managed and has the same investment objective as the Partnership fund. In addition to the Master Fund, investments are made primarily in offshore investment funds, investment partnerships, and pooled investment vehicles; collectively referred to as Portfolio Funds, which generally implement "nontraditional" or "alternative" investment strategies. The following table sets forth by level, within the fair value hierarchy, the Other Benefits plan assets which consist of insurance benefits for retired employees, at fair value: Recurring Fair Value Measures Recurring Fair Value Measures December 31, 2019 December 31, 2018 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual fund 1 $ 6,201 $ — $ 6,201 $ 5,910 $ — $ 5,910 Investments measured at NAV 2 88 50 Total assets $ 6,289 $ 5,960 ________________ 1. This is a publicly traded balanced mutual fund. The fund seeks regular income, conservation of principal, and an opportunity for long-term growth of principal and income. The fair value is determined by taking the number of shares owned by the plan, and multiplying by the market price as of December 31, 2019, and 2018.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	(14) Income Taxes The details of income tax (benefit) expense are as follows: Puget Energy Year Ended December 31, (Dollars in Thousands) 2019 2018 2017 Charged to operating expenses: Current: Federal $ 9,424 $ 10,382 $ 1,127 State 164 263 17 Deferred: Federal 7,357 19,451 254,420 State 128 (4) (421) Total income tax expense $ 17,073 $ 30,092 $ 255,143 Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2019 2018 2017 Charged to operating expenses: Current: Federal $ 18,093 $ 19,283 $ 1,127 State 570 438 17 Deferred: Federal 20,485 30,979 210,842 State — — — Total income tax expense $ 39,148 $ 50,700 $ 211,986 The following reconciliation compares pre-tax book income at the federal statutory rate of 21.0% in 2019 and 2018 and 35.0% in 2017 to the actual income tax expense in the Statements of Income: Puget Energy Year Ended December 31, (Dollars in Thousands) 2019 2018 2017 Income taxes at the statutory rate $ 47,834 $ 55,800 $ 148,847 Increase (decrease): Utility plant differences 1 $ (23,025) $ (25,871) $ — AFUDC, net (4,462) (4,173) (4,506) Executive compensation 2,596 4,439 — Treasury grant amortization (7,870) (4,861) (9,537) Tax reform — — 117,185 Other–net 2,000 4,758 3,154 Total income tax expense $ 17,073 $ 30,092 $ 255,143 Effective tax rate 7.5 % 11.3 % 60.0 % Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2019 2018 2017 Income taxes at the statutory rate $ 69,735 $ 77,251 $ 185,430 Increase (decrease): Utility plant differences 1 $ (23,025) $ (25,871) $ — AFUDC, net (4,462) (4,173) (4,506) Executive Compensation 2,596 4,439 — Treasury grant amortization (7,870) (4,861) (9,537) Tax reform — — 36,328 Other–net 2,174 3,915 4,271 Total income tax expense $ 39,148 $ 50,700 $ 211,986 Effective tax rate 11.8 % 13.8 % 40.0 % _______________ 1. Utility plant differences include the reversal of excess deferred taxes using the average rate assumption method in the amount of $27.6 million and $29.8 million in 2019, and 2018, respectively. The Company’s net deferred tax liability at December 31, 2019, and 2018, is composed of amounts related to the following types of temporary differences: Puget Energy At December 31, (Dollars in Thousands) 2019 2018 Utility plant and equipment $ 1,943,730 $ 1,998,721 Other deferred tax liabilities 133,440 113,051 Subtotal deferred tax liabilities 2,077,170 2,111,772 Net operating loss carryforward (238,869) (224,885) Net regulatory liability for income taxes (946,179) (975,974) Production tax credit carryforward (67,402) (121,616) Subtotal deferred tax assets (1,252,450) (1,322,475) Total net deferred tax liabilities $ 824,720 $ 789,297 Puget Sound Energy At December 31, (Dollars in Thousands) 2019 2018 Utility plant and equipment $ 1,943,730 $ 1,998,721 Other, net deferred tax liabilities 47,774 25,880 Subtotal deferred tax liabilities 1,991,504 2,024,601 Net regulatory liability for income taxes (946,936) (976,582) Production tax credit carryforward (67,405) (121,616) Subtotal deferred tax assets (1,014,341) (1,098,198) Total net deferred tax liabilities $ 977,163 $ 926,403 The Company calculates its deferred tax assets and liabilities under ASC 740, “Income Taxes” (ASC 740). ASC 740 requires recording deferred tax balances, at the currently enacted tax rate, on assets and liabilities that are reported differently for income tax purposes than for financial reporting purposes. The utilization of deferred tax assets requires sufficient taxable income in future years. ASC 740 requires a valuation allowance on deferred tax assets when it is more likely than not that the deferred tax assets will not be realized. PSE’s PTC carryforwards expire from 2033 through 2036. Puget Energy’s net operating loss carryforwards expire from 2027 through 2037. Net operating losses generated in 2018 and thereafter have no expiration date. No valuation allowance has been provided for PTC or net operating loss carryforwards. Federal Income Tax Law Changes On December 22, 2017, President Trump signed into law legislation referred to as the TCJA. Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes significant changes to the Internal Revenue Code of 1986 (as amended, the Code), including amendments which significantly change the taxation of business entities and includes specific provisions related to regulated public utilities including PSE. The most significant change that impacts the Company included in the TCJA is the reduction in the corporate federal income tax rate from 35.0% to 21.0% and the limitation of deductibility of executive compensation. The specific provisions related to regulated public utilities in the TCJA generally allow for the continued deductibility of interest expense, the elimination of full expensing for tax purposes of certain property acquired after December 31, 2017, and continues normalization requirements for accelerated depreciation benefits. Under GAAP, specifically ASC Topic 740, Income Taxes, the tax effects of changes in tax laws must be recognized in the period in which the law is enacted and deferred tax assets and liabilities are to be re-measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. For PSE, the change in deferred taxes is recorded as either an offset to a regulatory asset or liability and is subject to approval by the Washington Commission. For Puget Energy, the change in deferred taxes is recorded as an adjustment to Puget Energy’s income tax expense, which decreased Puget Energy’s net income. Upon enactment of the TCJA, the Company re-measured its deferred tax assets and liabilities based upon the TCJA’s 21.0% percent corporate federal income tax rate. The corporate tax rate change for PSE is captured in the deferred tax balance with an offset to the regulatory liability for deferred income taxes. The balance of the regulatory deferred tax account at the beginning of 2017, before tax reform, was a $71.5 million asset. As a result of tax reform, the balance was a liability of $1,012.3 million. Since PSE is in a net regulatory liability position with respect to these income tax matters, PSE netted the regulatory asset for deferred income taxes against the regulatory liability for deferred income taxes. Under the normalization requirements continued by the TCJA, $919.8 million of the net regulatory liability related to certain accelerated tax depreciation benefits is to be reversed over the remaining lives of the related assets using ARAM. The remainder of the net regulatory liability of $91.9 million is available for PSE and the Washington Commission regulatory process to determine how the amounts will be refunded to customers. PSE requested to delay the impact of tax reform in an accounting petition which was filed with the Washington Commission on December 29, 2017. For further details regarding PSE's ERF and Accounting Petition, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report. In 2019 and 2018, the Company reversed excess deferred taxes for plant-related items using ARAM in the amount of $27.6 million and $29.8 million, respectively. The impact of the TCJA to income tax expense as of December 31, 2017, was $36.3 million of which $3.0 million relates to deferred tax balances that are not subject to regulatory treatment. In addition, $33.3 million relates to the revaluation of the deferred tax for regulatory liability on PTC balances. The regulatory liability owed to customers for PTCs, which previously reduced revenue upon generation of the PTCs, was also revalued at the new rate of 21.0%. The change in the liability owed to customers for PTCs increased revenue by $51.2 million, which increased tax expense by $17.9 million, to reverse the initial deferral. The changes in the deferred tax and the liability owed to customers for PTCs had no impact on net income. Incrementally, Puget Energy increased its tax expense by $80.9 million primarily due to the revaluation of Puget Energy's net deferred tax asset on its net operating loss carryforward. The staff of the US Securities and Exchange Commission (SEC) has recognized the complexity of reflecting the impacts of the TCJA and on December 22, 2017, issued guidance in Staff Accounting Bulletin 118 (SAB 118). The guidance clarifies accounting for income taxes under ASC 740 if information is not yet available or complete and provides for up to a one year period in which to complete the required analysis and accounting (the measurement period). The Company completed the required analysis and accounting for the effects of the TCJA's enactment and did not identify any additional adjustments required. Unrecognized Tax Benefits The Company accounts for uncertain tax positions under ASC 740, which clarifies the accounting for uncertainty in income taxes recognized in the financial statements. ASC 740 requires the use of a two-step approach for recognizing and measuring tax positions taken or expected to be taken in a tax return. First, a tax position should only be recognized when it is more likely than not, based on technical merits, that the position will be sustained upon challenge by the taxing authorities and taken by management to the court of last resort. Second, a tax position that meets the recognition threshold should be measured at the largest amount that has a greater than 50.0% likelihood of being sustained. As of December 31, 2019, and 2018, the Company had no material unrecognized tax benefits. As a result, no interest or penalties were accrued for unrecognized tax benefits during the year. The Company has open tax years from 2016 through 2019. The Company classifies interest as interest expense and penalties as other expense in the financial statements.

Litigation

Litigation	12 Months Ended
	Dec. 31, 2019
Colstrip Unit 4 [Member]
Jointly Owned Utility Plant Interests
Litigation	Litigation From time to time, the Company is involved in litigation or legislative rulemaking proceedings relating to its operations in the normal course of business. The following is a description of pending proceedings that are material to PSE’s operations: Colstrip PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in each of Colstrip Units 3 and 4. In March 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. In July 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court in September 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and Talen Energy Corporation (Talen), agreed to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana no later than July 1, 2022. Depreciation rates were updated in the GRC effective December 19, 2017, where PSE's depreciation increased for Colstrip Units 1 and 2 to recover plant costs to the expected shutdown date. Additionally, PSE has accelerated the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027. The GRC also repurposed PTCs and hydro-related treasury grants to recover unrecovered plant costs and to fund and recover decommissioning and remediation costs for Colstrip Units 1 through 4. Consistent with a June 2019 announcement, Talen permanently shut down Units 1 and 2 at the end of the year due to operational losses associated with the Units. Colstrip Units 1 and 2 were retired effective December 31, 2019. The Washington Clean Energy Transition Act requires the Washington Commission to provide recovery of the investment, decommissioning, and remediation costs associated with the facilities that are not recovered through the repurposed PTC's and hydro-related treasury grants. The full scope of decommissioning activities and costs may vary from the estimates that are available at this time. On December 10, 2019, PSE announced its intention to sell its interest in Colstrip Unit 4 to NorthWestern Energy for $1. Under this agreement, PSE would retain its obligation to fund 25% of the environmental remediation and decommissioning costs associated with Unit 4 during PSE's operation. The agreement is subject to approval by the Washington Commission and the Montana Public Service Commission. Additionally, PSE has agreed to enter into a power purchase agreement with NorthWestern Energy for 90 MW through 2025 to facilitate the transition, and sell a portion of its dedicated Colstrip transmission system, conditioned upon regulatory approval. PSE expects external parties to intervene on the contingent purchase agreement for Colstrip Unit 4. For accounting purposes, management has evaluated the applicable held for sale criteria as of December 31, 2019, and determined that these criteria were not met. As such, Unit 4 is classified as Electric Utility Plant on the balance sheet, see Note 6, "Utility Plant," to the consolidated financial statements included in Item 8 of this report. Regional Haze Rule In January 2017, the EPA published revisions to the Regional Haze Rule. Among other things, these revisions delayed new Regional Haze review from 2018 to 2021, however the end date will remain 2028. In January 2018, the EPA announced that it was reconsidering certain aspects of these revisions and PSE is unable to predict the outcome. Challenges to the 2017 Regional Haze Revision Rule are pending in abeyance in the U.S. Court of Appeals for the D.C. Circuit, pending resolution of the EPA’s reconsideration of the rule. Clean Air Act 111(d)/EPA Affordable clean Energy Rule In June 2014, the EPA issued a proposed Clean Power Plan (CPP) rule under Section 111(d) of the Clean Air Act designed to regulate GHG emissions from existing power plants. The proposed rule includes state-specific goals and guidelines for states to develop plans for meeting these goals. The EPA published a final rule in October 2015. In March 2017, then EPA Administrator, Scott Pruitt, signed a notice of withdrawal of the proposed CPP federal plan and model trading rules and, in October 2017, the EPA proposed to repeal the CPP rule. In August 2018, the EPA proposed the Affordable Clean Energy (ACE) rule, pursuant to Section 111(d) of the Clean Air Act.. The ACE rule was finalized in June 2019, and establishes emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired plants. Compliance plans under ACE are due July 2020, and compliance generally required by July 2024. PSE is evaluating the final ACE rule to determine its impact on operations pending the outcome of the proposed Colstrip Unit 4 sale to NorthWestern Energy. Washington Clean Air Rule The CAR was adopted in September 2016, in Washington State and attempts to reduce greenhouse gas emissions from “covered entities” located within Washington State. Included under the new rule are large manufacturers, petroleum producers and natural gas utilities, including PSE. The CAR sets a cap on emissions associated with covered entities, which decreases over time approximately 5.0% every three years. Entities must reduce their carbon emissions, or purchase emission reduction units (ERUs), as defined under the rule, from others. In September 2016, PSE, along with Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed a lawsuit in the U.S. District Court for the Eastern District of Washington challenging the CAR. In September 2016, the four companies filed a similar challenge to the CAR in Thurston County Superior Court. In March 2018, the Thurston County Superior Court invalidated the CAR. The Department of Ecology appealed the Superior Court decision in May 2018. As a result of the appeal, direct review to the Washington State Supreme Court was granted and oral argument was held on March 16, 2019. In January 2020, the Washington Supreme Court affirmed that CAR is not valid for “indirect emitters” meaning it does not apply to the sale of natural gas for use by customers. The court ruled, however, that the rule can be severed and is valid for direct emitters including electric utilities with permitted air emission sources, but remanded the case back to the Thurston County to determine which parts of the rule survive. Meanwhile, the federal court litigation has been held in abeyance pending resolution of the state case.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies For the year ended December 31, 2019, approximately 10.2% of the Company’s energy output was obtained at an average cost of approximately $0.033 per Kilowatt Hour (kWh) through long-term contracts with three of the Washington Public Utility Districts (PUDs) that own hydroelectric projects on the Columbia River. The purchase of power from the Columbia River projects is on a pro rata share basis under which the Company pays a proportionate share of the annual debt service, operating and maintenance costs and other expenses associated with each project, in proportion to the contractual share of power that PSE obtains from that project. In these instances, PSE’s payments are not contingent upon the projects being operable; therefore, PSE is required to make the payments even if power is not delivered. These projects are financed substantially through debt service payments and their annual costs should not vary significantly over the term of the contracts unless additional financing is required to meet the costs of major maintenance, repairs or replacements, or license requirements. The Company’s share of the costs and the output of the projects is subject to reduction due to various withdrawal rights of the PUDs and others over the contract lives. The Company's expenses under these PUD contracts were as follows for the years ended December 31, : (Dollars in Thousands) 2019 2018 2017 PUD contract costs $ 87,135 $ 80,165 $ 73,827 As of December 31, 2019, the Company purchased portions of the power output of the PUDs' projects as set forth in the following table: Company's Current Share of (Dollars in Thousands) Contract Percent of Megawatt Capacity Estimated 2020 Costs 2020 Debt Service Costs Interest included in 2020 Debt Service Costs Debt Outstanding Chelan County PUD: Rock Island Project 2031 25.0 % 156 $ 34,180 $ 11,499 $ 5,681 $ 96,956 Rocky Reach Project 2031 25.0 325 31,190 4,940 2,129 33,317 Douglas County PUD: Wells Project 1 2028 27.1 228 43,004 — — — Grant County PUD: Priest Rapids Development 2052 0.6 6 1,831 1,085 586 12,793 Wanapum Development 2052 0.6 7 1,831 1,085 586 12,793 Total 722 $ 112,036 $ 18,609 $ 8,982 $ 155,859 _______________ 1. In March 2017, PSE entered a new PPA with Douglas County PUD for Wells Project output that begins upon expiration of the existing contract on August 31, 2018, and continues through September 30, 2028. The following table summarizes the Company’s estimated payment obligations for power purchases from the Columbia River projects, electric portfolio contracts and electric wholesale market transactions. These contracts have varying terms and may include escalation and termination provisions. (Dollars in Thousands) 2020 2021 2022 2023 2024 Thereafter Total Columbia River projects $ 121,680 $ 111,125 $ 103,879 $ 103,377 $ 102,976 $ 609,912 $ 1,152,949 Electric portfolio contracts 263,940 300,795 302,838 307,888 315,593 969,383 2,460,437 Electric wholesale market transactions 188,822 24,901 3,190 — — — 216,913 Total $ 574,442 $ 436,821 $ 409,907 $ 411,265 $ 418,569 $ 1,579,295 $ 3,830,299 Total purchased power contracts provided the Company with approximately 12.5 million, 14.1 million and 14.5 million MWhs of firm energy at a cost of approximately $550.6 million, $508.2 million and $456.4 million for the years 2019, 2018, and 2017, respectively. Natural Gas Supply Obligations The Company has entered into various firm supply, transportation and storage service contracts in order to ensure adequate availability of natural gas supply for its customers and generation requirements. The Company contracts for its long-term natural gas supply on a firm basis, which means the Company has a 100% daily take obligation and the supplier has a 100% daily delivery obligation to ensure service to PSE’s customers and generation requirements. The transportation and storage contracts, which have remaining terms from 1 year to 25 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. The Company incurred demand charges for 2019 for firm transportation, storage and peaking services for its natural gas customers of $125.1 million. The Company incurred demand charges in 2019 for firm transportation and storage services for the natural gas supply for its combustion turbines in the amount of $51.2 million. The following table summarizes the Company’s obligations for future natural gas supply and demand charges through the primary terms of its existing contracts. The quantified obligations are based on the FERC and CER (Canadian Energy Regulator) currently authorized rates, which are subject to change. Natural Gas Supply and Demand Charge Obligations 2020 2021 2022 2023 2024 Thereafter Total Natural gas portfolio contracts $ 273,263 $ 196,806 $ 178,208 $ 148,165 $ 82,509 $ — $ 878,951 Firm transportation service 176,741 173,133 172,190 161,508 116,842 828,136 1,628,550 Firm storage service 8,954 4,503 3,014 853 140 213 17,677 Total $ 458,958 $ 374,442 $ 353,412 $ 310,526 $ 199,491 $ 828,349 $ 2,525,178 Service Contracts The following table summarizes the Company’s estimated obligations for service contracts through the terms of its existing contracts. Service Contract Obligations 2020 2021 2022 2023 2024 Thereafter Total Energy production service contracts $ 28,474 $ 29,219 $ 29,923 $ 30,645 $ 31,400 $ 141,817 $ 291,478 Automated meter reading system 43,971 44,849 45,526 46,218 46,926 96,149 323,639 Total $ 72,445 $ 74,068 $ 75,449 $ 76,863 $ 78,326 $ 237,966 $ 615,117 Other Commitments and Contingencies For information regarding PSE's environmental remediation obligations, see Note 4, "Regulation and Rates," to the consolidated financial statements included in Item 8 of this report.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Related Party Transactions	Related Party TransactionsThe Company identified no material related party transactions during the year ended December 31, 2019 and December 31, 2018.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Segment Information	Segment InformationPuget Energy and PSE operate one reportable segment referred to as the regulated utility segment.  Puget Energy’s regulated utility operation generates, purchases and sells electricity and purchases, transports and sells natural gas.  The service territory of PSE covers approximately 6,000 square miles in the state of Washington.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2019
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss) The following tables present the changes in the Company’s (loss) AOCI by component for the years ended December 31, 2019, 2018, and 2017, respectively: Puget Energy Net unrealized gain (loss) and prior service cost on pension plans Changes in AOCI, net of tax (Dollars in Thousands) Total Balance at December 31, 2016 $ (33,712) $ (33,712) Other comprehensive income (loss) before reclassifications 10,251 10,251 Amounts reclassified from accumulated other comprehensive income (loss), net of tax (821) (821) Net current-period other comprehensive income (loss) 9,430 9,430 Balance at December 31, 2017 $ (24,282) $ (24,282) Other comprehensive income (loss) before reclassifications (48,870) (48,870) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 1,180 1,180 Reclassification of stranded taxes to retained earnings due to tax reform (5,230) (5,230) Net current-period other comprehensive income (loss) (52,920) (52,920) Balance at December 31, 2018 $ (77,202) $ (77,202) Other comprehensive income (loss) before reclassifications (7,337) (7,337) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 390 390 Net current-period other comprehensive income (loss) (6,947) (6,947) Balance at December 31, 2019 $ (84,149) $ (84,149) Puget Sound Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on treasury interest rate swaps Changes in AOCI, net of tax (Dollars in Thousands) Total Balance at December 31, 2016 $ (140,155) $ (5,356) $ (145,511) Other comprehensive income (loss) before reclassifications 10,200 — 10,200 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 8,088 317 8,405 Net current-period other comprehensive income (loss) 18,288 317 18,605 Balance at December 31, 2017 $ (121,867) $ (5,039) $ (126,906) Other comprehensive income (loss) before reclassifications (48,802) — (48,802) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 11,772 385 12,157 Reclassification of stranded taxes to retained earnings due to tax reform (26,233) (1,100) (27,333) Net current-period other comprehensive income (loss) (63,263) (715) (63,978) Balance at December 31, 2018 $ (185,130) $ (5,754) $ (190,884) Other comprehensive income (loss) before reclassifications (8,096) — (8,096) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 10,118 385 10,503 Net current-period other comprehensive income (loss) 2,022 385 2,407 Balance at December 31, 2019 $ (183,108) $ (5,369) $ (188,477) Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2019, 2018, and 2017, respectively, are as follows: Puget Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented Amount reclassified from accumulated 2019 2018 2017 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,648 $ 1,937 $ 1,938 Amortization of net gain (loss) (a) (2,142) (3,431) (675) Total before tax $ (494) $ (1,494) $ 1,263 Tax (expense) or benefit 104 314 (442) Net of Tax (390) (1,180) 821 Total reclassification for the period Net of Tax $ (390) $ (1,180) $ 821 __________ (a) These AOCI components are included in the computation of net periodic pension cost, see Note 13, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details. Puget Sound Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented Amount reclassified from accumulated 2019 2018 2017 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,240 $ 1,529 $ 1,529 Amortization of net gain (loss) (a) (14,048) (16,430) (13,972) Total before tax $ (12,808) $ (14,901) $ (12,443) Tax (expense) or benefit 2,690 3,129 4,355 Net of tax $ (10,118) $ (11,772) $ (8,088) Net unrealized gain (loss) on treasury interest rate swaps: Interest rate contracts Interest expense (487) (487) (488) Tax (expense) or benefit 102 102 171 Net of Tax $ (385) $ (385) $ (317) Total reclassification for the period Net of Tax $ (10,503) $ (12,157) $ (8,405) ____________ (a) These AOCI components are included in the computation of net periodic pension cost, see Note 13, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.

SUPPLEMENTAL QUARTERLY FINANCIA

SUPPLEMENTAL QUARTERLY FINANCIAL DATA	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Supplemental Quarterly Financial Data	SUPPLEMENTAL QUARTERLY FINANCIAL DATA The following unaudited amounts, in the opinion of the Company, include all adjustments (consisting of normal recurring adjustments) necessary for a fair statement of the results of operations for the interim periods. Quarterly amounts vary during the year due to the seasonal nature of the utility business. Puget Energy 2019 Quarter (Unaudited; Dollars in Thousands) First Second Third Fourth Operating revenue $ 1,114,839 $ 670,930 $ 627,007 $ 988,354 Operating income 213,460 39,115 26,126 240,307 Net income (loss) 132,154 (32,952) (39,443) 150,949 2018 Quarter (Unaudited; Dollars in Thousands) First Second Third Fourth Operating revenue $ 1,038,008 $ 671,852 $ 651,464 $ 985,172 Operating income 232,785 84,091 37,297 199,885 Net income (loss) 146,897 3,642 (21,970) 107,053 Puget Sound Energy 2019 Quarter (Unaudited; Dollars in Thousands) First Second Third Fourth Operating revenue $ 1,114,839 $ 670,930 $ 627,007 $ 988,354 Operating income 214,159 39,780 26,721 241,955 Net income (loss) 147,302 (8,325) (15,257) 169,204 2018 Quarter (Unaudited; Dollars in Thousands) First Second Third Fourth Operating revenue $ 1,038,008 $ 671,852 $ 651,464 $ 985,172 Operating income 235,856 81,701 46,147 193,432 Net income (loss) 163,037 26,778 3,891 123,456

SCHEDULE I CONDENSED FINANCIAL

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY	12 Months Ended
	Dec. 31, 2019
Condensed Financial Information Disclosure [Abstract]
Schedule I: Condensed Financial Information of Puget Energy	SCHEDULE I: CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY Puget Energy Condensed Statements of Income and Comprehensive Income (Loss) (Dollars in Thousands) Year Ended December 31, 2019 2018 2017 Non-utility expense and other $ (1,495) $ (1,345) $ (1,466) Other income (deductions): Equity in earnings of subsidiary 294,724 320,122 323,568 Non-hedged interest rate swap expense — — 28 Interest income 6,643 4,273 1,039 Interest expense (111,716) (108,816) (106,072) Income tax expense (benefit) 22,552 21,388 (41,903) Net income (loss) $ 210,708 $ 235,622 $ 175,194 Comprehensive income (loss) $ 203,761 $ 182,702 $ 184,624 See accompanying notes to the condensed financial statements. Puget Energy Condensed Balance Sheets (Dollars in Thousands) December 31, 2019 2018 Assets: Investment in subsidiaries $ 4,153,618 $ 3,820,347 Other property and investments: Goodwill 1,656,513 1,656,513 Current assets: Cash 947 2,067 Receivables from affiliates 1 180,527 138,714 Total current assets 181,474 140,781 Long-term assets: Deferred income taxes 235,428 221,660 Other 2,056 2,040 Total long-term assets 237,484 223,700 Total assets $ 6,229,089 $ 5,841,341 Capitalization and liabilities: Common equity $ 4,000,299 $ 3,860,728 Long-term debt 1,752,644 1,954,205 Total capitalization 5,752,943 5,814,933 Current liabilities: Account Payable 208 260 Current maturities of long-term debt 450,000 — Interest 25,938 26,148 Total current liabilities 476,146 26,408 Commitments and contingencies (Note 16) Total capitalization and liabilities $ 6,229,089 $ 5,841,341 _______________ 1 Eliminated in consolidation. See accompanying notes to the condensed financial statements. Puget Energy Condensed Statements of Cash Flows (Dollars in Thousands) Year Ended December 31, 2019 2018 2017 Operating activities: Net cash provided by (used in) operating activities $ 68,724 $ 79,176 $ 139,005 Investing activities: Investment in subsidiaries (210,000) — (24,222) (Increase) decrease in loan to subsidiary (41,708) (59,864) (78,155) Other — — (437) Net cash provided by (used in) investing activities (251,708) (59,864) (102,814) Financing activities: Dividends paid (64,220) (77,204) (123,307) Issuance of bond 246,200 209,300 — Issuance/redemption of term-loan and other long-term debt — (150,000) 90,120 Issue costs and others (116) (92) (2,650) Net cash provided by (used in) by financing activities 181,864 (17,996) (35,837) Increase (decrease) in cash (1,120) 1,316 354 Cash at beginning of year 2,067 751 397 Cash at end of year $ 947 $ 2,067 $ 751 See accompanying notes to the condensed financial statements.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Puget Energy is an energy services holding company that owns Puget Sound Energy (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma liquefied natural gas (LNG) facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that are incurred by PSE and allocated to Puget LNG are related party transactions by nature. In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805) purchase accounting adjustments. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.
Utility Plant	Utility Plant Puget Energy and PSE capitalize, at original cost, additions to utility plant, including renewals and betterments. Costs include indirect costs such as engineering, supervision, certain taxes, pension and other employee benefits and an allowance for funds used during construction (AFUDC). Replacements of minor items of property are included in maintenance expense. When the utility plant is retired and removed from service, the original cost of the property is charged to accumulated depreciation and costs associated with removal of the property, less salvage, are charged to the cost of removal regulatory liability. Planned Major Maintenance Planned major maintenance is an activity that typically occurs when PSE overhauls or substantially upgrades various systems and equipment on a scheduled basis. Costs related to planned major maintenance are deferred and amortized to the next scheduled major maintenance. This accounting method also follows the Washington Utilities and Transportation Commission (Washington Commission) regulatory treatment related to these generating facilities. Other Property and Investments For PSE, the costs of other property and investments (i.e., non-utility) are stated at historical cost. Expenditures for refurbishment and improvements that significantly add to productive capacity or extend useful life of an asset are capitalized. Replacements of minor items are expensed on a current basis. Gains and losses on assets sold or retired, which were previously recorded in utility plant, are apportioned between regulatory assets/liabilities and earnings. However, gains and losses on assets sold or retired, not previously recorded in utility plant, are reflected in earnings.
Depreciation and Amortization	Depreciation and Amortization The Company provides for depreciation and amortization on a straight-line basis. Amortization is recorded for intangibles such as regulatory assets and liabilities, computer software and franchises. The annual depreciation provision stated as a percent of a depreciable electric utility plant was 3.4%, 3.3%, and 2.8% in 2019, 2018, and 2017, respectively; depreciable natural gas
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents consist of demand bank deposits and short-term highly liquid investments with original maturities of three months or less at the time of purchase. The carrying amounts of cash and cash equivalents are reported at cost and approximate fair value, due to the short-term maturity.
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy	Restricted Cash Restricted cash amounts are primarily represent cash posted as collateral for derivative contracts as well as funds required to be set aside for contractual obligations related to transmission and generation facilities.
Materials and Supplies	Materials and Supplies Materials and supplies are used primarily in the operation and maintenance of electric and natural gas distribution and transmission systems as well as spare parts for combustion turbines used for the generation of electricity. The Company records these items at weighted-average cost.
Fuel and Gas Inventory	Fuel and Natural Gas Inventory Fuel and natural gas inventory is used in the generation of electricity and for future sales to the Company’s natural gas customers. Fuel inventory consists of coal, diesel and natural gas used for generation. Natural gas inventory consists of natural gas and LNG held in storage for future sales. The Company records these items at the lower of cost or net realizable value method.
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities PSE accounts for its regulated operations in accordance with ASC 980, “Regulated Operations” (ASC 980). ASC 980 requires PSE to defer certain costs or losses that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. It similarly requires deferral of revenues or gains that are expected to be returned to customers in the future. Accounting under ASC 980 is appropriate as long as rates are established by or subject to approval by independent third-party regulators; rates are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that rates set at levels that will recover costs can be charged to and collected from customers. In most cases, PSE classifies regulatory assets and liabilities as long-term when amortization periods extend longer than one year. For further details regarding regulatory assets and liabilities, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report. Puget Energy recorded regulatory assets and liabilities at the time of the merger related to power purchase contracts.
Allowance for Funds Used During Construction	Allowance for Funds Used During Construction AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. The amount of AFUDC recorded in each accounting period varies depending primarily upon the level of construction work in progress and the AFUDC rate used. AFUDC is capitalized as a part of the cost of utility plant; the AFUDC debt portion is credited to interest expense, while the AFUDC equity portion is credited to other income. Cash inflow related to AFUDC does not occur until these charges are reflected in rates. The current AFUDC rate authorized by the Washington Commission for natural gas and electric utility plant additions through December 18, 2017, was 7.77%. Effective December 19, 2017, with the Washington Commission order, the new AFUDC rate authorized is 7.60%. The Washington Commission authorized the Company to calculate AFUDC using its allowed rate of return. To the extent amounts calculated using this rate exceed the AFUDC calculated rate using the Federal Energy Regulatory Commission (FERC) formula, PSE capitalizes the excess as a deferred asset, crediting other income. The deferred asset is being amortized over the average useful life of PSE’s non-project electric utility plant which is approximately 30 years.
Revenue Recognition	Revenue Recognition Operating utility revenue is recognized when the basis of services is rendered, which includes estimated unbilled revenue. Revenue from retail sales is billed based on tariff rates approved by the Washington Commission. PSE's estimate of unbilled revenue is based on a calculation using meter readings from its automated meter reading (AMR) system. The estimate calculates unbilled usage at the end of each month as the difference between the customer meter readings on the last day of the month and the last customer meter readings billed. The unbilled usage is then priced at published rates for each tariff rate schedule to estimate the unbilled revenues by customer. PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $236.5 million, $239.3 million and $257.1 million for 2019, 2018, and 2017, respectively. The Company reports the collection of such taxes on a gross basis in operation revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income. PSE's electric and natural gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, natural gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. The mechanism mitigates volatility in revenue and gross margin erosion due to weather and energy efficiency. Any differences in revenue are deferred to a regulatory asset for under recovery or regulatory liability for over recovery under alternative revenue recognition standard. Revenue is recognized under this program when deemed collectible within 24 months based on alternative revenue recognition guidance. Decoupled rate increases are effective May 1 of each year subject to a 3.0% cap of total revenue for decoupled rate schedules. Any excess revenue above 3.0% will be included in the following year's decoupled rate. The Company will be able to recognize revenue below the 3.0% cap of total revenue for decoupled rate schedules. For revenue deferrals exceeding the annual 3.0% rate cap of total revenue for decoupled rate schedules, the Company will assess the excess amount to determine its ability to be collected within 24 months. On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 general rate case (GRC) to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. The rate test which limits the amount of revenues PSE can collect in its annual filings increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The Company will not record any decoupling revenue that is expected to take longer than 24 months to collect following the end of the annual period in which the revenues would have otherwise been recognized. Once determined to be collectible within 24 months, any previously non-recognized amounts will be recognized. Revenues associated with energy costs under the power cost adjustment (PCA) mechanism and purchased gas adjustment (PGA) mechanism are excluded from the decoupling mechanism.
Allowance for Doubtful Accounts	Allowance for Doubtful Accounts Allowance for doubtful accounts are provided for electric and natural gas customer accounts based upon a historical experience rate of write-offs of energy accounts receivable along with information on future economic outlook. The allowance account is adjusted monthly for this experience rate. The allowance account is maintained until either receipt of payment or the likelihood of collection is considered remote at which time the allowance account and corresponding receivable balance are
Self Insurance	Self-Insurance PSE is self-insured for storm damage and certain environmental contamination associated with current operations occurring on PSE-owned property. In addition, PSE is required to meet a deductible for a portion of the risk associated with comprehensive liability, workers’ compensation claims and catastrophic property losses other than those which are storm related. Under the December 5, 2017, Washington Commission order regarding PSE’s GRC, the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018. Additionally, costs may only be deferred if the outage meets the Institute of Electrical and Electronics Engineers (IEEE) outage criteria for system average interruption duration index.
Federal Income Taxes	Federal Income Taxes For presentation in Puget Energy's and PSE’s separate financial statements, income taxes are allocated to the subsidiaries on the basis of separate company computations of tax, modified by allocating certain consolidated group limitations which are attributed to the separate company. Taxes payable or receivable are settled with Puget Holdings, which is the ultimate tax payer.
Natural Gas Off System Sales and Capacity Release	Natural Gas Off-System Sales and Capacity Release PSE contracts for firm natural gas supplies and holds firm transportation and storage capacity sufficient to meet the expected peak winter demand for natural gas by its firm customers. Due to the variability in weather, winter peaking consumption of natural gas by most of its customers and other factors, PSE holds contractual rights to natural gas supplies and transportation and storage capacity in excess of its average annual requirements to serve firm customers on its distribution system. For much of the year, there is excess capacity available for third-party natural gas sales, exchanges and capacity releases. PSE sells excess natural gas supplies, enters into natural gas supply exchanges with third parties outside of its distribution area and releases to third parties excess interstate natural gas pipeline capacity and natural gas storage rights on a short-term basis to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. The proceeds from such activities, net of transactional costs, are accounted for as reductions in the cost of purchased natural gas and passed on to customers through the PGA mechanism, with no direct impact on net income. As a result, PSE nets the sales revenue and associated cost of sales for these transactions in purchased natural gas.
Non-Core Gas Sales	As part of the Company’s electric operations, PSE purchases natural gas for its gas-fired generation facilities.  The projected volume of natural gas for power is relative to the price of natural gas.  Based on the market prices for natural gas, PSE may use the natural gas it has already purchased to generate power or PSE may sell the already purchased natural gas.  The net proceeds from selling natural gas, previously purchased for power generation, are accounted for in electric operating revenue and are included in the PCA mechanism.
Production Tax Credit	Production Tax Credit Production Tax Credits (PTCs) represent federal income tax incentives available to taxpayers that generate energy from qualifying renewable sources during the first ten years of operation. Before the 2017 GRC, the tax savings from these credits were intended to be refunded by PSE to its customers when monetized, used on the income tax return, through its revenue requirement as initially approved by the Washington Commission. As the Company had not generated taxable income with which to monetize the credits, they had not been refunded to customers. Amounts to be refunded have been recorded as a regulatory liability with an offsetting reduction to revenue as it was intended to be refunded through the revenue requirement. A deferred tax asset and reduction to deferred tax expense were also recorded for the regulatory liability. These entries resulted in no net income impact. In connection with the GRC settlement in 2017, the Washington Commission authorized the Company to utilize the tax savings associated with the monetization of the PTCs to fund the following: (i) Colstrip Community Transition Fund, (ii) unrecovered Colstrip plant and (iii) incurred decommissioning and remediation costs for Colstrip. As PTCs will no longer be refunded to customers through the revenue requirement, a non-cash increase to revenue and deferred tax expense will be recorded as the PTCs are monetized. These entries will result in no net income impact. As of December 31, 2019 and 2018, $67.5 million and $84.0 million of PTCs were estimated to be monetized through tax filings, respectively.
Accounting for Derivatives	Accounting for Derivatives ASC 815, "Derivatives and Hedging" (ASC 815) requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value unless the contracts qualify for an exception. PSE enters into derivative contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts and swaps. Some of PSE’s physical electric supply contracts qualify for the normal purchase normal sale (NPNS) exception to derivative accounting rules. PSE may enter into financial fixed price contracts to economically hedge the variability of certain index-based contracts. Those contracts that do not meet the NPNS exception are marked-to-market to current earnings in the statements of income, subject to deferral under ASC 980, for natural gas related derivatives due to the PGA mechanism. For additional information, see Note 10, "Accounting for Derivative Instruments and Hedging Activities" to the consolidated financial statements included in Item 8 of this report.
Fair Value Measurements of Derivatives	Fair Value Measurements of Derivatives ASC 820, “Fair Value Measurements and Disclosures” (ASC 820), defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). As permitted under ASC 820, the Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements as it believes that the approach is used by market participants for these types of assets and liabilities. Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company values derivative instruments based on daily quoted prices from an independent external pricing service. When external quoted market prices are not available for derivative contracts, the Company uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves. All derivative instruments are sensitive to market price fluctuations that can occur on a daily basis. For additional information, see Note 11, "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report.
Debt Related Costs	Debt Related Costs Debt premiums, discounts, expenses and amounts received or incurred to settle hedges are amortized over the life of the related debt for the Company. The premiums and costs associated with reacquired debt are deferred and amortized over the life of the related new issuance, in accordance with ratemaking treatment for PSE and presented net of long-term liabilities on the balance sheet.
Lessee, Leases	Leases PSE determines if an arrangement is, or contains, a lease at inception of the contract. If the arrangement is, or contains a lease, PSE assesses whether the lease is operating or financing for income statement and balance sheet classification. Operating leases are included in operating lease right-of-use (ROU) assets, operating lease current liabilities, and operating lease liabilities in our consolidated balance sheets. Finance leases are included in utility plant, other current liabilities, and other deferred credits in our consolidated balance sheets. ROU assets represent the right to use an underlying asset for the lease term, and consist of the amount of the initial measurement of the lease liability, any lease payments made to the lessor at or before the commencement date, minus any lease incentives received, and any initial direct costs incurred by the lessee. Lease liabilities represent our obligation to make lease payments arising from the lease and are measured at present value of the lease payments not yet paid, discounted using the discount rate for the lease, determined based on PSE's incremental borrowing rate, at commencement. As most of PSE's leases do not provide an implicit interest rate, PSE uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. For fleet, IT and wind farm leases, this rate is applied using a portfolio approach. The lease terms may include options to extend or terminate the lease when it is reasonably certain that PSE will exercise that option. On the statement of income, operating leases are generally accounted for under a straight-line expense model, while finance leases, which were previously referred to as capital leases, are generally accounted for under a financing model. Consistent with the previous lease guidance, however, the standard allows rate-regulated utilities to recognize expense consistent with the timing of recovery in rates.

Revenue (Tables)

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

Regulation and Rates (Tables)

Regulation and Rates (Tables)	12 Months Ended
	Dec. 31, 2019
Regulatory Assets [Line Items]
Schedule of Net Regulatory Assets and Liabilities	The net regulatory assets and liabilities at December 31, 2019, and 2018, included the following: Puget Sound Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2019 2018 Storm damage costs electric 1 to 4 years $ 121,894 $ 118,331 Chelan PUD contract initiation 11.8 years 83,875 90,964 Environmental remediation (a) 68,486 76,345 Lower Snake River 17.4 years 62,899 67,021 Decoupling deferrals and interest Less than 2 years 43,509 65,779 Baker Dam licensing operating and maintenance costs N/A 56,427 55,607 Deferred Washington Commission AFUDC 30 years 57,553 52,029 Property tax tracker Less than 2 years 22,442 45,621 Unamortized loss on reacquired debt 2 to 48 years 40,177 42,378 Colstrip 1 & 2 Regulatory Asset N/A — 37,674 Energy conservation costs (a) 25,272 30,701 Get to zero depreciation expense deferral N/A 22,148 — Advanced metering infrastructure (a) 14,845 — Generation plant major maintenance, excluding Colstrip 3 to 10 years 12,744 15,027 PGA deferral of unrealized losses on derivative instruments N/A — 14,739 White River relicensing and other costs 1 year 6,399 12,966 Mint Farm ownership and operating costs 5.3 years 10,318 12,319 PGA receivable 2 years 132,766 9,922 Snoqualmie licensing operating and maintenance costs N/A 7,442 7,407 Colstrip major maintenance 0.0 years 2,929 6,841 PCA mechanism N/A 41,745 4,735 Colstrip common property 4.4 years 3,188 3,903 Ferndale 0.0 years — 3,316 Various other regulatory assets (a) 10,474 14,583 Total PSE regulatory assets $ 847,532 $ 788,208 Deferred income taxes (d) N/A (946,936) (976,582) Cost of removal (b) (469,922) (424,727) Treasury grants 18 years (101,981) (168,884) Production tax credits (c) (85,323) (93,616) Gain on Sale Shuffleton N/A (12,483) — Microsoft special contract regulatory liability N/A (12,661) — Repurposed production tax credits N/A (23,171) — Accumulated provision for rate refunds N/A — (34,579) Total decoupling liability Less than 2 years (8,500) (13,758) Various other regulatory liabilities (a) (15,573) (10,316) Total PSE regulatory liabilities (1,676,550) (1,722,462) PSE net regulatory assets (liabilities) $ (829,018) $ (934,254) __________________ (a) Amortization periods vary depending on timing of underlying transactions. (b) The balance is dependent upon the cost of removal of underlying assets and the life of utility plant. (c) Amortize as PTCs are utilized by PSE on its tax return. (d) For additional information, see Note 14,"Income Taxes" to the consolidated financial statements included in Item 8 of this report. Puget Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2019 2018 Total PSE regulatory assets (a) $ 847,532 $ 788,208 Puget Energy acquisition adjustments: Regulatory assets related to power contracts 6 to 33 years 14,146 16,693 Total Puget Energy regulatory assets 861,678 804,901 Total PSE regulatory liabilities (a) (1,676,550) (1,722,462) Puget Energy acquisition adjustments: Deferred income taxes 757 608 Regulatory liabilities related to power contracts 6 to 33 years (156,597) (162,711) Various other regulatory liabilities Varies (1,265) (1,323) Total Puget Energy regulatory liabilities (1,833,655) (1,885,888) Puget Energy net regulatory asset (liabilities) $ (971,977) $ (1,080,987) ____________________ (a) Puget Energy’s regulatory assets and liabilities include purchase accounting adjustments under ASC 805.
Subsidiaries [Member] | Electricity [Member] | PCA Mechanism [Member]
Regulatory Assets [Line Items]
Schedule of Graduated Scale of Rate Adjustment Mechanism	Effective January 1, 2017, the following graduated scale is used in the PCA mechanism: Company’s Share Customers' Share Annual Power Cost Variability Over Under Over Under Over or Under Collected by up to $17 million 100 % 100 % — % — % Over or Under Collected by between $17 million - $40 million 35 50 65 50 Over or Under Collected beyond $40 + million 10 10 90 90

Utility Plant (Tables)

Utility Plant (Tables)	12 Months Ended
	Dec. 31, 2019
Utility Plant [Abstract]
Schedule of Utility Plant	The following table presents electric, natural gas and common utility plant classified by account: Puget Energy Puget Sound Energy Utility Plant Estimated Useful Life December 31, December 31, (Dollars in Thousands) (Years) 2019 2018 2019 2018 Distribution plant 20-65 $ 6,602,934 $ 6,122,739 $ 8,185,700 $ 7,722,024 Production plant 12-90 3,066,792 3,099,805 3,743,493 3,974,250 Transmission plant 43-75 1,463,288 1,442,854 1,571,186 1,550,950 General plant 5-75 698,275 682,976 731,279 718,105 Intangible plant (including capitalized software) 1 3-50 735,826 662,328 726,383 652,942 Plant acquisition adjustment N/A 242,826 242,826 282,792 282,792 Underground storage 25-60 37,511 35,404 50,963 48,874 Liquefied natural gas storage 25-60 12,628 12,628 14,498 14,498 Plant held for future use N/A 46,233 39,384 46,385 39,536 Recoverable Cushion Gas N/A 8,655 8,655 8,655 8,655 Plant not classified N/A 316,923 239,857 316,923 239,857 Finance leases, net of accumulated amortization 2 N/A 1,488 1,315 1,488 1,315 Less: accumulated provision for depreciation (3,236,240) (2,832,321) (5,682,606) (5,495,348) Subtotal $ 9,997,139 $ 9,758,450 $ 9,997,139 $ 9,758,450 Construction work in progress 591,199 550,466 591,199 550,466 Net utility plant $ 10,588,338 $ 10,308,916 $ 10,588,338 $ 10,308,916 _______________________ 1. Intangible assets include capitalized software and franchise agreements with useful lives ranging between 3-10 years and 10-50 years, respectively. 2. At December 31, 2019, and 2018, accumulated amortization of capital leases at Puget Energy and PSE was $1.0 million and $1.3 million, respectively.
Schedule of Jointly Owned Utility Plants	These amounts are also included in the Utility Plant table above. The Company's share of fuel costs and operating expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income. Puget Energy Jointly Owned Generating Plants Energy Source (Fuel) Company’s Ownership Share Plant in Service at Cost Construction Work in Progress Accumulated Depreciation Colstrip Units 3 & 4 Coal 25.00% $ 323,100 $ — $ (138,827) Frederickson 1 Natural Gas 49.85 61,820 — (10,995) Jackson Prairie Natural Gas 33.34 36,837 119 (8,452) Tacoma LNG Natural Gas various — 362,684 — Puget Sound Energy Jointly Owned Generating Plants Energy Source (Fuel) Company’s Ownership Share Plant in Service at Cost Construction Work in Progress Accumulated Depreciation Colstrip Units 3 & 4 Coal 25.00% $ 582,372 $ — $ (398,099) Frederickson 1 Natural Gas 49.85 67,888 — (17,063) Jackson Prairie Natural Gas 33.34 50,963 119 (22,578) Tacoma LNG Natural Gas various — 162,820 —
Schedule of Asset Retirement Obligations	Puget Energy and Puget Sound Energy December 31, (Dollars in Thousands) 2019 2018 Asset retirement obligation at beginning of the period $ 182,203 $ 191,176 New asset retirement obligation recognized in the period — 501 Relief of liability (12,449) (4,750) Revisions in estimated cash flows 5,922 (10,512) Accretion expense 5,677 5,788 Asset retirement obligation at end of period 1 $ 181,353 $ 182,203 ___________________ 1. Asset retirement obligations include $4.3 million and $1.7 million for Puget LNG held only at PE as of December 31, 2019, and 2018, respectively.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Long-term Debt, Unclassified [Abstract]
Schedule of Long-Term Debt Instruments	The following table presents outstanding long-term debt principal amounts and due dates as of 2019 and 2018: (Dollars in Thousands) December 31, Series Type Due 2019 2018 Puget Sound Energy: 5.500% Promissory Note 1 2020 $ — $ 2,412 7.150% First Mortgage Bond 2025 15,000 15,000 7.200% First Mortgage Bond 2025 2,000 2,000 7.020% Senior Secured Note 2027 300,000 300,000 7.000% Senior Secured Note 2029 100,000 100,000 3.900% Pollution Control Bond 2031 138,460 138,460 4.000% Pollution Control Bond 2031 23,400 23,400 5.483% Senior Secured Note 2035 250,000 250,000 6.724% Senior Secured Note 2036 250,000 250,000 6.274% Senior Secured Note 2037 300,000 300,000 5.757% Senior Secured Note 2039 350,000 350,000 5.795% Senior Secured Note 2040 325,000 325,000 5.764% Senior Secured Note 2040 250,000 250,000 4.434% Senior Secured Note 2041 250,000 250,000 5.638% Senior Secured Note 2041 300,000 300,000 4.300% Senior Secured Note 2045 425,000 425,000 4.223% Senior Secured Note 2048 600,000 600,000 3.250% Senior Secured Note 2049 450,000 — 4.700% Senior Secured Note 2051 45,000 45,000 * Debt discount, issuance cost and other * (37,718) (31,412) Total PSE long-term debt 4,336,142 3,894,860 Puget Energy: * Fair value adjustment of PSE long-term debt * (173,865) (182,372) * Revolving Credit Agreement 2023 24,100 11,900 * Term Loan Agreement 2021 174,000 150,000 * Term Loan Agreement 2022 210,000 — 6.500% Senior Secured Note 2 2020 — 450,000 6.000% Senior Secured Note 2021 500,000 500,000 5.625% Senior Secured Note 2022 450,000 450,000 3.650% Senior Secured Note 2025 400,000 400,000 * Debt discount, issuance cost and other * (52) (1,897) Total Puget Energy long-term debt $ 5,920,325 $ 5,672,491 ___________________ * Not Applicable. 1. 5.500% Promissory Note in the amount of $2.4 million was classified on the Balance Sheet as a current maturity of long-term debt as of August 12, 2019. 2. 6.500% Senior Secured Note in the amount of $450.0 million was classified on the Balance Sheet as a current maturity of long-term debt as of December 14,2019.
Schedule of Maturities of Long-Term Debt	The principal amounts of long-term debt maturities for the next five years and thereafter are as follows: (Dollars in Thousands) 2020 2021 2022 2023 2024 Thereafter Total Maturities of: PSE $ 2,412 $ — $ — $ — $ — $ 4,373,860 $ 4,376,272 Puget Energy 450,000 674,000 660,000 24,100 — 400,000 2,208,100 Total long-term debt $ 452,412 $ 674,000 $ 660,000 $ 24,100 $ — $ 4,773,860 $ 6,584,372

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Lessee, Lease, Description [Line Items]
Lease, Cost	The components of lease cost were as follows: Puget Energy and Year Ended December 31, (Dollars in Thousands) 2019 Finance lease cost: Amortization of right-of-use asset $ 562 Interest on lease liabilities 40 Total finance lease cost $ 602 Operating lease cost 1 $ 20,639 _______________ 1. Includes $1.0 million allocated to PLNG at PE related to the Port of Tacoma lease. Supplemental cash flow information related to leases was as follows: Puget Energy and Year Ended December 31, (Dollars in Thousands) 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flow for operating leases $ 14,104 Investing cash flow for operating leases 1 6,535 Operating cash flow for finance leases 40 Financing cash flow for finance leases 562 Non-cash disclosure upon commencement of new lease Right-of-use assets obtained in exchange for new operating lease liabilities $ 5,976 Right-of-use assets obtained in exchange for new finance lease liabilities 745 Non-cash disclosure upon modification of existing lease Modification of operating lease right-of-use assets $ 14,712 _______________ 1 Includes $1.0 million allocated to PLNG at PE related to the Port of Tacoma lease.
Balance Sheet of Leases	Supplemental balance sheet information related to leases was as follows: Puget Sound Energy (Dollars in Thousands) At December 31, Operating Leases 2019 Operating lease right-of-use asset $ 183,048 Operating leases liabilities current 15,862 Operating lease liabilities long-term 174,327 Total Operating lease liabilities: $ 190,189 Finance Leases Common Plant $ 1,488 Other current liabilities 669 Other deferred credits 811 Total finance lease liabilities $ 1,480 Weighted Average Remaining Lease Term Operating leases 19.24 Years Finance leases 2.76 Years Weighted Average Discount Rate Operating leases 3.59 % Finance leases 2.98 %
Finance Lease, Liability, Maturity	The following tables summarize the Company’s estimated future minimum lease payments as of December 31, 2019, and December 31, 2018, respectively: Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2020 $ 22,500 $ 643 2021 22,527 508 2022 21,856 279 2023 21,415 98 2024 20,690 — Thereafter 160,410 — Total lease payments $ 269,398 $ 1,528 Less imputed interest (79,209) (48) Total net present value $ 190,189 $ 1,480 Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2019 $ 20,635 $ 495 2020 20,704 446 2021 20,630 311 2022 20,202 82 2023 19,223 — Thereafter 132,889 — Total lease payments $ 234,283 $ 1,334
Lessee, Operating Lease, Liability, Maturity	The following tables summarize the Company’s estimated future minimum lease payments as of December 31, 2019, and December 31, 2018, respectively: Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2020 $ 22,500 $ 643 2021 22,527 508 2022 21,856 279 2023 21,415 98 2024 20,690 — Thereafter 160,410 — Total lease payments $ 269,398 $ 1,528 Less imputed interest (79,209) (48) Total net present value $ 190,189 $ 1,480 Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At December 31, Operating Leases Finance Leases 2019 $ 20,635 $ 495 2020 20,704 446 2021 20,630 311 2022 20,202 82 2023 19,223 — Thereafter 132,889 — Total lease payments $ 234,283 $ 1,334
Schedule of Operating Lease Expense		PSE adopted ASU 2016-02 and elected the modified transition method practical expedient. Consequently, comparative period disclosures are presented in accordance with ASC 840. For further details see Note 2, "New Accounting Pronouncements" to the consolidated financial statements included in Item 8 of this report. Operating lease expense, which includes both cancellable and non-cancellable leases, net of sublease receipts are presented in the following table. (Dollars in Thousands) Operating Lease Expense Year Ended December 31, 2018 $ 34,093 2017 35,198
Subsidiaries [Member]
Lessee, Lease, Description [Line Items]
Assets and Liabilities, Lessee	Supplemental balance sheet information related to leases was as follows: Puget Sound Energy (Dollars in Thousands) At December 31, Operating Leases 2019 Operating lease right-of-use asset $ 183,048 Operating leases liabilities current 15,862 Operating lease liabilities long-term 174,327 Total Operating lease liabilities: $ 190,189 Finance Leases Common Plant $ 1,488 Other current liabilities 669 Other deferred credits 811 Total finance lease liabilities $ 1,480 Weighted Average Remaining Lease Term Operating leases 19.24 Years Finance leases 2.76 Years Weighted Average Discount Rate Operating leases 3.59 % Finance leases 2.98 %

Accounting for Derivative Ins_2

Accounting for Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative [Line Items]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	The following table presents the volumes, fair values and classification of the Company's derivative instruments recorded on the balance sheets: Puget Energy and Year Ended December 31, (Dollars in Thousands) Volumes (millions) Assets 1 Liabilities² 2019 2018 2019 2018 2019 2018 Electric portfolio derivatives * * $ 19,933 $ 33,287 $ 17,504 $ 27,284 Natural gas derivatives (MMBtus) 3 316 337 11,375 15,732 8,617 30,472 Total derivative contracts $ 31,308 $ 49,019 $ 26,121 $ 57,756 Current 23,626 46,507 13,428 46,661 Long-term 7,682 2,512 12,693 11,095 Total derivative contracts $ 31,308 $ 49,019 $ 26,121 $ 57,756 __________ 1. Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments. 2. Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments. 3. All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 229.3 million One Million British Thermal Units (MMBtus) and purchased electricity of 10.4 million megawatt hours (MWhs) at December 31, 2019, and 194.8 million MMBtus and 6.6 million MWhs at December 31, 2018.
Offsetting Assets and Liabilities [Table Text Block]	The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities: Puget Energy and December 31, 2019 (Dollars in Thousands) Gross Amount Recognized in the Consolidated Balance Sheet 1 Gross Amounts Offset in the Consolidated Balance Sheet Net of Amounts Presented in the Consolidated Balance Sheet Gross Amounts Not Offset in the Consolidated Balance Sheet Commodity Contracts 2 Cash Collateral Received/Pledged Net Amount Assets: Energy derivative contracts $ 31,308 $ — $ 31,308 $ (14,922) $ — $ 16,386 Liabilities: Energy derivative contracts 26,121 — 26,121 (14,922) 2,000 13,199 Puget Energy and December 31, 2018 (Dollars in Thousands) Gross Amount Recognized 1 Gross Amounts Offset in the Consolidated Balance Sheet Net of Amounts Presented in the Consolidated Balance Sheet Gross Amounts Not Offset in the Consolidated Balance Sheet Commodity Contracts 2 Cash Collateral Received/Pledged Net Amount Assets Energy Derivative Contracts $ 49,019 $ — $ 49,019 $ (25,388) $ — $ 23,631 Liabilities Energy Derivative Contracts 57,756 — 57,756 (25,388) — 32,368 __________ 1. All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of set-off. 2. Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments.
Schedule of Credit Risk Related Contingent Features [Table Text Block]	The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post: Puget Energy and December 31, (Dollars in Thousands) 2019 2018 Contingent Feature Fair Value 1 Liability Posted Contingent Fair Value 1 Liability Posted Contingent Credit rating 2 $ 6,110 $ — $ 6,110 $ 574 $ — $ 574 Requested credit for adequate assurance 5,253 — — 18,495 — — Forward value of contract 3 — 14,827 N/A — — — Total $ 11,363 $ 14,827 $ 6,110 $ 19,069 $ — $ 574 _______________ 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.
Parent Company [Member]
Derivative [Line Items]
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance [Table Text Block]	The following tables present the effect and locations of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income: Puget Energy and Year Ended December 31, (Dollars in Thousands) Location 2019 2018 2017 Interest rate contracts 1 : Non-hedged interest rate swap (expense) income $ — $ — $ 28 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 16,970 23,186 (32,492) Realized Electric generation fuel 10,828 26,222 (23,195) Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net (20,544) 18,476 1,702 Realized Purchased electricity 48,686 12,240 (17,873) Total gain (loss) recognized in income on derivatives $ 55,940 $ 80,124 $ (71,830) _______________ 1. Interest rate swap contracts were held at Puget Energy, and matured January 2017.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Liabilities, Quantitative Information	The carrying values and estimated fair values were as follows: Puget Energy December 31, 2019 December 31, 2018 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Financial liabilities: Long-term debt (fixed-rate), net of discount 1 2 $ 5,512,225 $ 7,004,316 $ 5,510,591 $ 6,443,742 Long-term debt (variable-rate), net of discount 2 408,100 408,100 161,900 161,900 Total $ 5,920,325 $ 7,412,416 $ 5,672,491 $ 6,605,642 Puget Sound Energy December 31, 2019 December 31, 2018 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Financial liabilities: Long-term debt (fixed-rate), net of discount 2 2 $ 4,336,142 $ 5,571,818 $ 3,894,860 $ 4,574,611 Total $ 4,336,142 $ 5,571,818 $ 3,894,860 $ 4,574,611 _______________ 1. The carrying value includes debt issuances costs of $24.1 million and $26.1 million for December 31, 2019, and 2018, respectively, which are not included in fair value. 2. The carrying value includes debt issuances costs of $24.4 million and $24.6 million for December 31, 2019, and 2018, respectively, which are not included in fair value.
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]	Puget Energy and Year Ended December 31, Level 3 Roll-Forward Net Asset(Liability) 2019 2018 2017 (Dollars in Thousands) Electric Natural Gas Total Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ 1,362 $ 1,673 $ 3,035 $ 1,098 $ 1,923 $ 3,021 $ 972 $ 625 $ 1,597 Changes during period Realized and unrealized energy derivatives: Included in earnings 1 3,558 — 3,558 34,604 — 34,604 2,781 — 2,781 Included in regulatory assets / liabilities — 3,151 3,151 — 6,075 6,075 — 6,346 6,346 Settlements 2 (11,265) (4,708) (15,973) (33,067) (7,197) (40,264) (6,549) (6,372) (12,921) Transferred into Level 3 4,390 (398) 3,992 (1,987) — (1,987) 523 (553) (30) Transferred out Level 3 (1,424) 1,564 140 714 872 $ 1,586 3,371 1,877 $ 5,248 Balance at end of period $ (3,379) $ 1,282 $ (2,097) $ 1,362 $ 1,673 $ 3,035 $ 1,098 $ 1,923 $ 3,021 __________________ 1. Income Statement classification: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(3.2) million, $1.1 million and $1.5 million for the years ended December 31, 2019, 2018, and 2017, respectively. 2. The Company had no purchases, sales or issuances during the reported periods.
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Table Text Block]	Below are the forward price ranges for the Company's commodity contracts, as of December 31, 2019: Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Electricity $ 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. Below are significant unobservable inputs used in estimating the impaired long-term power purchase contracts' fair value in 2019 and 2018: Puget Energy Valuation Date Contract Unobservable Input Low High Average March 31, 2018 Wells Hydro Power prices (per MWh) $ 9.69 $ 25.30 $ 17.50 Power contract costs per quarter (in thousands) 4,126 4,126 4,126
Schedule of Impaired Intangible Assets [Table Text Block]	Puget Energy (Dollars in Thousands) Valuation Date Contract Name Carrying Value Fair Value Write Down March 31, 2018 Wells Hydro $ 4,302 $ 2,395 $ 1,907 Total 2018 Impairments $ 1,907
Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following tables present the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis and the reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy and Fair Value Fair Value December 31, 2019 December 31, 2018 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric Derivative Instruments $ 19,282 $ 651 $ 19,933 $ 28,765 $ 4,522 $ 33,287 Gas Derivative Instruments 9,852 1,523 11,375 12,247 3,485 15,732 Total derivative assets $ 29,134 $ 2,174 $ 31,308 $ 41,012 $ 8,007 $ 49,019 Liabilities: Electric Derivative Instruments $ 13,474 $ 4,030 $ 17,504 $ 24,124 $ 3,160 $ 27,284 Gas Derivative Instruments 8,376 241 8,617 28,660 1,812 30,472 Total derivative liabilities $ 21,850 $ 4,271 $ 26,121 $ 52,784 $ 4,972 $ 57,756

Retirement Benefits (Tables)

Retirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2019
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Schedule of Changes in Projected Benefit Obligations	The following tables summarize the Company’s change in benefit obligation, change in plan assets and amounts recognized in the Statements of Financial Position for the years ended December 31, 2019, and 2018: Puget Energy and Qualified SERP Other (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Change in benefit obligation: Benefit obligation at beginning of period $ 677,643 $ 700,481 $ 55,708 $ 55,754 $ 10,636 $ 11,454 Amendments — — — 1,446 9,049 — Service cost 22,656 22,757 1,023 847 61 69 Interest cost 28,913 27,303 2,314 2,120 410 444 Curtailment Loss / (Gain) — — — — (7,486) — Actuarial loss (gain) 84,272 (29,067) 6,756 1,122 (287) (379) Benefits paid (36,740) (42,662) (2,801) (5,581) (982) (1,037) Medicare part D subsidy received — — — — 226 85 Administrative expense (2,439) (1,169) — — — — Benefit obligation at end of period $ 774,305 $ 677,643 $ 63,000 $ 55,708 $ 11,627 $ 10,636
Schedule of Changes in Fair Value of Plan Assets	Puget Energy and Qualified SERP Other (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Change in plan assets: Fair value of plan assets at beginning of period $ 640,242 $ 704,360 $ — $ — $ 5,960 $ 7,138 Actual return on plan assets 133,939 (38,379) — — 1,006 (395) Employer contribution 18,000 18,000 2,801 5,581 305 254 Benefits paid (36,740) (42,662) (2,801) (5,581) (982) (1,037) Administrative expense (2,399) (1,077) — — — — Fair value of plan assets at end of period $ 753,042 $ 640,242 $ — $ — $ 6,289 $ 5,960 Funded status at end of period $ (21,263) $ (37,401) $ (63,000) $ (55,708) $ (5,338) $ (4,676)
Schedule of Amounts Recognized in Balance Sheet and Accumulated Other Comprehensive Income	Puget Energy and Qualified SERP Other (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Amounts recognized in Consolidated Balance Sheet consist of: Noncurrent assets $ — $ — $ — $ — $ — $ — Current liabilities — — (22,604) (6,249) (308) (332) Noncurrent liabilities (21,263) (37,401) (40,396) (49,459) (5,030) (4,344) Net assets (liabilities) $ (21,263) $ (37,401) $ (63,000) $ (55,708) $ (5,338) $ (4,676)
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets [Table Text Block]	Puget Energy and Qualified SERP Other (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets: Projected benefit obligation $ 774,305 $ 677,643 $ 63,000 $ 55,708 $ 11,627 $ 10,636 Accumulated benefit obligation 762,838 668,469 59,988 51,031 11,604 10,557 Fair value of plan assets 753,042 640,242 — — 6,289 5,960
Schedule of Net Benefit Costs	The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, 2019, 2018, and 2017. Puget Energy Qualified SERP Other (Dollars in Thousands) 2019 2018 2017 2019 2018 2017 2019 2018 2017 Components of net periodic benefit cost: Service cost $ 22,656 $ 22,757 $ 20,081 $ 1,023 $ 847 $ 913 $ 61 $ 69 $ 72 Interest cost 28,913 27,303 28,373 2,314 2,120 2,285 410 444 500 Expected return on plan assets (50,249) (50,202) (47,784) — — — (393) (472) (461) Amortization of prior service cost (credit) (1,980) (1,980) (1,980) 331 1,580 42 — — — Amortization of net loss (gain) 1,151 2,187 — 1,365 42 1,077 (374) (335) (402) Net periodic benefit cost $ 491 $ 65 $ (1,310) $ 5,033 $ 4,589 $ 4,317 $ (296) $ (294) $ (291)
Schedule of Amounts Recognized in Other Comprehensive Income (Loss)	The following tables summarize Puget Energy's and PSE's benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, 2019, and 2018: Puget Energy Qualified SERP Other (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 541 $ 59,422 $ 6,756 $ 1,122 $ (900) $ 488 Amortization of net (loss) gain (1,151) (2,187) (1,365) (1,580) 374 335 Settlements, mergers, sales, and closures — — — (619) 2,892 — Prior service cost (credit) — — — 1,446 — — Amortization of prior service (cost) credit 1,980 1,980 (331) (42) — — Total change in other comprehensive income for year $ 1,370 $ 59,215 $ 5,060 $ 327 $ 2,366 $ 823
Schedule of Assumptions Used	In accounting for pension and other benefit obligations and costs under the plans, the following weighted-average actuarial assumptions were used by the Company: Qualified SERP Other Benefit Obligation Assumptions 2019 2018 2017 2019 2018 2017 2019 2018 2017 Discount rate 3.35 % 4.40 % 4.00 % 3.35 % 4.40 % 4.00 % 3.35 % 4.40 % 4.00 % Rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Medical trend rate 1 — — — — — — N/A 7.60 6.80 Benefit Cost Assumptions Discount rate 4.40 4.40 4.50 4.40 4.40 4.50 4.40 4.40 4.50 Return on plan assets 7.50 7.50 7.45 — — — 7.00 7.00 6.75 Rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Medical trend rate 1 — — — — — — N/A 7.60 9.50
Schedule of Expected Benefit Payments	The expected total benefits to be paid during the next five years and the aggregate total to be paid for the five years thereafter are as follows: (Dollars in Thousands) 2020 2021 2022 2023 2024 2025-2029 Qualified Pension total benefits $ 45,000 $ 45,200 $ 46,200 $ 47,900 $ 48,800 $ 253,400 SERP Pension total benefits 22,604 1,940 5,792 3,663 6,290 21,283 Other Benefits total with Medicare Part D subsidy 843 826 972 937 901 4,053 Other Benefits total without Medicare Part D subsidy 1,055 1,007 972 937 901 4,053
Schedule of Allocation of Plan Assets	To obtain the desired return needed to fund the pension benefit plans, the Retirement Plan Committee has established investment allocation percentages by asset classes as follows: Allocation Asset Class Minimum Target Maximum Domestic large cap equity 25 % 31 % 40 % Domestic small cap equity — 9 15 Non-U.S. equity 10 25 30 Fixed income 15 25 30 Real estate — — 10 Absolute return 5 10 15 Cash — — 5 The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, 2019, and 2018: Recurring Fair Value Measures Recurring Fair Value Measures December 31, 2019 December 31, 2018 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual Funds $ 91,658 $ — $ 91,658 $ 103,661 $ — $ 103,661 Common Stock 224,146 — 224,146 177,949 — 177,949 Government Securities 34,916 — 34,916 — — — Corporate Bonds — — — — — — Cash and cash equivalents — 150 150 — 702 702 Subtotal $ 350,720 $ 150 $ 350,870 $ 281,610 $ 702 $ 282,312 Investments measured at NAV 1 401,668 356,586 Net (payable) receivable 505 1,345 Total assets $ 753,043 $ 640,243 ________________________ 1. In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that are measured at NAV per share (or its equivalent) are not classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV primarily consist of common/collective trust funds and two partnerships held as of December 31, 2019, and 2018. Mesirow Institutional Multi-Strategy Fund Partnership, L.P. utilizes a combination of long and short strategies through investments in investment funds. The major strategy allocations of the investment funds include (1) Investments in debt obligations of public and private entities; typically, in financial duress, and (2) Investments in equity positions on a global basis utilizing fundamental analysis. Grosvenor Institutional Partners Fund, L.P invests substantially all of the fund assets available in the Grosvenor Master Fund, a Cayman Islands exempted company which is sponsored, managed and has the same investment objective as the Partnership fund. In addition to the Master Fund, investments are made primarily in offshore investment funds, investment partnerships, and pooled investment vehicles; collectively referred to as Portfolio Funds, which generally implement "nontraditional" or "alternative" investment strategies.
Other Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Schedule of Allocation of Plan Assets	The following table sets forth by level, within the fair value hierarchy, the Other Benefits plan assets which consist of insurance benefits for retired employees, at fair value: Recurring Fair Value Measures Recurring Fair Value Measures December 31, 2019 December 31, 2018 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual fund 1 $ 6,201 $ — $ 6,201 $ 5,910 $ — $ 5,910 Investments measured at NAV 2 88 50 Total assets $ 6,289 $ 5,960 ________________ 1. This is a publicly traded balanced mutual fund. The fund seeks regular income, conservation of principal, and an opportunity for long-term growth of principal and income. The fair value is determined by taking the number of shares owned by the plan, and multiplying by the market price as of December 31, 2019, and 2018. 2. In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments are measured at NAV per share (or its equivalent) are not classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV consist of a common/collective trust fund as of December 31, 2019, and 2018.
Parent Company [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Schedule of Amounts Recognized in Balance Sheet and Accumulated Other Comprehensive Income	The following tables summarize Puget Energy's and PSE's pension benefit amounts recognized in AOCI for the years ended December 31, 2019, and 2018: Puget Energy Qualified SERP Other (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 94,319 $ 94,929 $ 15,003 $ 9,612 $ (197) $ (2,564) Prior service cost (credit) (3,884) (5,863) 1,276 1,607 — — Total $ 90,435 $ 89,066 $ 16,279 $ 11,219 $ (197) $ (2,564)
Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Schedule of Amounts Recognized in Balance Sheet and Accumulated Other Comprehensive Income	Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 217,502 $ 229,819 $ 16,473 $ 11,450 $ (364) $ (3,857) Prior service cost (credit) (3,086) (4,659) 1,276 1,609 — — Total $ 214,416 $ 225,160 $ 17,749 $ 13,059 $ (364) $ (3,857)
Schedule of Net Benefit Costs	Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2019 2018 2017 2019 2018 2017 2019 2018 2017 Components of net periodic benefit cost: Service cost $ 22,656 $ 22,757 $ 20,081 $ 1,023 $ 847 $ 913 $ 61 $ 69 $ 72 Interest cost 28,913 27,303 28,373 2,314 2,120 2,285 410 444 500 Expected return on plan assets (50,267) (50,240) (47,862) — — — (393) (472) (461) Amortization of prior service cost (credit) (1,573) (1,573) (1,573) 333 44 44 — — — Amortization of net loss (gain) 12,877 14,917 13,048 1,733 2,069 1,565 (562) (556) (641) Net periodic benefit cost $ 12,606 $ 13,164 $ 12,067 $ 5,403 $ 5,080 $ 4,807 $ (484) $ (515) $ (530)
Schedule of Amounts Recognized in Other Comprehensive Income (Loss)	Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 559 $ 59,460 $ 6,756 $ 1,122 $ (900) $ 488 Amortization of net (loss) gain (12,877) (14,917) (1,733) (2,069) 562 556 Settlements, mergers, sales, and closures — — — (737) 3,832 — Prior service cost (credit) — — — 1,446 — — Amortization of prior service (cost) credit 1,573 1,573 (333) (44) — — Total change in other comprehensive income for year $ (10,745) $ 46,116 $ 4,690 $ (282) $ 3,494 $ 1,044

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosures [Line Items]
Schedule of Components of Income Tax Expense (Benefit)	The details of income tax (benefit) expense are as follows: Puget Energy Year Ended December 31, (Dollars in Thousands) 2019 2018 2017 Charged to operating expenses: Current: Federal $ 9,424 $ 10,382 $ 1,127 State 164 263 17 Deferred: Federal 7,357 19,451 254,420 State 128 (4) (421) Total income tax expense $ 17,073 $ 30,092 $ 255,143
Schedule of Effective Income Tax Rate Reconciliation	The following reconciliation compares pre-tax book income at the federal statutory rate of 21.0% in 2019 and 2018 and 35.0% in 2017 to the actual income tax expense in the Statements of Income: Puget Energy Year Ended December 31, (Dollars in Thousands) 2019 2018 2017 Income taxes at the statutory rate $ 47,834 $ 55,800 $ 148,847 Increase (decrease): Utility plant differences 1 $ (23,025) $ (25,871) $ — AFUDC, net (4,462) (4,173) (4,506) Executive compensation 2,596 4,439 — Treasury grant amortization (7,870) (4,861) (9,537) Tax reform — — 117,185 Other–net 2,000 4,758 3,154 Total income tax expense $ 17,073 $ 30,092 $ 255,143 Effective tax rate 7.5 % 11.3 % 60.0 % Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2019 2018 2017 Income taxes at the statutory rate $ 69,735 $ 77,251 $ 185,430 Increase (decrease): Utility plant differences 1 $ (23,025) $ (25,871) $ — AFUDC, net (4,462) (4,173) (4,506) Executive Compensation 2,596 4,439 — Treasury grant amortization (7,870) (4,861) (9,537) Tax reform — — 36,328 Other–net 2,174 3,915 4,271 Total income tax expense $ 39,148 $ 50,700 $ 211,986 Effective tax rate 11.8 % 13.8 % 40.0 % _______________ 1. Utility plant differences include the reversal of excess deferred taxes using the average rate assumption method in the amount of $27.6 million and $29.8 million in 2019, and 2018, respectively.
Schedule of Deferred Tax Assets and Liabilities	The Company’s net deferred tax liability at December 31, 2019, and 2018, is composed of amounts related to the following types of temporary differences: Puget Energy At December 31, (Dollars in Thousands) 2019 2018 Utility plant and equipment $ 1,943,730 $ 1,998,721 Other deferred tax liabilities 133,440 113,051 Subtotal deferred tax liabilities 2,077,170 2,111,772 Net operating loss carryforward (238,869) (224,885) Net regulatory liability for income taxes (946,179) (975,974) Production tax credit carryforward (67,402) (121,616) Subtotal deferred tax assets (1,252,450) (1,322,475) Total net deferred tax liabilities $ 824,720 $ 789,297 Puget Sound Energy At December 31, (Dollars in Thousands) 2019 2018 Utility plant and equipment $ 1,943,730 $ 1,998,721 Other, net deferred tax liabilities 47,774 25,880 Subtotal deferred tax liabilities 1,991,504 2,024,601 Net regulatory liability for income taxes (946,936) (976,582) Production tax credit carryforward (67,405) (121,616) Subtotal deferred tax assets (1,014,341) (1,098,198) Total net deferred tax liabilities $ 977,163 $ 926,403
Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Schedule of Components of Income Tax Expense (Benefit)	Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2019 2018 2017 Charged to operating expenses: Current: Federal $ 18,093 $ 19,283 $ 1,127 State 570 438 17 Deferred: Federal 20,485 30,979 210,842 State — — — Total income tax expense $ 39,148 $ 50,700 $ 211,986

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
Long-term Purchase Commitment [Line Items]
Schedule of Long-term Contracts for Purchase of Electric Power	The Company's expenses under these PUD contracts were as follows for the years ended December 31, : (Dollars in Thousands) 2019 2018 2017 PUD contract costs $ 87,135 $ 80,165 $ 73,827 As of December 31, 2019, the Company purchased portions of the power output of the PUDs' projects as set forth in the following table: Company's Current Share of (Dollars in Thousands) Contract Percent of Megawatt Capacity Estimated 2020 Costs 2020 Debt Service Costs Interest included in 2020 Debt Service Costs Debt Outstanding Chelan County PUD: Rock Island Project 2031 25.0 % 156 $ 34,180 $ 11,499 $ 5,681 $ 96,956 Rocky Reach Project 2031 25.0 325 31,190 4,940 2,129 33,317 Douglas County PUD: Wells Project 1 2028 27.1 228 43,004 — — — Grant County PUD: Priest Rapids Development 2052 0.6 6 1,831 1,085 586 12,793 Wanapum Development 2052 0.6 7 1,831 1,085 586 12,793 Total 722 $ 112,036 $ 18,609 $ 8,982 $ 155,859 _______________ 1. In March 2017, PSE entered a new PPA with Douglas County PUD for Wells Project output that begins upon expiration of the existing contract on August 31, 2018, and continues through September 30, 2028.
Schedule of Long-term Purchase Commitments	The following table summarizes the Company’s estimated obligations for service contracts through the terms of its existing contracts. Service Contract Obligations 2020 2021 2022 2023 2024 Thereafter Total Energy production service contracts $ 28,474 $ 29,219 $ 29,923 $ 30,645 $ 31,400 $ 141,817 $ 291,478 Automated meter reading system 43,971 44,849 45,526 46,218 46,926 96,149 323,639 Total $ 72,445 $ 74,068 $ 75,449 $ 76,863 $ 78,326 $ 237,966 $ 615,117
Electricity, Purchased [Member]
Long-term Purchase Commitment [Line Items]
Schedule of Long-term Purchase Commitments	These contracts have varying terms and may include escalation and termination provisions. (Dollars in Thousands) 2020 2021 2022 2023 2024 Thereafter Total Columbia River projects $ 121,680 $ 111,125 $ 103,879 $ 103,377 $ 102,976 $ 609,912 $ 1,152,949 Electric portfolio contracts 263,940 300,795 302,838 307,888 315,593 969,383 2,460,437 Electric wholesale market transactions 188,822 24,901 3,190 — — — 216,913 Total $ 574,442 $ 436,821 $ 409,907 $ 411,265 $ 418,569 $ 1,579,295 $ 3,830,299
Natural Gas, US Regulated [Member]
Long-term Purchase Commitment [Line Items]
Schedule of Long-term Purchase Commitments	The following table summarizes the Company’s obligations for future natural gas supply and demand charges through the primary terms of its existing contracts. The quantified obligations are based on the FERC and CER (Canadian Energy Regulator) currently authorized rates, which are subject to change. Natural Gas Supply and Demand Charge Obligations 2020 2021 2022 2023 2024 Thereafter Total Natural gas portfolio contracts $ 273,263 $ 196,806 $ 178,208 $ 148,165 $ 82,509 $ — $ 878,951 Firm transportation service 176,741 173,133 172,190 161,508 116,842 828,136 1,628,550 Firm storage service 8,954 4,503 3,014 853 140 213 17,677 Total $ 458,958 $ 374,442 $ 353,412 $ 310,526 $ 199,491 $ 828,349 $ 2,525,178

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2019
Accumulated Other Comprehensive Income (Loss) [Line Items]
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	The following tables present the changes in the Company’s (loss) AOCI by component for the years ended December 31, 2019, 2018, and 2017, respectively: Puget Energy Net unrealized gain (loss) and prior service cost on pension plans Changes in AOCI, net of tax (Dollars in Thousands) Total Balance at December 31, 2016 $ (33,712) $ (33,712) Other comprehensive income (loss) before reclassifications 10,251 10,251 Amounts reclassified from accumulated other comprehensive income (loss), net of tax (821) (821) Net current-period other comprehensive income (loss) 9,430 9,430 Balance at December 31, 2017 $ (24,282) $ (24,282) Other comprehensive income (loss) before reclassifications (48,870) (48,870) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 1,180 1,180 Reclassification of stranded taxes to retained earnings due to tax reform (5,230) (5,230) Net current-period other comprehensive income (loss) (52,920) (52,920) Balance at December 31, 2018 $ (77,202) $ (77,202) Other comprehensive income (loss) before reclassifications (7,337) (7,337) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 390 390 Net current-period other comprehensive income (loss) (6,947) (6,947) Balance at December 31, 2019 $ (84,149) $ (84,149)
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2019, 2018, and 2017, respectively, are as follows: Puget Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented Amount reclassified from accumulated 2019 2018 2017 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,648 $ 1,937 $ 1,938 Amortization of net gain (loss) (a) (2,142) (3,431) (675) Total before tax $ (494) $ (1,494) $ 1,263 Tax (expense) or benefit 104 314 (442) Net of Tax (390) (1,180) 821 Total reclassification for the period Net of Tax $ (390) $ (1,180) $ 821 __________ (a) These AOCI components are included in the computation of net periodic pension cost, see Note 13, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.
Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	Puget Sound Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on treasury interest rate swaps Changes in AOCI, net of tax (Dollars in Thousands) Total Balance at December 31, 2016 $ (140,155) $ (5,356) $ (145,511) Other comprehensive income (loss) before reclassifications 10,200 — 10,200 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 8,088 317 8,405 Net current-period other comprehensive income (loss) 18,288 317 18,605 Balance at December 31, 2017 $ (121,867) $ (5,039) $ (126,906) Other comprehensive income (loss) before reclassifications (48,802) — (48,802) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 11,772 385 12,157 Reclassification of stranded taxes to retained earnings due to tax reform (26,233) (1,100) (27,333) Net current-period other comprehensive income (loss) (63,263) (715) (63,978) Balance at December 31, 2018 $ (185,130) $ (5,754) $ (190,884) Other comprehensive income (loss) before reclassifications (8,096) — (8,096) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 10,118 385 10,503 Net current-period other comprehensive income (loss) 2,022 385 2,407 Balance at December 31, 2019 $ (183,108) $ (5,369) $ (188,477)
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	Puget Sound Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented Amount reclassified from accumulated 2019 2018 2017 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,240 $ 1,529 $ 1,529 Amortization of net gain (loss) (a) (14,048) (16,430) (13,972) Total before tax $ (12,808) $ (14,901) $ (12,443) Tax (expense) or benefit 2,690 3,129 4,355 Net of tax $ (10,118) $ (11,772) $ (8,088) Net unrealized gain (loss) on treasury interest rate swaps: Interest rate contracts Interest expense (487) (487) (488) Tax (expense) or benefit 102 102 171 Net of Tax $ (385) $ (385) $ (317) Total reclassification for the period Net of Tax $ (10,503) $ (12,157) $ (8,405) ____________ (a) These AOCI components are included in the computation of net periodic pension cost, see Note 13, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.

SUPPLEMENTAL QUARTERLY FINANC_2

SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Tables)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information	Puget Energy 2019 Quarter (Unaudited; Dollars in Thousands) First Second Third Fourth Operating revenue $ 1,114,839 $ 670,930 $ 627,007 $ 988,354 Operating income 213,460 39,115 26,126 240,307 Net income (loss) 132,154 (32,952) (39,443) 150,949 2018 Quarter (Unaudited; Dollars in Thousands) First Second Third Fourth Operating revenue $ 1,038,008 $ 671,852 $ 651,464 $ 985,172 Operating income 232,785 84,091 37,297 199,885 Net income (loss) 146,897 3,642 (21,970) 107,053 Puget Sound Energy 2019 Quarter (Unaudited; Dollars in Thousands) First Second Third Fourth Operating revenue $ 1,114,839 $ 670,930 $ 627,007 $ 988,354 Operating income 214,159 39,780 26,721 241,955 Net income (loss) 147,302 (8,325) (15,257) 169,204 2018 Quarter (Unaudited; Dollars in Thousands) First Second Third Fourth Operating revenue $ 1,038,008 $ 671,852 $ 651,464 $ 985,172 Operating income 235,856 81,701 46,147 193,432 Net income (loss) 163,037 26,778 3,891 123,456

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details) $ in Thousands	Dec. 19, 2017	Dec. 18, 2017	Dec. 31, 2019USD ($)mi²	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Jan. 01, 2018USD ($)	Jan. 01, 2017USD ($)
Accounting Policies
Excise taxes collected			$ 236,500	$ 239,300	$ 257,100
Allowance for doubtful accounts			8,294	8,408
Monetized production tax credits			$ 67,500	$ 84,000
Electric Transmission
Accounting Policies
Annual depreciation provision			3.40%	3.30%	2.80%
Gas Transmission Equipment
Accounting Policies
Annual depreciation provision			2.80%	2.80%	3.40%
Common Plant
Accounting Policies
Annual depreciation provision			7.30%	7.10%	8.30%
Subsidiaries [Member]
Accounting Policies
Area of service territory (sqmi) | mi²			6,000
Allowance for doubtful accounts			$ 8,294	$ 8,408
Public Utilities, Rate Case, Deferred Storm Costs Threshold						$ 10,000	$ 8,000
Puget LNG [Member]
Accounting Policies
Jointly Owned Non-Utility Plant Share			57.00%
Construction in Progress, Gross			$ 199,900	165,600
Operating Costs and Expenses			$ 1,200	2,000	$ 300
Tacoma LNG [Member]
Accounting Policies
Jointly Owned Non-Utility Plant Share			43.00%
Construction in Progress, Gross			$ 162,800	$ 130,800
Decoupling Mechanism [Member] | Electricity, US Regulated [Member] | Subsidiaries [Member] | Maximum
Accounting Policies
Public Utilities, Approved Rate Increase (Decrease), Percentage	3.00%
Decoupling Mechanism [Member] | Natural Gas, US Regulated [Member] | Subsidiaries [Member] | Maximum
Accounting Policies
Public Utilities, Approved Rate Increase (Decrease), Percentage	5.00%	3.00%

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - AFUDC (Details)	Nov. 07, 2018	Dec. 19, 2017	Dec. 31, 2013	Dec. 31, 2019
Regulatory Assets [Line Items]
Public Utilities, Property, Plant and Equipment, Non-project Electric Utility Plant, Estimated Useful Life Average				30 years
Subsidiaries [Member]
Regulatory Assets [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities	7.49%	7.60%	7.77%

Revenue (Details)

Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenue from Contract with Customer, Including Assessed Tax	$ 3,311,090	$ 3,222,093
Regulated Operating Revenue, Other	28,718	39,829	$ 41,854
Revenues	3,401,130	3,346,496	$ 3,460,276
Electricity, US Regulated [Member]
Revenue from Contract with Customer, Including Assessed Tax	2,132,522	2,138,008
Natural Gas, US Regulated [Member]
Revenue from Contract with Customer, Including Assessed Tax	870,457	849,898
Other Revenue From Contracts with Customers [Member]
Revenue from Contract with Customer, Including Assessed Tax	308,111	234,187
Decoupling over-collection [Domain]
Regulated Operating Revenue, Other	(18,634)	(22,852)
Other Non-606 Revenue [Member]
Regulated Operating Revenue, Other	$ 108,674	$ 147,255

Regulation and Rates Net regula

Regulation and Rates Net regulatory assets and liabilities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Regulatory Assets [Line Items]
Regulatory Assets	$ 861,678,000	$ 804,901,000
Regulatory Liabilities	1,833,655,000	1,885,888,000
Deferred income tax charge
Regulatory Assets [Line Items]
Regulatory Liabilities	$ 757,000	608,000
Regulatory liabilities related to power contracts
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Min	6 years
Net Regulatory Assets, Remaining Amortization Period, Max	33 years
Regulatory Liabilities	$ 156,597,000	162,711,000
Various other regulatory liabilities
Regulatory Assets [Line Items]
Regulatory Liabilities	1,265,000	1,323,000
Net Regulatory Assets
Regulatory Assets [Line Items]
Net Regulatory Assets	(971,977,000)	(1,080,987,000)
Requlatory Assets Related to Power Contracts
Regulatory Assets [Line Items]
Regulatory Assets	$ 14,146,000	16,693,000
Net Regulatory Assets, Remaining Amortization Period, Min	6 years
Net Regulatory Assets, Remaining Amortization Period, Max	33 years
Subsidiaries [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities Reclassified from Accumulated Depreciation	$ 469,900,000	424,700,000
Subsidiaries [Member] | Deferred income tax charge
Regulatory Assets [Line Items]
Regulatory Liabilities	946,936,000	976,582,000
Subsidiaries [Member] | Cost of removal
Regulatory Assets [Line Items]
Regulatory Liabilities	$ 469,922,000	424,727,000
Subsidiaries [Member] | Treasury grants
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period	18 years
Regulatory Liabilities	$ 101,981,000	168,884,000
Subsidiaries [Member] | Production tax credits [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	85,323,000	93,616,000
Subsidiaries [Member] | Gain on Sale Shuffleton [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	12,483,000	0
Subsidiaries [Member] | Microsoft special contract [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	12,661,000	0
Subsidiaries [Member] | Repurposed production tax credits [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	23,171,000	0
Subsidiaries [Member] | Accumulated Provision for Rate Refund [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	0	34,579,000
Subsidiaries [Member] | Deferred decoupling revenue, net [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	8,500,000	13,758,000
Subsidiaries [Member] | Various other regulatory liabilities
Regulatory Assets [Line Items]
Regulatory Liabilities	15,573,000	10,316,000
Subsidiaries [Member] | Liabilities, Total
Regulatory Assets [Line Items]
Regulatory Liabilities	(1,676,550,000)	1,722,462,000
Subsidiaries [Member] | Net Regulatory Assets
Regulatory Assets [Line Items]
Net Regulatory Assets	(829,018,000)	(934,254,000)
Subsidiaries [Member] | Storm Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 121,894,000	118,331,000
Net Regulatory Assets, Remaining Amortization Period, Min	1 year
Net Regulatory Assets, Remaining Amortization Period, Max	4 years
Subsidiaries [Member] | Chelan PUD contract initiation
Regulatory Assets [Line Items]
Regulatory Assets	$ 83,875,000	90,964,000
Net Regulatory Assets, Remaining Amortization Period	11 years 9 months 18 days
Subsidiaries [Member] | Environmental remediation
Regulatory Assets [Line Items]
Regulatory Assets	$ 68,486,000	76,345,000
Subsidiaries [Member] | Lower Snake River
Regulatory Assets [Line Items]
Regulatory Assets	$ 62,899,000	67,021,000
Net Regulatory Assets, Remaining Amortization Period	17 years 4 months 24 days
Subsidiaries [Member] | Deferred decoupling revenue, net [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 43,509,000	65,779,000
Net Regulatory Assets, Remaining Amortization Period	2 years
Subsidiaries [Member] | Baker Dam Licensing Operating Maintenance Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 56,427,000	55,607,000
Subsidiaries [Member] | Deferred Washington Commission AFUDC
Regulatory Assets [Line Items]
Regulatory Assets	$ 57,553,000	52,029,000
Net Regulatory Assets, Remaining Amortization Period	30 years
Subsidiaries [Member] | Property tax tracker
Regulatory Assets [Line Items]
Regulatory Assets	$ 22,442,000	45,621,000
Net Regulatory Assets, Remaining Amortization Period	2 years
Subsidiaries [Member] | Unamortized loss on reacquired debt
Regulatory Assets [Line Items]
Regulatory Assets	$ 40,177,000	42,378,000
Net Regulatory Assets, Remaining Amortization Period, Min	2 years
Net Regulatory Assets, Remaining Amortization Period, Max	48 years
Subsidiaries [Member] | Colstrip Regulatory Asset
Regulatory Assets [Line Items]
Regulatory Assets	$ 0	37,674,000
Subsidiaries [Member] | Energy Conservation Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	25,272,000	30,701,000
Subsidiaries [Member] | GTZ depreciation expense deferral [Member]
Regulatory Assets [Line Items]
Regulatory Assets	22,148,000	0
Subsidiaries [Member] | Advanced metering infrastructure [Member]
Regulatory Assets [Line Items]
Regulatory Assets	14,845,000	0
Subsidiaries [Member] | Generation plant major maintenance [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 12,744,000	15,027,000
Net Regulatory Assets, Remaining Amortization Period, Min	3 years
Net Regulatory Assets, Remaining Amortization Period, Max	10 years
Subsidiaries [Member] | PGA deferral of unrealized losses on derivative instruments
Regulatory Assets [Line Items]
Regulatory Assets	$ 0	14,739,000
Subsidiaries [Member] | White River relicensing and other costs
Regulatory Assets [Line Items]
Regulatory Assets	$ 6,399,000	12,966,000
Net Regulatory Assets, Remaining Amortization Period	1 year
Subsidiaries [Member] | Mint Farm ownership and operating costs
Regulatory Assets [Line Items]
Regulatory Assets	$ 10,318,000	12,319,000
Net Regulatory Assets, Remaining Amortization Period	5 years 3 months 18 days
Subsidiaries [Member] | PGA receivable [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 132,766,000	9,922,000
Net Regulatory Assets, Remaining Amortization Period	2 years
Subsidiaries [Member] | Snoqualmie Licensing Operating Maintenance Costs
Regulatory Assets [Line Items]
Regulatory Assets	$ 7,442,000	7,407,000
Subsidiaries [Member] | Colstrip major maintenance [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 2,929,000	6,841,000
Net Regulatory Assets, Remaining Amortization Period	0 years
Subsidiaries [Member] | PCA Mechanism [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 41,745,000	4,735,000
Subsidiaries [Member] | Colstrip common property
Regulatory Assets [Line Items]
Regulatory Assets	$ 3,188,000	3,903,000
Net Regulatory Assets, Remaining Amortization Period	4 years 4 months 24 days
Subsidiaries [Member] | Ferndale
Regulatory Assets [Line Items]
Regulatory Assets	$ 0	3,316,000
Net Regulatory Assets, Remaining Amortization Period	0 years
Subsidiaries [Member] | Various other regulatory assets
Regulatory Assets [Line Items]
Regulatory Assets	$ 10,474,000	14,583,000
Subsidiaries [Member] | Assets, Total
Regulatory Assets [Line Items]
Regulatory Assets	$ 847,532,000	$ 788,208,000

General Rate Case Filing (Detai

General Rate Case Filing (Details) - Subsidiaries [Member] $ in Millions	Jan. 15, 2020USD ($)	Jun. 20, 2019	Nov. 07, 2018	Dec. 19, 2017USD ($)	Jan. 13, 2017	Dec. 31, 2013
Regulatory Assets [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities			7.49%	7.60%		7.77%
General Rate Case [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Return on Equity, Percentage				9.50%
Regulated Utility, After-tax Allowed Rate of Return on Net Regulatory Assets and Liabilities				6.55%
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities		7.62%
Public Utilities, Requested Return on Equity, Percentage		9.80%
Public Utilities, Approved Equity Capital Structure, Percentage				48.50%
Number of new mechanisms					2
General Rate Case [Member] | Subsequent Event [Member]
Regulatory Assets [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities	7.48%
Public Utilities, Requested Return on Equity, Percentage	9.50%
General Rate Case, Electric [Member] | Subsequent Event [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage	6.90%
General Rate Case, Natural Gas [Member] | Subsequent Event [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage	7.90%
Electricity, US Regulated [Member] | General Rate Case [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount				$ 20.2
Public Utilities, Requested Rate Increase (Decrease), Percentage		6.90%
Public Utilities, Approved Rate Increase (Decrease), Percentage				0.90%
Electricity, US Regulated [Member] | General Rate Case [Member] | Subsequent Event [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ (1.5)
Natural Gas, US Regulated [Member] | General Rate Case [Member]
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount				$ (35.5)
Public Utilities, Requested Rate Increase (Decrease), Percentage		7.90%
Public Utilities, Approved Rate Increase (Decrease), Percentage				(3.80%)

Expedited Rate Filing Rate Adju

Expedited Rate Filing Rate Adjustment (Details) - USD ($)	Mar. 01, 2019	Jan. 30, 2019	Nov. 07, 2018	May 01, 2018	Dec. 19, 2017	Dec. 31, 2013	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Regulatory Assets [Line Items]
Income tax (benefit) expense							$ 17,073,000	$ 30,092,000	$ 255,143,000
Subsidiaries [Member]
Regulatory Assets [Line Items]
Income tax (benefit) expense				$ 34,600,000			$ 39,148,000	$ 50,700,000	$ 211,986,000
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities			7.49%		7.60%	7.77%
Subsidiaries [Member] | Natural Gas, US Regulated [Member] | Expedited Rate Filing (ERF) [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 6,100,000		$ 21,700,000
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 25,900,000	$ 21,500,000
Public Utilities, Requested Rate Increase (Decrease), Percentage			2.70%
Subsidiaries [Member] | Electricity, US Regulated [Member] | Expedited Rate Filing (ERF) [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 18,900,000
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 0
Public Utilities, Requested Rate Increase (Decrease), Percentage			0.90%

Washington Commission Tax Defer

Washington Commission Tax Deferral Filing (Details) - USD ($) $ in Thousands	May 01, 2018	Dec. 31, 2019	Apr. 30, 2019	Dec. 31, 2018	Dec. 31, 2017
Regulatory Assets [Line Items]
Income tax (benefit) expense		$ 17,073		$ 30,092	$ 255,143
Subsidiaries [Member]
Regulatory Assets [Line Items]
Income tax (benefit) expense	$ 34,600	$ 39,148		$ 50,700	$ 211,986
Subsidiaries [Member] | Electricity, US Regulated [Member] | Tax Cuts and Jobs Act [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage			(3.40%)
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount			$ (72,900)
Subsidiaries [Member] | Natural Gas, US Regulated [Member] | Tax Cuts and Jobs Act [Member]
Regulatory Assets [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage			(2.70%)
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount			$ (23,600)

Decoupling Filings (Details)

Decoupling Filings (Details) - Decoupling Mechanism [Member] - USD ($) $ in Millions	Dec. 19, 2017	Dec. 18, 2017	Dec. 31, 2019
Regulatory Assets [Line Items]
Deferred Revenue, Revenue Recognized			$ 20.8
Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Contract with Customer, Liability, Revenue Recognized			$ 0.8
Subsidiaries [Member] | Electricity, US Regulated [Member] | Maximum
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage	3.00%
Subsidiaries [Member] | Natural Gas, US Regulated [Member] | Maximum
Regulatory Assets [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage	5.00%	3.00%

Schedule of Power Cost Adjustme

Schedule of Power Cost Adjustment Mechanism (Details) - Subsidiaries [Member] $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Regulatory Assets [Line Items]
Annual Power Cost Variability, Interest	$ 1	$ 0.2
Customer's share | Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount	$ 36	0
Customer's share | Range 1 | Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	0
Customer's share | Range 1 | Over-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	0
Customer's share | Range 2 | Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	0.50
Customer's share | Range 2 | Over-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	0.65
Customer's share | Range 3 | Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	0.90
Customer's share | Range 3 | Over-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	0.90
Companys share | Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount	$ 67.2	$ 3.5
Companys share | Range 1 | Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	1
Companys share | Range 1 | Over-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	1
Companys share | Range 2 | Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	0.50
Companys share | Range 2 | Over-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	0.35
Companys share | Range 3 | Under-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	0.10
Companys share | Range 3 | Over-collection
Regulatory Assets [Line Items]
Annual Power Cost Variability	0.10

Narrative (Details)

Narrative (Details) - USD ($)	Nov. 01, 2019	Apr. 10, 2019	Nov. 07, 2018	Dec. 19, 2017	Dec. 31, 2013	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2018	Jan. 01, 2017
Regulatory Assets [Line Items]
Depreciation and amortization						$ 656,323,000	$ 666,432,000	$ 481,969,000
Accrual for Environmental Loss Contingencies						31.6
Subsidiaries [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Incurred During Period						39,300,000	25,400,000
PGA payable								16,100,000
Depreciation and amortization						656,220,000	666,324,000	$ 481,955,000
Purchased gas adjustment receivable						132,800,000	9,900,000
Public Utilities, Rate Case, Deferred Storm Costs Threshold									$ 10,000,000	$ 8,000,000
Public Utilities, Rate Case, Deferred Storm Qualifying Costs									$ 0.5
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities			7.49%	7.60%	7.77%
Subsidiaries [Member] | Purchased Gas Adjustment [Member]
Regulatory Assets [Line Items]
Purchased natural gas costs, recoverable						292,000,000	289,900,000
Purchased natural gas adjustment, interest						1,300,000	6,600,000
Out of Cycle PGA	$ 54,000,000
purchased gas costs						319,300,000	406,200,000
Commodity Costs	10,800,000
Under collected commodity balances	114,400,000
Public Utilities, Approved Rate Increase (Decrease), Amount	17,800,000
Annual revenue	100,600,000
Refund to Customers	54,700,000
Refund to Customers, remaining balance	$ 4,100,000
Subsidiaries [Member] | Get to Zero Deferral Filing [Member]
Regulatory Assets [Line Items]
Depreciation and amortization		$ 21,700,000
Carrying charges on deferral		$ 500,000
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities		6.89%
Public Utilities, Property, Plant and Equipment, Equipment, Useful Life		10 years
Subsidiaries [Member] | Storm that occurred in 2019 [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Deferred During Period						28,500,000
Subsidiaries [Member] | Storm that occurred in 2018 [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Deferred During Period						400,000	11,900,000
Subsidiaries [Member] | Storm that occurred in 2017 [Member]
Regulatory Assets [Line Items]
Storm Damage Costs Deferred During Period							3,300,000
Natural Gas, US Regulated [Member]
Regulatory Assets [Line Items]
Environmental Expense and Liabilities						54,800,000	62,200,000
Environmental Remediation Expense						41,800,000
Electricity, US Regulated [Member]
Regulatory Assets [Line Items]
Environmental Expense and Liabilities						13,700,000	$ 14,100,000
Environmental Remediation Expense						$ 8,700,000

Dividend Payment Restrictions (

Dividend Payment Restrictions (Details)	12 Months Ended
	Dec. 31, 2019USD ($)
Parent [Line Items]
Retained Earnings, Unappropriated	$ 914,200,000
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio, Threshold For Dividend Payment	2
EBITDA Interest Expense Ratio	3.6
EBITDA to Interest Expense Denominator	1
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End	1
Subsidiaries [Member]
Parent [Line Items]
Dividends, Common Equity Ratio, Threshold For Dividend Payment	44.00%
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio, Threshold For Dividend Payment	3
Dividends, Common Equity Ratio at Period End	48.40%
EBITDA Interest Expense Ratio	5.3
EBITDA to Interest Expense Denominator	1
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End	1

Utility Plant (Details)

Utility Plant (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Public Utility, Property, Plant and Equipment
Accumulated amortization of capital leases	$ 1,000	$ 1,300
Utility Plant
Distribution plant	6,602,934	6,122,739
Production plant	3,066,792	3,099,805
Transmission plant	1,463,288	1,442,854
General plant	698,275	682,976
Intangible plant (including capitalized software)	735,826	662,328
Plant acquisition adjustment	242,826	242,826
Underground storage	37,511	35,404
Liquefied natural gas storage	12,628	12,628
Plant held for future use	46,233	39,384
Base Gas Stored Underground	8,655	8,655
Plant not classified	316,923	239,857
Capital leases, net of accumulated amortization	1,488	1,315
Less: Accumulated depreciation and amortization	(3,236,240)	(2,832,321)
Subtotal	9,997,139	9,758,450
Construction work in progress	591,199	550,466
Net utility plant	$ 10,588,338	10,308,916
Minimum
Public Utility, Property, Plant and Equipment
Distribution plant, Estimated Useful Life	20 years
Production plant, Estimated Useful Life	12 years
Transmission plant, Estimated Useful Life	43 years
General plant, Estimated Useful Life	5 years
Public Utilities, Property, Plant and Equipment, Intangible, Estimated Useful Life 1	5 years
Underground storage, Estimated Useful Life	25 years
Liquefied natural gas storage, Estimated Useful Life	25 years
Minimum | Franchise Rights [Member]
Public Utility, Property, Plant and Equipment
General plant, Estimated Useful Life	10 years
Minimum | Software and Software Development Costs [Member]
Public Utility, Property, Plant and Equipment
General plant, Estimated Useful Life	3 years
Maximum
Public Utility, Property, Plant and Equipment
Distribution plant, Estimated Useful Life	65 years
Production plant, Estimated Useful Life	90 years
Transmission plant, Estimated Useful Life	75 years
General plant, Estimated Useful Life	75 years
Public Utilities, Property, Plant and Equipment, Intangible, Estimated Useful Life 1	50 years
Underground storage, Estimated Useful Life	60 years
Liquefied natural gas storage, Estimated Useful Life	60 years
Maximum | Franchise Rights [Member]
Public Utility, Property, Plant and Equipment
General plant, Estimated Useful Life	50 years
Maximum | Software and Software Development Costs [Member]
Public Utility, Property, Plant and Equipment
General plant, Estimated Useful Life	10 years
Subsidiaries [Member]
Utility Plant
Distribution plant	$ 8,185,700	7,722,024
Production plant	3,743,493	3,974,250
Transmission plant	1,571,186	1,550,950
General plant	731,279	718,105
Intangible plant (including capitalized software)	726,383	652,942
Plant acquisition adjustment	282,792	282,792
Underground storage	50,963	48,874
Liquefied natural gas storage	14,498	14,498
Plant held for future use	46,385	39,536
Base Gas Stored Underground	8,655	8,655
Plant not classified	316,923	239,857
Capital leases, net of accumulated amortization	1,488	1,315
Less: Accumulated depreciation and amortization	(5,682,606)	(5,495,348)
Subtotal	9,997,139	9,758,450
Construction work in progress	591,199	550,466
Net utility plant	$ 10,588,338	$ 10,308,916

Utility Plant - Jointly Owned U

Utility Plant - Jointly Owned Utility Plant (Details) $ in Thousands	Dec. 31, 2019USD ($)
Colstrip Units 3 & 4
Jointly Owned Utility Plant Interests
Plant in Service at Cost	$ 323,100
Construction Work in Progress	0
Accumulated Depreciation	(138,827)
Frederickson 1
Jointly Owned Utility Plant Interests
Plant in Service at Cost	61,820
Construction Work in Progress	0
Accumulated Depreciation	(10,995)
Jackson Prairie [Member]
Jointly Owned Utility Plant Interests
Plant in Service at Cost	36,837
Construction Work in Progress	119
Accumulated Depreciation	(8,452)
Tacoma LNG [Member]
Jointly Owned Utility Plant Interests
Plant in Service at Cost	0
Construction Work in Progress	362,684
Accumulated Depreciation	0
Subsidiaries [Member] | Colstrip Units 1 and 2 [Member]
Jointly Owned Utility Plant Interests
Regulatory Assets, Unrecovered plant balance	$ 126,500
Subsidiaries [Member] | Colstrip Units 3 & 4
Jointly Owned Utility Plant Interests
Company’s Ownership Share	25.00%
Plant in Service at Cost	$ 582,372
Construction Work in Progress	0
Accumulated Depreciation	$ (398,099)
Subsidiaries [Member] | Frederickson 1
Jointly Owned Utility Plant Interests
Company’s Ownership Share	49.85%
Plant in Service at Cost	$ 67,888
Construction Work in Progress	0
Accumulated Depreciation	$ (17,063)
Subsidiaries [Member] | Jackson Prairie [Member]
Jointly Owned Utility Plant Interests
Company’s Ownership Share	33.34%
Plant in Service at Cost	$ 50,963
Construction Work in Progress	119
Accumulated Depreciation	(22,578)
Subsidiaries [Member] | Tacoma LNG [Member]
Jointly Owned Utility Plant Interests
Plant in Service at Cost	0
Construction Work in Progress	162,820
Accumulated Depreciation	$ 0

Utility Plant - Schedule of Ass

Utility Plant - Schedule of Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Tacoma LNG [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Decommissioning Liability, Noncurrent	$ 3,000	$ 2,700
Subsidiaries [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of the period	182,203	191,176
New asset retirement obligation recognized in the period	0	501
Relief of liability	(12,449)	(4,750)
Revisions in estimated cash flows	5,922	(10,512)
Accretion expense	5,677	5,788
Asset Retirement Obligation, Ending Balance	181,353	182,203
Decommissioning Liability, Noncurrent	12,400	4,800
Subsidiaries [Member] | Colstrip Units 1 and 2 [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Decommissioning Liability, Noncurrent	4,200	11,000
Regulatory Assets, Unrecovered plant balance	126,500
Puget LNG [Member] | Tacoma LNG [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Decommissioning Liability, Noncurrent	$ 4,300	$ 1,700

Utility Plant - Narrative (Deta

Utility Plant - Narrative (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Tacoma LNG [Member]
Jointly Owned Utility Plant Interests
Decommissioning Liability, Noncurrent	$ 3,000	$ 2,700
Subsidiaries [Member]
Jointly Owned Utility Plant Interests
Decommissioning Liability, Noncurrent	12,400	4,800
Subsidiaries [Member] | Colstrip Units 1 and 2 [Member]
Jointly Owned Utility Plant Interests
Decommissioning Liability, Noncurrent	4,200	11,000
Subsidiaries [Member] | Colstrip Units 3 and 4 [Member]
Jointly Owned Utility Plant Interests
Decommissioning Liability, Noncurrent	500	1,800
Puget LNG [Member] | Tacoma LNG [Member]
Jointly Owned Utility Plant Interests
Decommissioning Liability, Noncurrent	$ 4,300	$ 1,700

Long-Term Debt (Schedule of Lon

Long-Term Debt (Schedule of Long-Term Debt Instruments) (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018	Oct. 01, 2018	Jun. 04, 2018	Mar. 05, 2018
Debt Instrument [Line Items]
Total PSE long-term debt	$ 6,584,372,000
Long Term Debt, Reconciliation, Fair Value Adjustment	(173,865,000)	$ (182,372,000)
Long-term Debt, term loan			$ 210,000,000
Long-term Line of Credit, Noncurrent	24,100,000	11,900,000
Unamortized discount on senior notes	(52,000)	(1,897,000)
Long-term Debt, Excluding Current Maturities	5,920,325,000	5,672,491,000
Current maturities of long-term debt	452,412,000	0
$174M Term Loan Due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt, term loan	174,000,000	150,000,000	$ 150,000,000
$210M Term Loan Due 2022
Debt Instrument [Line Items]
Long-term Debt, term loan	$ 210,000,000	0
Senior Secured Note | 6.500% Senior Secured Note Due 2020
Debt Instrument [Line Items]
Stated interest rate percent	6.50%
Total PSE long-term debt	$ 0	450,000,000
Current maturities of long-term debt	$ 450,000,000
Senior Secured Note | 6.000% Senior Secured Note Due 2021
Debt Instrument [Line Items]
Stated interest rate percent	6.00%
Total PSE long-term debt	$ 500,000,000	500,000,000
Senior Secured Note | 5.625% Senior Secured Note Due 2022
Debt Instrument [Line Items]
Stated interest rate percent	5.625%
Total PSE long-term debt	$ 450,000,000	450,000,000
Senior Secured Note | 3.650% Senior Secured Note Due 2025 [Member]
Debt Instrument [Line Items]
Stated interest rate percent	3.65%
Total PSE long-term debt	$ 400,000,000	400,000,000
Subsidiaries [Member]
Debt Instrument [Line Items]
Total PSE long-term debt	4,376,272,000
Unamortized discount on senior notes	(37,718,000)	(31,412,000)
Long-term Debt, Excluding Current Maturities	4,336,142,000	3,894,860,000
Current maturities of long-term debt	$ 2,412,000	0
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 5.500% Secured Promissory Note Due 2017
Debt Instrument [Line Items]
Stated interest rate percent	5.50%
Total PSE long-term debt	$ 0	2,412,000
Current maturities of long-term debt	$ 2,400,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 7.150% Series Due 2025
Debt Instrument [Line Items]
Stated interest rate percent	7.15%
Total PSE long-term debt	$ 15,000,000	15,000,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 7.200% Series Due 2025
Debt Instrument [Line Items]
Stated interest rate percent	7.20%
Total PSE long-term debt	$ 2,000,000	2,000,000
Subsidiaries [Member] | Pollution Control Bonds | 3.900% Series Due 2031
Debt Instrument [Line Items]
Stated interest rate percent	3.90%
Total PSE long-term debt	$ 138,460,000	138,460,000
Subsidiaries [Member] | Pollution Control Bonds | 4.000% Series Due 2031
Debt Instrument [Line Items]
Stated interest rate percent	4.00%
Total PSE long-term debt	$ 23,400,000	23,400,000
Subsidiaries [Member] | Senior Secured Note | 7.020% Series Due 2027
Debt Instrument [Line Items]
Stated interest rate percent	7.02%
Total PSE long-term debt	$ 300,000,000	300,000,000
Subsidiaries [Member] | Senior Secured Note | 7.000% Series Due 2029
Debt Instrument [Line Items]
Stated interest rate percent	7.00%
Total PSE long-term debt	$ 100,000,000	100,000,000
Subsidiaries [Member] | Senior Secured Note | 5.483% Series Due 2035
Debt Instrument [Line Items]
Stated interest rate percent	5.483%
Total PSE long-term debt	$ 250,000,000	250,000,000
Subsidiaries [Member] | Senior Secured Note | 6.724% Series Due 2036
Debt Instrument [Line Items]
Stated interest rate percent	6.724%
Total PSE long-term debt	$ 250,000,000	250,000,000
Subsidiaries [Member] | Senior Secured Note | 6.274% Series Due 2037
Debt Instrument [Line Items]
Stated interest rate percent					6.274%
Total PSE long-term debt	$ 300,000,000	300,000,000
Subsidiaries [Member] | Senior Secured Note | 5.757% Series Due 2039
Debt Instrument [Line Items]
Stated interest rate percent	5.757%
Total PSE long-term debt	$ 350,000,000	350,000,000
Subsidiaries [Member] | Senior Secured Note | 5.795% Series Due 2040
Debt Instrument [Line Items]
Stated interest rate percent	5.795%
Total PSE long-term debt	$ 325,000,000	325,000,000
Subsidiaries [Member] | Senior Secured Note | 5.764% Series Due 2040
Debt Instrument [Line Items]
Stated interest rate percent	5.764%
Total PSE long-term debt	$ 250,000,000	250,000,000
Subsidiaries [Member] | Senior Secured Note | 4.434% Series Due 2041
Debt Instrument [Line Items]
Stated interest rate percent	4.434%
Total PSE long-term debt	$ 250,000,000	250,000,000
Subsidiaries [Member] | Senior Secured Note | 5.638% Series Due 2041
Debt Instrument [Line Items]
Stated interest rate percent	5.638%
Total PSE long-term debt	$ 300,000,000	300,000,000
Subsidiaries [Member] | Senior Secured Note | 4.300% Series Due 2045
Debt Instrument [Line Items]
Stated interest rate percent	4.30%
Total PSE long-term debt	$ 425,000,000	425,000,000
Subsidiaries [Member] | Senior Secured Note | 4.223% Series Due 2048
Debt Instrument [Line Items]
Stated interest rate percent	4.223%			4.223%
Total PSE long-term debt	$ 600,000,000	600,000,000		$ 600,000,000
Subsidiaries [Member] | Senior Secured Note | 3.250% Senior Secured Note Due 2049 [Member]
Debt Instrument [Line Items]
Stated interest rate percent	3.25%
Total PSE long-term debt	$ 450,000,000	0
Subsidiaries [Member] | Senior Secured Note | 4.700% Series Due 2051
Debt Instrument [Line Items]
Stated interest rate percent	4.70%
Total PSE long-term debt	$ 45,000,000	$ 45,000,000

Long-Term Debt (Narrative) (Det

Long-Term Debt (Narrative) (Details) - USD ($)	Dec. 31, 2019	Aug. 02, 2019	Dec. 31, 2018	Oct. 01, 2018	Jun. 04, 2018	Mar. 28, 2018	Mar. 19, 2018	Mar. 05, 2018
Debt Instrument [Line Items]
Long-term Debt, term loan				$ 210,000,000
Total PSE long-term debt	$ 6,584,372,000
Long-term Line of Credit, Noncurrent	24,100,000		$ 11,900,000
Long-term debt	6,584,372,000
Line of Credit Facility, Remaining Borrowing Capacity		$ 550,000,000
Line of Credit Facility, Maximum Borrowing Capacity	1,300,000,000
$174M Term Loan Due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt, term loan	174,000,000		150,000,000	150,000,000
Term Loan Expansion [Member]
Debt Instrument [Line Items]
Long-term Line of Credit, Noncurrent			100,000,000
Term Loan Expansion [Member] | $174M Term Loan Due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt, term loan				$ 24,000,000
Subsidiaries [Member]
Debt Instrument [Line Items]
Total PSE long-term debt	4,376,272,000
Long-term debt	4,376,272,000
Commercial Paper					$ 348,000,000
Line of Credit Facility, Maximum Borrowing Capacity	1,400,000,000	$ 1,000,000,000
Subsidiaries [Member] | Senior Secured Note | 6.740% Series Due 2018
Debt Instrument [Line Items]
Total PSE long-term debt					200,000,000
Long-term debt					200,000,000
Subsidiaries [Member] | Senior Secured Note | 4.223% Series Due 2048
Debt Instrument [Line Items]
Total PSE long-term debt	600,000,000		600,000,000		600,000,000
Long-term debt	$ 600,000,000		$ 600,000,000		$ 600,000,000
Stated interest rate percent	4.223%				4.223%
Subsidiaries [Member] | Junior Subordinated Debt | consent fees [Member]
Debt Instrument [Line Items]
Total PSE long-term debt								$ 2,600,000
Long-term debt								2,600,000
Subsidiaries [Member] | Junior Subordinated Debt | debt premium
Debt Instrument [Line Items]
Total PSE long-term debt								1,005
Long-term debt								1,005
Subsidiaries [Member] | Junior Subordinated Debt | debt discount
Debt Instrument [Line Items]
Total PSE long-term debt								975
Long-term debt								975
Subsidiaries [Member] | Junior Subordinated Debt | principal paid
Debt Instrument [Line Items]
Total PSE long-term debt								194,900,000
Long-term debt								194,900,000
Subsidiaries [Member] | Junior Subordinated Debt | debt face value
Debt Instrument [Line Items]
Total PSE long-term debt								1,000
Long-term debt								1,000
Subsidiaries [Member] | Junior Subordinated Debt | early principal paid
Debt Instrument [Line Items]
Total PSE long-term debt								193,400,000
Long-term debt								193,400,000
Subsidiaries [Member] | Junior Subordinated Debt | remaining principal paid
Debt Instrument [Line Items]
Total PSE long-term debt						$ 56,600,000
Long-term debt						$ 56,600,000
Subsidiaries [Member] | Junior Subordinated Debt | 6.974% Series Due 2067
Debt Instrument [Line Items]
Total PSE long-term debt								250,000,000
Long-term debt								$ 250,000,000
Stated interest rate percent						6.974%	6.974%	6.974%

Long-Term Debt (Schedule of Mat

Long-Term Debt (Schedule of Maturities of Long-Term Debt) (Details) $ in Thousands	Dec. 31, 2019USD ($)
Maturities of Long-term Debt [Abstract]
2020	$ 452,412
2021	674,000
2022	660,000
2023	24,100
2024	0
Thereafter	4,773,860
Total long-term debt	6,584,372
Subsidiaries [Member]
Maturities of Long-term Debt [Abstract]
2020	2,412
2021	0
2022	0
2023	0
2024	0
Thereafter	4,373,860
Total long-term debt	4,376,272
Parent Company [Member]
Maturities of Long-term Debt [Abstract]
2020	450,000
2021	674,000
2022	660,000
2023	24,100
2024	0
Thereafter	400,000
Total long-term debt	$ 2,208,100

Liquidity Facilities and Othe_2

Liquidity Facilities and Other Financing Arrangements (Details) - USD ($)	Feb. 10, 2012	Dec. 31, 2019	Aug. 02, 2019	Dec. 31, 2018	Oct. 10, 2017
Short-term Debt [Line Items]
Short-term debt		$ 176,000,000		$ 379,297,000
Line of Credit Facility, Maximum Borrowing Capacity		1,300,000,000
Working Capital Needs
Short-term Debt [Line Items]
Current borrowing capacity of line of credit					$ 800,000,000
Subsidiaries [Member]
Short-term Debt [Line Items]
Short-term debt		$ 176,000,000		$ 379,297,000
Weighted-average interest rate on short-term debt (percent)		3.40%
Line of Credit Facility, Current Same-Day Borrowing Capacity		$ 75,000,000
Line of Credit Facility, Maximum Borrowing Capacity		$ 1,400,000,000	$ 1,000,000,000
Maximum capitalization percentage		65.00%
Derivative, Basis Spread on Variable Rate		1.25%
Line of Credit, Unused Capacity, Commitment Fee Percentage		0.175%
Subsidiaries [Member] | Working Capital Needs
Short-term Debt [Line Items]
Current borrowing capacity of line of credit					$ 800,000,000
Subsidiaries [Member] | Energy Hedging Activities [Member]
Short-term Debt [Line Items]
Outstanding amount for line of credit		$ 1,000,000
Subsidiaries [Member] | Letter of Credit | Working Capital Needs
Short-term Debt [Line Items]
Current borrowing capacity of line of credit		2,800,000
Subsidiaries [Member] | Line of Credit [Member] | Promissory Note with Puget Energy
Short-term Debt [Line Items]
Current borrowing capacity of line of credit		$ 30,000,000
Basis spread on variable rate (percent)		25.00%
Debt instrument variable rate basis		one-month LIBOR
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Basis spread on variable rate (percent)		1.75%
Line of Credit Facility, Commitment Fee Percentage	0.275%
Line of Credit Facility, Fair Value of Amount Outstanding		$ 24,100,000

Leases (Details)

Leases (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Lessee, Lease, Description [Line Items]
Lease, Remaining Lease Term	50 years
Lease Extension Term	25 years
Subsidiaries [Member]
Lessee, Lease, Description [Line Items]
Right-of-Use, Modification, Operating	$ 14,712

Leases (Schedule of Operating L

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

Leases (Cash paid) (Details)

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

Leases (Balance Sheet) (Details

Leases (Balance Sheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Leases [Abstract]
Operating lease right-of-use asset	$ 183,048	$ 0
Operating lease liabilities	15,862	0
Operating lease liabilities	174,327	$ 0
Operating Lease, Liability	190,189
Finance Lease, Right-of-Use Asset	1,488
Finance Lease, Liability, Current	669
Finance Lease, Liability, Noncurrent	811
Finance Lease, Liability	$ 1,480
Operating Lease, Weighted Average Remaining Lease Term	19 years 2 months 26 days
Finance Lease, Weighted Average Remaining Lease Term	2 years 9 months 3 days
Operating Lease, Weighted Average Discount Rate, Percent	3.59%
Finance Lease, Weighted Average Discount Rate, Percent	2.98%

Leases (Remaining Cash Payments

Leases (Remaining Cash Payments) (Details) $ in Thousands	Dec. 31, 2019USD ($)
Leases [Abstract]
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months	$ 22,500
Lessee, Operating Lease, Liability, Payments, Due Year Two	22,527
Lessee, Operating Lease, Liability, Payments, Due Year Three	21,856
Lessee, Operating Lease, Liability, Payments, Due Year Four	21,415
Lessee, Operating Lease, Liability, Payments, Due Year Five	20,690
Lessee, Operating Lease, Liability, Payments, Due after Year Five	160,410
Lessee, Operating Lease, Liability, Payments, Due	269,398
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(79,209)
Operating Lease, Liability	190,189
Finance Lease, Liability, Payments, Due Next Twelve Months	643
Finance Lease, Liability, Payments, Due Year Two	508
Finance Lease, Liability, Payments, Due Year Three	279
Finance Lease, Liability, Payments, Due Year Four	98
Finance Lease, Liability, Payments, Due Year Five	0
Finance Lease, Liability, Payments, Due after Year Five	0
Finance Lease, Liability, Payment, Due	1,528
Finance Lease, Liability, Undiscounted Excess Amount	(48)
Finance Lease, Liability	$ 1,480

Leases (Schedule of Future Mini

Leases (Schedule of Future Minimum Lease Payments for Non-cancellable Leases) (Details) $ in Thousands	Dec. 31, 2018USD ($)
Operating
2019	$ 20,635
2020	20,704
2021	20,630
2022	20,202
2023	19,223
Thereafter	132,889
Total minimum lease payments	234,283
Capital
2019	495
2020	446
2021	311
2022	82
2023	0
Thereafter	0
Total minimum lease payments	$ 1,334

Leases (ASC 840) (Details)

Leases (ASC 840) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Leases [Abstract]
Operating Lease Expense	$ 34,093	$ 35,198

Accounting for Derivative Ins_3

Accounting for Derivative Instruments and Hedging Activities (Schedule of Derivative Assets and Liabilities) (Details) $ in Thousands, MWh in Millions, MMBTU in Millions	Dec. 31, 2019USD ($)MWhMMBTU	Dec. 31, 2018USD ($)MMBTUMWh
Derivative [Line Items]
Assets, Current	$ 23,626	$ 46,507
Assets, Long-term	7,682	2,512
Liabilities, Current	13,428	46,661
Liabilities, Long-term	12,693	11,095
Not Designated as Hedging Instrument
Derivative [Line Items]
Total derivative assets	31,308	49,019
Total derivative liabilities	26,121	57,756
Not Designated as Hedging Instrument | Parent Company [Member]
Derivative [Line Items]
Assets, Current	23,626	46,507
Assets, Long-term	7,682	2,512
Liabilities, Current	13,428	46,661
Liabilities, Long-term	$ 12,693	$ 11,095
Not Designated as Hedging Instrument | Electric Generation Fuel
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	229.3	194.8
Not Designated as Hedging Instrument | Purchased Electricity
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MWh	10.4	6.6
Not Designated as Hedging Instrument | Natural Gas Portfolio
Derivative [Line Items]
Total derivative assets	$ 11,375	$ 15,732
Total derivative liabilities	8,617	30,472
Not Designated as Hedging Instrument | Electric Portfolio
Derivative [Line Items]
Total derivative assets	19,933	33,287
Total derivative liabilities	$ 17,504	$ 27,284
Not Designated as Hedging Instrument | Gas Derivatives
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	316	337

Accounting for Derivative Ins_4

Accounting for Derivative Instruments and Hedging Activities (Offsetting) (Details) - Commodity Contract [Member] - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Derivative Asset, Fair Value, Amount Offset Against Collateral [Abstract]
Derivative Asset, Fair Value, Gross Asset	$ 31,308	$ 49,019
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	0
Derivative Asset	31,308	49,019
Derivative, Collateral, Obligation to Return Securities	14,922	25,388
Derivative, Collateral, Obligation to Return Cash	0	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	16,386	23,631
Derivative Liability, Fair Value, Amount Offset Against Collateral [Abstract]
Derivative Liability, Fair Value, Gross Liability	26,121	57,756
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0	0
Derivative Liability	26,121	57,756
Derivative, Collateral, Right to Reclaim Securities	14,922	25,388
Derivative, Collateral, Right to Reclaim Cash	(2,000)	0
Derivative Liability, Fair Value, Amount Offset Against Collateral	$ 13,199	$ 32,368

Accounting for Derivative Ins_5

Accounting for Derivative Instruments and Hedging Activities (Schedule of Amounts Recognized in Statement of Income) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments, net	$ 3,574	$ (41,662)	$ 30,790
Not Designated as Hedging Instrument
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments, net	55,940	80,124	(71,830)
Not Designated as Hedging Instrument | Other Income (Deductions) | Interest Expense
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments, net	0	0	28
Not Designated as Hedging Instrument | Energy Related Derivative | Unrealized (Gain) Loss on Derivative Instruments, Net
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments, net	16,970	23,186	(32,492)
Not Designated as Hedging Instrument | Commodity Contract [Member] | Electric Generation Fuel
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments, net	10,828	26,222	(23,195)
Not Designated as Hedging Instrument | Commodity Contract [Member] | Purchased Electricity
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments, net	48,686	12,240	(17,873)
Not Designated as Hedging Instrument | Electric | Unrealized (Gain) Loss on Derivative Instruments, Net
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments, net	$ (20,544)	$ 18,476	$ 1,702

Accounting for Derivative Ins_6

Accounting for Derivative Instruments and Hedging Activities (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Electric Portfolio
Derivative [Line Items]
Posted Collateral	$ 14,827	$ 0
Credit Rating | Natural Gas Portfolio
Derivative [Line Items]
Posted Collateral	$ 1,000
External Credit Rating, Investment Grade [Member] | Electric Portfolio
Derivative [Line Items]
Percentage of derivatives with credit risk exposure	95.00%
External Credit Rating, Non Investment Grade [Member] | Electric Portfolio
Derivative [Line Items]
Percentage of derivatives with credit risk exposure	5.00%
Credit Rating
Derivative [Line Items]
Posted Collateral	$ 14,800
Credit Rating | Electric Portfolio
Derivative [Line Items]
Posted Collateral	$ 0	$ 0

Accounting for Derivative Ins_7

Accounting for Derivative Instruments and Hedging Activities (Schedule of Contractual Contingent Liability Positions) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Electric Portfolio
Derivative [Line Items]
Fair Value Liability	$ 11,363	$ 19,069
Posted Collateral	14,827	0
Contingent Collateral	6,110	574
Forward Value of Contract [Member] | Electric Portfolio
Derivative [Line Items]
Fair Value Liability	0	0
Posted Collateral	14,827	0
Contingent Collateral		0
Requested Credit for Adequate Assurance | Electric Portfolio
Derivative [Line Items]
Fair Value Liability	5,253	18,495
Posted Collateral	0	0
Contingent Collateral	0	0
Credit Rating
Derivative [Line Items]
Posted Collateral	14,800
Credit Rating | Electric Portfolio
Derivative [Line Items]
Fair Value Liability	6,110	574
Posted Collateral	0	0
Contingent Collateral	$ 6,110	$ 574

Fair Value Measurements - Debt

Fair Value Measurements - Debt at Carrying and Fair Value (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Subsidiaries [Member] | Carrying Amount | Income Approach Valuation Technique
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	$ 4,336,142,000	$ 3,894,860,000
Subsidiaries [Member] | Carrying Amount | Income Approach Valuation Technique | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unamortized Debt Issuance Expense	24,400,000	24,600,000
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	4,336,142,000	3,894,860,000
Subsidiaries [Member] | Total | Income Approach Valuation Technique
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	5,571,818,000	4,574,611,000
Subsidiaries [Member] | Total | Income Approach Valuation Technique | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	5,571,818,000	4,574,611,000
Parent Company [Member] | Carrying Amount | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Notes Receivable, Fair Value Disclosure	51,500,000	49,500,000
Parent Company [Member] | Carrying Amount | Income Approach Valuation Technique
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	5,920,325,000	5,672,491,000
Parent Company [Member] | Carrying Amount | Income Approach Valuation Technique | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unamortized Debt Issuance Expense	24,100,000	26,100,000
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	5,512,225,000	5,510,591,000
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure	408,100,000	161,900,000
Parent Company [Member] | Total | Income Approach Valuation Technique
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	7,412,416,000	6,605,642,000
Parent Company [Member] | Total | Income Approach Valuation Technique | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	7,004,316,000	6,443,742,000
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure	$ 408,100,000	$ 161,900,000

Fair Value Measurements - Sched

Fair Value Measurements - Schedule of Assets and Liabilities (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	$ 31,308	$ 49,019
Derivative Liability	26,121	57,756
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	29,134	41,012
Derivative Liability	21,850	52,784
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	2,174	8,007
Derivative Liability	4,271	4,972
Electric Portfolio
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	19,933	33,287
Derivative Liability	17,504	27,284
Electric Portfolio | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	19,282	28,765
Derivative Liability	13,474	24,124
Electric Portfolio | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	651	4,522
Derivative Liability	4,030	3,160
Natural Gas Portfolio
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	11,375	15,732
Derivative Liability	8,617	30,472
Natural Gas Portfolio | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	9,852	12,247
Derivative Liability	8,376	28,660
Natural Gas Portfolio | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	1,523	3,485
Derivative Liability	$ 241	$ 1,812

Fair Value Measurements - Unobs

Fair Value Measurements - Unobservable Input Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Beginning Balance	$ 3,035	$ 3,021	$ 1,597
Included in earnings	3,558	34,604	2,781
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities)	3,151	6,075	6,346
Settlements	(15,973)	(40,264)	(12,921)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3	3,992	(1,987)	(30)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3	140	1,586	5,248
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Ending Balance	(2,097)	3,035	3,021
Electric Portfolio
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Beginning Balance	1,362	1,098	972
Included in earnings	3,558	34,604	2,781
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities)	0	0	0
Settlements	(11,265)	(33,067)	(6,549)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3	4,390	(1,987)	523
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3	(1,424)	714	3,371
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Ending Balance	(3,379)	1,362	1,098
Unrealized gain (loss) on derivative instruments, net	(3,200)	1,100,000	1,500,000
Natural Gas Portfolio
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Beginning Balance	1,673	1,923	625
Included in earnings	0	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Regulatory Assets (Liabilities)	3,151	6,075	6,346
Settlements	(4,708)	(7,197)	(6,372)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3	(398)	0	(553)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3	1,564	872	1,877
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Ending Balance	$ 1,282	$ 1,673	$ 1,923

Fair Value Measurements - Forwa

Fair Value Measurements - Forward Price Ranges (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)$ / MWh$ / MMBTU	Dec. 31, 2018USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value measurement, sensitivity analysis, hypothetical increase or decrease of market prices, result on fair value, percent	10.00%
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value	$ 2,500
Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	31,308	$ 49,019
Derivative Liability	26,121	57,756
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	2,174	8,007
Derivative Liability	4,271	4,972
Natural Gas Portfolio | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	11,375	15,732
Derivative Liability	8,617	30,472
Natural Gas Portfolio | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	1,523	3,485
Derivative Liability	$ 241	1,812
Natural Gas Portfolio | Income Approach Valuation Technique | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU	1.25
Natural Gas Portfolio | Income Approach Valuation Technique | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU	3.18
Natural Gas Portfolio | Income Approach Valuation Technique | Weighted Average
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU	2.47
Natural Gas Portfolio | Parent Company [Member] | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 1,523
Derivative Liability	241
Electric Portfolio | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	19,933	33,287
Derivative Liability	17,504	27,284
Electric Portfolio | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	651	4,522
Derivative Liability	$ 4,030	$ 3,160
Electric Portfolio | Income Approach Valuation Technique | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Power prices (per MWh) | $ / MWh	9
Electric Portfolio | Income Approach Valuation Technique | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Power prices (per MWh) | $ / MWh	43.85
Electric Portfolio | Income Approach Valuation Technique | Weighted Average
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Power prices (per MWh) | $ / MWh	33.99
Electric Portfolio | Parent Company [Member] | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 651
Derivative Liability	$ 4,030

Fair Value Measurements - Valua

Fair Value Measurements - Valuations (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2018
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Impairment of Intangible Assets (Excluding Goodwill)		$ 1,907
Wells Project [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-Lived Intangible Assets, Net	$ 4,302
Impairment of Intangible Assets (Excluding Goodwill)	1,907
Wells Project [Member] | Carrying Amount
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure	$ 2,395

Fair Value Measurements - Uno_2

Fair Value Measurements - Unobservable Input (Details) - Wells Project [Member] - Income Approach Valuation Technique	3 Months Ended
	Mar. 31, 2018USD ($)$ / MWh
Minimum
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Power prices (per MWh) | $ / MWh	9.69
Fair Value Inputs, Power Contract Costs | $	$ 4,126
Maximum
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Power prices (per MWh) | $ / MWh	25.30
Fair Value Inputs, Power Contract Costs | $	$ 4,126
Weighted Average
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Power prices (per MWh) | $ / MWh	17.50
Fair Value Inputs, Power Contract Costs | $	$ 4,126

Employee Investment Plans - Nar

Employee Investment Plans - Narrative (Details) - Subsidiaries [Member] - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Contribution Plan Disclosure [Line Items]
Employer discretionary contribution amount	$ 21,700,000	$ 20,700,000	$ 19,200,000
Employer matching contribution, percent	4.50%
Maximum annual contribution per employee, percent	6.00%
employer contribution [Member]
Defined Contribution Plan Disclosure [Line Items]
Employer matching contribution, percent	4.00%
Collective Bargaining Arrangement Member [Member] | employer contribution [Member]
Defined Contribution Plan Disclosure [Line Items]
Employer matching contribution, percent	4.00%
Cash Balance Formula | Collective Bargaining Arrangement Member [Member]
Defined Contribution Plan Disclosure [Line Items]
Employer matching contribution, percent	100.00%
Maximum annual contribution per employee, percent	6.00%
Employer additional contribution of base pay, percentage	1.00%
Final Average Earnings Formula | Collective Bargaining Arrangement Member [Member]
Defined Contribution Plan Disclosure [Line Items]
Employer matching contribution, percent	55.00%
Maximum annual contribution per employee, percent	6.00%
Second 3 Percent
Defined Contribution Plan Disclosure [Line Items]
Employer matching contribution, percent	50.00%
Maximum annual contribution per employee, percent	3.00%
First 3 Percent
Defined Contribution Plan Disclosure [Line Items]
Employer matching contribution, percent	100.00%
Maximum annual contribution per employee, percent	3.00%

Retirement Benefits - Change in

Retirement Benefits - Change in Net Benefit Obligation and Fair Value (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Other Pension Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	$ 10,636	$ 11,454
Amendments	(9,049)	0
Service cost	61	69
Interest cost	410	444
Curtailment Loss / (Gain)	(7,486)	0
Actuarial loss (gain)	287	379
Benefits paid	982	1,037
Medicare part D subsidy received	226	85
Administrative expense	0	0
Benefit obligation at end of period	11,627	10,636
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of period	5,960	7,138
Actual return on plan assets	1,006	(395)
Employer contribution	305	254
Benefits paid	(982)	(1,037)
Administrative expense	0	0
Fair value of plan assets at end of period	6,289	5,960
Funded status at end of period	(5,338)	(4,676)
Nonqualified Plan | Pension Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	55,708	55,754
Amendments	0	(1,446)
Service cost	1,023	847
Interest cost	2,314	2,120
Curtailment Loss / (Gain)	0	0
Actuarial loss (gain)	(6,756)	(1,122)
Benefits paid	2,801	5,581
Medicare part D subsidy received	0	0
Administrative expense	0	0
Benefit obligation at end of period	63,000	55,708
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of period	0	0
Actual return on plan assets	0	0
Employer contribution	2,801	5,581
Benefits paid	(2,801)	(5,581)
Administrative expense	0	0
Fair value of plan assets at end of period	0	0
Funded status at end of period	(63,000)	(55,708)
Qualified Plan | Pension Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	677,643	700,481
Amendments	0	0
Service cost	22,656	22,757
Interest cost	28,913	27,303
Curtailment Loss / (Gain)	0	0
Actuarial loss (gain)	(84,272)	29,067
Benefits paid	36,740	42,662
Medicare part D subsidy received	0	0
Administrative expense	(2,439)	(1,169)
Benefit obligation at end of period	774,305	677,643
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of period	640,242	704,360
Actual return on plan assets	133,939	(38,379)
Employer contribution	18,000	18,000
Benefits paid	(36,740)	(42,662)
Administrative expense	(2,399)	(1,077)
Fair value of plan assets at end of period	753,042	640,242
Funded status at end of period	$ (21,263)	$ (37,401)

Retirement Benefits - Amounts R

Retirement Benefits - Amounts Recognized (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Other Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 11,627	$ 10,636	$ 11,454
Accumulated benefit obligation	11,604	10,557
Fair value of plan assets	6,289	5,960	7,138
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets	0	0
Current liabilities	(308)	(332)
Noncurrent liabilities	(5,030)	(4,344)
Net assets (liabilities)	(5,338)	(4,676)
Parent Company [Member] | Other Pension Plan [Member]
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Accumulated Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Tax	(197)	(2,564)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax	0	0
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total	(197)	(2,564)
Subsidiaries [Member] | Other Pension Plan [Member]
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Accumulated Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Tax	(364)	(3,857)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax	0	0
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total	(364)	(3,857)
Nonqualified Plan | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	63,000	55,708	55,754
Accumulated benefit obligation	59,988	51,031
Fair value of plan assets	0	0	0
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets	0	0
Current liabilities	(22,604)	(6,249)
Noncurrent liabilities	(40,396)	(49,459)
Net assets (liabilities)	(63,000)	(55,708)
Nonqualified Plan | Parent Company [Member] | Pension Plan [Member]
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Accumulated Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Tax	15,003	9,612
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax	1,276	1,607
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total	16,279	11,219
Nonqualified Plan | Subsidiaries [Member] | Pension Plan [Member]
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Accumulated Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Tax	16,473	11,450
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax	1,276	1,609
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total	17,749	13,059
Qualified Plan | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	774,305	677,643	700,481
Accumulated benefit obligation	762,838	668,469
Fair value of plan assets	753,042	640,242	$ 704,360
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets	0	0
Current liabilities	0	0
Noncurrent liabilities	(21,263)	(37,401)
Net assets (liabilities)	(21,263)	(37,401)
Qualified Plan | Parent Company [Member] | Pension Plan [Member]
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Accumulated Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Tax	94,319	94,929
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax	(3,884)	(5,863)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total	90,435	89,066
Qualified Plan | Subsidiaries [Member] | Pension Plan [Member]
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Accumulated Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Tax	217,502	229,819
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), after Tax	(3,086)	(4,659)
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax, Total	$ 214,416	$ 225,160

Retirement Benefits - Net Perio

Retirement Benefits - Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Other Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	$ 61	$ 69
Interest cost	410	444
Parent Company [Member] | Other Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	61	69	$ 72
Interest cost	410	444	500
Expected return on plan assets	(393)	(472)	(461)
Amortization of prior service cost (credit)	0	0	0
Amortization of net loss (gain)	(374)	(335)	(402)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	(296)	(294)	(291)
Subsidiaries [Member] | Other Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	61	69	72
Interest cost	410	444	500
Expected return on plan assets	(393)	(472)	(461)
Amortization of prior service cost (credit)	0	0	0
Amortization of net loss (gain)	(562)	(556)	(641)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	(484)	(515)	(530)
Nonqualified Plan | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	1,023	847
Interest cost	2,314	2,120
Nonqualified Plan | Parent Company [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	1,023	847	913
Interest cost	2,314	2,120	2,285
Expected return on plan assets	0	0	0
Amortization of prior service cost (credit)	331	1,580	42
Amortization of net loss (gain)	1,365	42	1,077
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	5,033	4,589	4,317
Nonqualified Plan | Subsidiaries [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	1,023	847	913
Interest cost	2,314	2,120	2,285
Expected return on plan assets	0	0	0
Amortization of prior service cost (credit)	333	44	44
Amortization of net loss (gain)	1,733	2,069	1,565
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	5,403	5,080	4,807
Qualified Plan | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	22,656	22,757
Interest cost	28,913	27,303
Qualified Plan | Parent Company [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	22,656	22,757	20,081
Interest cost	28,913	27,303	28,373
Expected return on plan assets	(50,249)	(50,202)	(47,784)
Amortization of prior service cost (credit)	(1,980)	(1,980)	(1,980)
Amortization of net loss (gain)	1,151	2,187	0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	491	65	(1,310)
Qualified Plan | Subsidiaries [Member] | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	22,656	22,757	20,081
Interest cost	28,913	27,303	28,373
Expected return on plan assets	(50,267)	(50,240)	(47,862)
Amortization of prior service cost (credit)	(1,573)	(1,573)	(1,573)
Amortization of net loss (gain)	12,877	14,917	13,048
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Total	$ 12,606	$ 13,164	$ 12,067

Retirement Benefits - Benefit O

Retirement Benefits - Benefit Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer matching contribution, percent	4.50%
Defined Contribution Plan, Interest Credit	1.00%
Subsidiaries [Member] | employer contribution [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer matching contribution, percent	4.00%
Subsidiaries [Member] | employer contribution [Member] | Collective Bargaining Arrangement Member [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer matching contribution, percent	4.00%
Subsidiaries [Member] | employer contribution [Member] | Collective Bargaining Arrangement Member [Member] | UA represented [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer matching contribution, percent	4.00%
Subsidiaries [Member] | employer contribution [Member] | Collective Bargaining Arrangement Member [Member] | IBEW represented [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer matching contribution, percent	4.00%
Other Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss (gain)	$ 900	$ (488)
Amortization of net (loss) gain	374	335
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	2,892	0
Prior service cost (credit)	0	0
Amortization of prior service (cost) credit	0	0
Total change in other comprehensive income for year	2,366	823
Other Pension Plan [Member] | Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss (gain)	900	(488)
Amortization of net (loss) gain	562	556
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	3,832	0
Prior service cost (credit)	0	0
Amortization of prior service (cost) credit	0	0
Total change in other comprehensive income for year	3,494	1,044
Qualified Plan | Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss (gain)	(541)	(59,422)
Amortization of net (loss) gain	(1,151)	(2,187)
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	0	0
Prior service cost (credit)	0	0
Amortization of prior service (cost) credit	(1,980)	(1,980)
Total change in other comprehensive income for year	1,370	59,215
Qualified Plan | Pension Plan [Member] | Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss (gain)	(559)	(59,460)
Amortization of net (loss) gain	(12,877)	(14,917)
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	0	0
Prior service cost (credit)	0	0
Amortization of prior service (cost) credit	(1,573)	(1,573)
Total change in other comprehensive income for year	(10,745)	46,116
Nonqualified Plan | Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss (gain)	(6,756)	(1,122)
Amortization of net (loss) gain	(1,365)	(1,580)
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	0	(619)
Prior service cost (credit)	0	1,446
Amortization of prior service (cost) credit	331	42
Total change in other comprehensive income for year	5,060	327
Nonqualified Plan | Pension Plan [Member] | Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss (gain)	(6,756)	(1,122)
Amortization of net (loss) gain	(1,733)	(2,069)
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	0	(737)
Prior service cost (credit)	0	1,446
Amortization of prior service (cost) credit	333	44
Total change in other comprehensive income for year	$ 4,690	$ (282)

Retirement Benefits - Textuals

Retirement Benefits - Textuals (Details) - Forecast [Member]	12 Months Ended
	Dec. 31, 2020USD ($)
Other Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Net Gain (Loss)	$ (8,400,000)
Subsidiaries [Member] | Other Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Net Gain (Loss)	(200,000)
Qualified Plan | Subsidiaries [Member] | Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Net Gain (Loss)	(18,600,000)
Pension and Other Postretirement Benefit Plans, Net Prior Service Cost or Credit, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	1,600,000
Estimated Future Employer Contributions in Current Fiscal Year	18,000,000
Nonqualified Plan | Subsidiaries [Member] | Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Net Gain (Loss)	(2,600,000)
Pension and Other Postretirement Benefit Plans, Prior Service Cost, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	(300,000)
Estimated Future Employer Contributions in Current Fiscal Year	22,600,000
Other Pension Plan [Member] | Subsidiaries [Member] | Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Estimated Future Employer Contributions in Current Fiscal Year	$ 100,000

Retirement Benefits - Assumptio

Retirement Benefits - Assumptions (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Other Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	3.35%	4.40%		4.00%
Rate of compensation increase	4.50%	4.50%		4.50%
Medical trend rate1		7.60%		6.80%
Benefit Cost Assumptions
Discount rate	4.40%	4.40%	4.50%
Return on plan assets	7.00%	7.00%	6.75%
Rate of compensation increase	4.50%	4.50%	4.50%
Medical trend rate1		7.60%	9.50%
Nonqualified Plan | Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	3.35%	4.40%		4.00%
Rate of compensation increase	4.50%	4.50%		4.50%
Medical trend rate1	0.00%	0.00%		0.00%
Benefit Cost Assumptions
Discount rate	4.40%	4.40%	4.50%
Return on plan assets	0.00%	0.00%	0.00%
Rate of compensation increase	4.50%	4.50%	4.50%
Medical trend rate1	0.00%	0.00%	0.00%
Qualified Plan | Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	3.35%	4.40%		4.00%
Rate of compensation increase	4.50%	4.50%		4.50%
Medical trend rate1	0.00%	0.00%		0.00%
Benefit Cost Assumptions
Discount rate	4.40%	4.40%	4.50%
Return on plan assets	7.50%	7.50%	7.45%
Rate of compensation increase	4.50%	4.50%	4.50%
Medical trend rate1	0.00%	0.00%	0.00%

Retirement Benefits - Future Be

Retirement Benefits - Future Benefit Payments (Details) $ in Thousands	Dec. 31, 2019USD ($)
Other Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2020	$ 843
2021	826
2022	972
2023	937
2024	901
2025-2029	4,053
2020, without Medicare Part D subsidy	1,055
2021, without Medicare Part D subsidy	1,007
2022, without Medicare Part D subsidy	972
2023, without Medicare Part D subsidy	937
2024, without Medicare Part D subsidy	901
2025-2029, without Medicare Part D subsidy	4,053
Qualified Plan | Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2020	45,000
2021	45,200
2022	46,200
2023	47,900
2024	48,800
2025-2029	253,400
Nonqualified Plan | Pension Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2020	22,604
2021	1,940
2022	5,792
2023	3,663
2024	6,290
2025-2029	$ 21,283

Retirement Benefits - Plan Asse

Retirement Benefits - Plan Asset Allocation (Details)	12 Months Ended
	Dec. 31, 2019
Domestic Large Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	31.00%
Domestic Small Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	900.00%
Foreign Equity Funds [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	2500.00%
Fixed Income Securities [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	2500.00%
Real Estate Funds [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	0.00%
Absolute Return Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	1000.00%
Cash and cash equivalents
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	0.00%
Minimum | Domestic Large Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	25
Minimum | Domestic Small Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	—
Minimum | Foreign Equity Funds [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	10
Minimum | Fixed Income Securities [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	15
Minimum | Real Estate Funds [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	—
Minimum | Absolute Return Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	5
Minimum | Cash and cash equivalents
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	—
Maximum | Domestic Large Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	40
Maximum | Domestic Small Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	15
Maximum | Foreign Equity Funds [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	30
Maximum | Fixed Income Securities [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	30
Maximum | Real Estate Funds [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	10
Maximum | Absolute Return Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	15
Maximum | Cash and cash equivalents
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	5

Retirement Benefits - Recurring

Retirement Benefits - Recurring Fair Value Measures (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Other Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 6,289	$ 5,960	$ 7,138
Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	753,043	640,243
Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6,289	5,960
Mutual Funds | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	91,658	103,661
Mutual Funds | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6,201	5,910
Mutual Funds | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Mutual Funds | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Mutual Funds | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	91,658	103,661
Mutual Funds | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	6,201	5,910
Common Stock | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	224,146	177,949
Common Stock | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Common Stock | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	224,146	177,949
US Treasury and Government [Member] | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	34,916	0
US Treasury and Government [Member] | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
US Treasury and Government [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	34,916	0
Corporate Bond Securities [Member] | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Corporate Bond Securities [Member] | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Corporate Bond Securities [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash and cash equivalents | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	0	0
Cash and cash equivalents | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	150	702
Cash and cash equivalents | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	150	702
Equity Investments [Member] | Fair Value, Inputs, Level 1 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	350,720	281,610
Equity Investments [Member] | Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	150	702
Equity Investments [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	350,870	282,312
Fair Value Measurement [Domain] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Measurements, Recurring | Other Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	88	50
Fair Value Measurement [Domain] | Fair Value Measured at Net Asset Value Per Share [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	401,668	356,586
Net Receivables [Member] | Fair Value Measured at Net Asset Value Per Share [Member] | Fair Value, Measurements, Recurring | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 505	$ 1,345

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	May 01, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosures [Line Items]
Current Federal Tax Expense (Benefit)		$ 9,424	$ 10,382	$ 1,127
Current State and Local Tax Expense (Benefit)		164	263	17
Deferred Federal Income Tax Expense (Benefit)		7,357	19,451	254,420
Deferred State and Local Income Tax Expense (Benefit)		128	(4)	(421)
Total income tax expense		17,073	30,092	255,143
Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Current Federal Tax Expense (Benefit)		18,093	19,283	1,127
Current State and Local Tax Expense (Benefit)		570	438	17
Deferred Federal Income Tax Expense (Benefit)		20,485	30,979	210,842
Deferred State and Local Income Tax Expense (Benefit)		0	0	0
Total income tax expense	$ 34,600	$ 39,148	$ 50,700	$ 211,986

Income Taxes - Deferred Income

Income Taxes - Deferred Income Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Deferred Tax Liabilities, Gross
Deferred Tax Liabilities, Property, Plant and Equipment	$ 1,943,730	$ 1,998,721
Deferred Tax Liabilities, Other	133,440	113,051
Deferred Tax Liabilities, Gross, Total	2,077,170	2,111,772
Deferred Tax Assets, Gross
Deferred Tax Assets, Operating Loss Carryforwards	(238,869)	(224,885)
Deferred Tax Assets, Net Regulatory Liability for Income Taxes	(946,179)	(975,974)
Deferred Tax Assets, Tax Credit Carryforwards, Production	(67,402)	(121,616)
Deferred Tax Assets, Gross	(1,252,450)	(1,322,475)
Deferred Tax Liabilities, Net, Total	824,720	789,297
Subsidiaries [Member]
Deferred Tax Liabilities, Gross
Deferred Tax Liabilities, Property, Plant and Equipment	1,943,730	1,998,721
Deferred Tax Liabilities, Other	47,774	25,880
Deferred Tax Liabilities, Gross, Total	1,991,504	2,024,601
Deferred Tax Assets, Gross
Deferred Tax Assets, Net Regulatory Liability for Income Taxes	946,936	976,582
Deferred Tax Assets, Tax Credit Carryforwards, Production	67,405	121,616
Deferred Tax Assets, Gross	1,014,341	1,098,198
Deferred Tax Liabilities, Net, Total	$ 977,163	$ 926,403

Income Taxes - Balance Sheet Lo

Income Taxes - Balance Sheet Location (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosures [Line Items]
Deferred Tax Assets, Regulatory Assets and Liabilities, Accelerated Tax Depreciation	$ 919.8
Deferred Tax Assets, Regulatory Assets and Liabilities, Undetermined refund	91,900,000
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	0	$ 0	$ 117,185,000
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Revenue Change	51,200,000
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, effect on income tax expense	17,900,000
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Effect on Income Taxes due to revaluation	80,900,000
Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Deferred Tax Assets, Regulatory Assets and Liabilities	(1,012,300,000)		71.5
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	0	0	36,328,000
ARAM [Member]
Income Tax Disclosures [Line Items]
Deferred Other Tax Expense (Benefit)	$ 27,600,000	$ 29,800,000
Income Tax Reg Treatment [Member] | Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, PTC revaluation			33,300,000
Income Tax Non-Reg Treatment [Member] | Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, unregulated portion			$ 3,000,000

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	May 01, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating Loss Carryforwards [Line Items]
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount		$ 47,834	$ 55,800	$ 148,847
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depreciation and Amortization, Amount		(23,025)	(25,871)	0
Income Tax Reconciliation, AFUDC (net)		(4,462)	(4,173)	(4,506)
Income Tax Reconciliation, Executive Compensation		2,596	4,439	0
Income Tax Reconciliation, Treasury Grant		(7,870)	(4,861)	(9,537)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		0	0	117,185
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount		2,000	4,758	3,154
Income tax (benefit) expense		$ 17,073	$ 30,092	$ 255,143
Effective Income Tax Rate Reconciliation, Percent		7.50%	11300.00%	60000.00%
Subsidiaries [Member]
Operating Loss Carryforwards [Line Items]
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount		$ 69,735	$ 77,251	$ 185,430
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depreciation and Amortization, Amount		(23,025)	(25,871)	0
Income Tax Reconciliation, AFUDC (net)		(4,462)	(4,173)	(4,506)
Income Tax Reconciliation, Executive Compensation		2,596	4,439	0
Income Tax Reconciliation, Treasury Grant		(7,870)	(4,861)	(9,537)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		0	0	36,328
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount		2,174	3,915	4,271
Income tax (benefit) expense	$ 34,600	$ 39,148	$ 50,700	$ 211,986
Effective Income Tax Rate Reconciliation, Percent		11.80%	13.80%	40.00%

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
ARAM [Member]
Operating Loss Carryforwards [Line Items]
Deferred Other Tax Expense (Benefit)	$ 27.6	$ 29.8

Litigation (Details)

Litigation (Details) - Subsidiaries [Member]	Dec. 31, 2019unit	Dec. 10, 2019USD ($)MW
Colstrip Unit 4 [Member]
Jointly Owned Utility Plant Interests
Company’s Ownership Share	25.00%
Colstrip 4 Sale Amount | $		$ 1
Colstrip PPA | MW		90
Colstrip Units 1 & 2
Jointly Owned Utility Plant Interests
Company’s Ownership Share	50.00%
Number of Units | unit	2

Commitments and Contingencies_2

Commitments and Contingencies (Details)	12 Months Ended
	Dec. 31, 2019USD ($)MWhContractsMW	Dec. 31, 2018USD ($)MWh	Dec. 31, 2017USD ($)MWh
Long-term Purchase Commitment [Line Items]
Long-term Line of Credit, Noncurrent	$ 24,100,000	$ 11,900,000
Average cost of Company's energy output (US$ per kWh)	$ 0.033
Number of Public Utility Districts with long term purchase agreements | Contracts	3
Contract expenses	$ 87,135,000	$ 80,165,000	$ 73,827,000
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased	10.20%
Long-term Contract for Purchase of Electric Power, Capacity | MW	722
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost	$ 112,036,000
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required	18,609,000
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges	8,982,000
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding	155,859,000
Payment Obligations for Power Purchases
2020	574,442,000
2021	436,821,000
2022	409,907,000
2023	411,265,000
2024	418,569,000
Thereafter	1,579,295,000
Total	$ 3,830,299,000
Total energy obtained during period under purchased power contracts (MWh) | MWh	12.5	14.1	14.5
Cost incurred during period to provide energy under purchased power contracts	$ 550,600,000	$ 508,200,000	$ 456,400,000
Daily take obligation under long-term service contract (percent)	100.00%
Daily delivery obligation under long-term service contract (percent)	100.00%
Natural Gas [Member]
Payment Obligations for Power Purchases
2020	$ 273,263,000
2021	196,806,000
2022	178,208,000
2023	148,165,000
2024	82,509,000
Thereafter	0
Total	878,951,000
Colombia River Projects [Member]
Payment Obligations for Power Purchases
2020	121,680,000
2021	111,125,000
2022	103,879,000
2023	103,377,000
2024	102,976,000
Thereafter	609,912,000
Non-Utility Generators [Member]
Payment Obligations for Power Purchases
Total	216,913,000
Firm Transportation Service [Member]
Payment Obligations for Power Purchases
2020	176,741,000
2021	173,133,000
2022	172,190,000
2023	161,508,000
2024	116,842,000
Thereafter	828,136,000
Total	1,628,550,000
Firm Storage and Peaking Service [Member]
Payment Obligations for Power Purchases
2020	8,954,000
2021	4,503,000
2022	3,014,000
2023	853,000
2024	140,000
Thereafter	213,000
Total	17,677,000
Long-term Purchase Commitment, Demand Charges	125,100,000
Combustion turbines
Payment Obligations for Power Purchases
Long-term Purchase Commitment, Demand Charges	51,200,000
Energy production service contracts
Payment Obligations for Power Purchases
2020	28,474,000
2021	29,219,000
2022	29,923,000
2023	30,645,000
2024	31,400,000
Thereafter	141,817,000
Total	291,478,000
Automated meter reading system
Payment Obligations for Power Purchases
2020	43,971,000
2021	44,849,000
2022	45,526,000
2023	46,218,000
2024	46,926,000
Thereafter	96,149,000
Total	323,639,000
Service contract obligations
Payment Obligations for Power Purchases
2020	72,445,000
2021	74,068,000
2022	75,449,000
2023	76,863,000
2024	78,326,000
Thereafter	237,966,000
Total	615,117,000
Colombia River Projects [Member]
Payment Obligations for Power Purchases
Total	1,152,949,000
Other Utilities [Member]
Payment Obligations for Power Purchases
Total	2,460,437,000
Electric Portfolio
Payment Obligations for Power Purchases
2020	263,940,000
2021	300,795,000
2022	302,838,000
2023	307,888,000
2024	315,593,000
Thereafter	969,383,000
Firm natural gas supply
Payment Obligations for Power Purchases
2020	458,958,000
2021	374,442,000
2022	353,412,000
2023	310,526,000
2024	199,491,000
Thereafter	828,349,000
Total	$ 2,525,178,000
Minimum | Combustion turbines
Payment Obligations for Power Purchases
Remaining terms under contract	1 year
Maximum | Combustion turbines
Payment Obligations for Power Purchases
Remaining terms under contract	25
Rock Island Project
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased	25.00%
Long-term Contract for Purchase of Electric Power, Capacity | MW	156
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost	$ 34,180,000
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required	11,499,000
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges	5,681,000
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding	$ 96,956,000
Rocky Reach Project
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased	25.00%
Long-term Contract for Purchase of Electric Power, Capacity | MW	325
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost	$ 31,190,000
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required	4,940,000
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges	2,129,000
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding	$ 33,317,000
Wells Project [Member]
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased	27.10%
Long-term Contract for Purchase of Electric Power, Capacity | MW	228
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost	$ 43,004,000
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required	0
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges	0
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding	$ 0
Priest Rapids Development
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased	0.60%
Long-term Contract for Purchase of Electric Power, Capacity | MW	6
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost	$ 1,831,000
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required	1,085,000
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges	586,000
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding	$ 12,793,000
Wanapum Development
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased	0.60%
Long-term Contract for Purchase of Electric Power, Capacity | MW	7
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost	$ 1,831,000
Long-term Contract for Purchase of Electric Power, Annual Minimum Debt Service Payment Required	1,085,000
Long-term Contract for Purchase of Electric Power, Interest Included in Contract Charges	586,000
Long-term Contract for Purchase of Electric Power, Amount of Long-term Debt or Lease Obligation Outstanding	12,793,000
Electricity, US Regulated [Member]
Payment Obligations for Power Purchases
2020	188,822,000
2021	24,901,000
2022	3,190,000
2023	0
2024	0
Thereafter	$ 0

Segment Information (Details)

Segment Information (Details)	12 Months Ended
	Dec. 31, 2019mi²segment
Segment Reporting Information [Line Items]
Number of operating segments | segment	1
Subsidiaries [Member]
Segment Reporting Information [Line Items]
Area of service territory (sqmi) | mi²	6,000

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Loss) Changes in AOCI, net of tax (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	$ (77,202)
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	0	$ 5,230	$ 0
Accumulated other comprehensive income (loss), net of tax	(84,149)	(77,202)
Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(190,884)
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	0	(27,333)	0
Accumulated other comprehensive income (loss), net of tax	(188,477)	(190,884)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(77,202)	(24,282)	(33,712)
Other comprehensive income (loss) before reclassifications	(7,337)	(48,870)	10,251
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	390	1,180	(821)
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings		(5,230)
Net current-period other comprehensive income (loss)	(6,947)	(52,920)	9,430
Accumulated other comprehensive income (loss), net of tax	(84,149)	(77,202)	(24,282)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(185,130)	(121,867)	(140,155)
Other comprehensive income (loss) before reclassifications	(8,096)	(48,802)	10,200
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	10,118	11,772	8,088
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings		(26,233)
Net current-period other comprehensive income (loss)	2,022	(63,263)	18,288
Accumulated other comprehensive income (loss), net of tax	(183,108)	(185,130)	(121,867)
Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(77,202)	(24,282)	(33,712)
Other comprehensive income (loss) before reclassifications	(7,337)	(48,870)	10,251
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	390	1,180	(821)
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings		(5,230)
Net current-period other comprehensive income (loss)	(6,947)	(52,920)	9,430
Accumulated other comprehensive income (loss), net of tax	(84,149)	(77,202)	(24,282)
Comprehensive Income [Member] | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(190,884)	(126,906)	(145,511)
Other comprehensive income (loss) before reclassifications	(8,096)	(48,802)	10,200
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	10,503	12,157	8,405
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings		(27,333)
Net current-period other comprehensive income (loss)	2,407	(63,978)	18,605
Accumulated other comprehensive income (loss), net of tax	(188,477)	(190,884)	(126,906)
Interest Rate Swap [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member] | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(5,754)	(5,039)	(5,356)
Other comprehensive income (loss) before reclassifications		0	0
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	385	385	317
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings		(1,100)
Net current-period other comprehensive income (loss)	385	(715)	317
Accumulated other comprehensive income (loss), net of tax	$ (5,369)	$ (5,754)	$ (5,039)

Accumulated Other Comprehensi_4

Accumulated Other Comprehensive Income (Loss) Reclassifications Out of Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification of net unrealized loss on energy derivative instruments during the period, tax	$ 0	$ 0	$ 0
Reclassification out of Accumulated Other Comprehensive Income | Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Comprehensive income (loss)	(390)	(1,180)	821
Reclassification out of Accumulated Other Comprehensive Income | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Comprehensive income (loss)	(10,503)	(12,157)	(8,405)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Amortization of prior service (cost) credit	1,648	1,937	1,938
Amortization of net (loss) gain	(2,142)	(3,431)	(675)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax	(494)	(1,494)	1,263
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax	104	314	(442)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, after Tax	(390)	(1,180)	821
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Noncontrolling Interest [Member] | Interest Rate Swap [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax	(487)	(487)	(488)
Reclassification of net unrealized loss on energy derivative instruments during the period, tax	102	102	171
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	(385)	(385)	(317)
Accumulated Defined Benefit Plans Adjustment Attributable to Noncontrolling Interest [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Amortization of prior service (cost) credit	1,240	1,529	1,529
Amortization of net (loss) gain	(14,048)	(16,430)	(13,972)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax	(12,808)	(14,901)	(12,443)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax	2,690	3,129	4,355
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, after Tax	$ (10,118)	$ (11,772)	$ (8,088)

SUPPLEMENTAL QUARTERLY FINANC_3

SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Information [Line Items]
Operating revenue									$ 3,401,130,000	$ 3,346,496,000	$ 3,460,276,000
Operating Income (Loss)									519,008,000	554,058,000	739,106,000
Net Income (Loss) Attributable to Parent									210,708,000	235,622,000	175,194,000
Parent Company [Member]
Quarterly Financial Information [Line Items]
Operating revenue	$ 988,354,000	$ 627,007,000	$ 670,930,000	$ 1,114,839,000	$ 985,172,000	$ 651,464,000	$ 671,852,000	$ 1,038,008,000
Operating Income (Loss)	240,307,000	26,126,000	39,115,000	213,460,000	199,885,000	37,297,000	84,091,000	232,785,000
Net Income (Loss) Attributable to Parent	150,949,000	(39,443,000)	(32,952,000)	132,154,000	107,053,000	(21,970,000)	3,642,000	146,897,000	210,708,000	235,622,000	175,194,000
Subsidiaries [Member]
Quarterly Financial Information [Line Items]
Operating revenue	988,354,000	627,007,000	670,930,000	1,114,839,000	985,172,000	651,464,000	671,852,000	1,038,008,000	3,401,130,000	3,346,496,000	3,460,276,000
Operating Income (Loss)	241,955,000	26,721,000	39,780,000	214,159,000	193,432,000	46,147,000	81,701,000	235,856,000	522,615,000	557,136,000	740,595,000
Net Income (Loss) Attributable to Parent	$ 169,204,000	$ (15,257,000)	$ (8,325,000)	$ 147,302,000	$ 123,456,000	$ 3,891,000	$ 26,778,000	$ 163,037,000	$ 292,924,000	$ 317,162,000	$ 320,054,000

SCHEDULE I CONDENSED FINANCIA_2

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Statements of Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Condensed Financial Statements, Captions [Line Items]
Nonutility Expense And Other									$ (47,907)	$ (54,519)	$ (53,864)
Interest expense									(356,638)	(343,795)	(354,802)
Income Tax Expense (Benefit)									(17,073)	(30,092)	(255,143)
Net income (loss)									210,708	235,622	175,194
Comprehensive income (loss)									203,761	182,702	184,624
Condensed Cash Flow Statements, Captions [Line Items]
Net Cash Provided by (Used in) Operating Activities									527,336	904,181	972,131
Payments for (Proceeds from) Other Investing Activities									(6,908)	(2,097)	195
Net Cash Provided by (Used in) Investing Activities									(952,479)	(1,070,573)	(1,040,330)
Payments of Dividends									64,220	77,204	123,307
Proceeds from Issuance of Long-term Debt									689,351	804,050	90,120
Repayments of Long-term Debt									0	600,000	0
Net Cash Provided by (Used in) Financing Activities									435,727	185,193	63,664
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect									10,584	18,801	(4,535)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 66,146				$ 55,562				66,146	55,562	36,761	$ 41,296
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Nonutility Expense And Other									(1,495)	(1,345)	(1,466)
Equity In Net Income (Loss) Of Subsidiaries									294,724	320,122	323,568
Non-hedged interest rate derivative expense									0	0	28
Investment Income, Interest									6,643	4,273	1,039
Interest expense									(111,716)	(108,816)	(106,072)
Income Tax Expense (Benefit)									22,552	21,388	(41,903)
Net income (loss)	150,949	$ (39,443)	$ (32,952)	$ 132,154	107,053	$ (21,970)	$ 3,642	$ 146,897	210,708	235,622	175,194
Comprehensive income (loss)									203,761	182,702	184,624
Condensed Cash Flow Statements, Captions [Line Items]
Net Cash Provided by (Used in) Operating Activities									68,724	79,176	139,005
Adjustments to Additional Paid in Capital, Other									210,000	0	24,222
Payments for (Proceeds from) Loans Receivable from Subsidiary									41,708	59,864	78,155
Payments for (Proceeds from) Other Investing Activities									0	0	437
Net Cash Provided by (Used in) Investing Activities									(251,708)	(59,864)	(102,814)
Payments of Dividends									64,220	77,204	123,307
Proceeds from Issuance of Long-term Debt									246,200	209,300	0
Repayments of Long-term Debt									0	150,000	(90,120)
Issue costs and others									116	92	2,650
Net Cash Provided by (Used in) Financing Activities									181,864	(17,996)	(35,837)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect									(1,120)	1,316	354
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 947				$ 2,067				$ 947	$ 2,067	$ 751	$ 397

SCHEDULE I CONDENSED FINANCIA_3

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Other Property And Investments [Abstract]
Goodwill	$ 1,656,513	$ 1,656,513
Current assets:
Cash and Cash Equivalents, at Carrying Value	45,259	37,521
Total current assets	835,119	857,376
Assets, Noncurrent [Abstract]
Other	92,980	77,523
Total assets	14,659,863	14,098,861
Capitalization, Long-term Debt and Equity [Abstract]
Stockholders' Equity Attributable to Parent	4,000,299	3,860,758	$ 3,750,030	$ 3,688,713
Long-term debt	1,758,100	1,961,900
Total capitalization	9,920,624	9,533,249
Current liabilities:
Accounts payable	325,913	480,069
Interest	74,855	70,099
Deferred income taxes	824,720	789,297
Unrealized loss on derivative instruments	13,428	46,661
Total current liabilities	1,318,767	1,226,882
Liabilities, Noncurrent [Abstract]
Unrealized loss on derivative instruments	12,693	11,095
Total capitalization and liabilities	14,659,863	14,098,861
Current maturities of long-term debt	452,412	0
Parent Company [Member]
Assets
Investments in subsidiaries	4,153,618	3,820,347
Other Property And Investments [Abstract]
Goodwill	1,656,513	1,656,513
Current assets:
Cash and Cash Equivalents, at Carrying Value	947	2,067
Receivables from affiliates	180,527	138,714
Total current assets	181,474	140,781
Assets, Noncurrent [Abstract]
Deferred Tax Assets, Net of Valuation Allowance, Noncurrent	235,428	221,660
Other	2,056	2,040
Assets, Noncurrent, Total	237,484	223,700
Total assets	6,229,089	5,841,341
Capitalization, Long-term Debt and Equity [Abstract]
Stockholders' Equity Attributable to Parent	4,000,299	3,860,728
Long-term debt	1,752,644	1,954,205
Total capitalization	5,752,943	5,814,933
Current liabilities:
Accounts payable	208	260
Interest	25,938	26,148
Total current liabilities	476,146	26,408
Liabilities, Noncurrent [Abstract]
Total capitalization and liabilities	6,229,089	5,841,341
Current maturities of long-term debt	$ 450,000	$ 0

SCHEDULE I CONDENSED FINANCIA_4

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Statements of Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net Cash Provided by (Used in) Operating Activities	$ 527,336	$ 904,181	$ 972,131
Net Cash Provided by (Used in) Investing Activities
Payments for (Proceeds from) Other Investing Activities	(6,908)	(2,097)	195
Net Cash Provided by (Used in) Investing Activities	(952,479)	(1,070,573)	(1,040,330)
Net Cash Provided by (Used in) Financing Activities
Payments of Dividends	64,220	77,204	123,307
Proceeds from Issuance of Long-term Debt	689,351	804,050	90,120
Repayments of Long-term Debt	0	600,000	0
Net Cash Provided by (Used in) Financing Activities	435,727	185,193	63,664
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect	10,584	18,801	(4,535)
Cash, cash equivalents, and restricted cash at end of period	45,259	37,521
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	66,146	55,562	36,761	$ 41,296
Parent Company [Member]
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net Cash Provided by (Used in) Operating Activities	68,724	79,176	139,005
Net Cash Provided by (Used in) Investing Activities
Adjustments to Additional Paid in Capital, Other	(210,000)	0	(24,222)
Payments for (Proceeds from) Other Investing Activities	0	0	437
Net Cash Provided by (Used in) Investing Activities	(251,708)	(59,864)	(102,814)
Net Cash Provided by (Used in) Financing Activities
Payments of Dividends	64,220	77,204	123,307
Proceeds from Issuance of Long-term Debt	246,200	209,300	0
Repayments of Long-term Debt	0	150,000	(90,120)
Net Cash Provided by (Used in) Financing Activities	181,864	(17,996)	(35,837)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect	(1,120)	1,316	354
Cash, cash equivalents, and restricted cash at end of period	947	2,067
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 947	$ 2,067	$ 751	$ 397

SCHEDULE I CONDENSED FINANCIA_5

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY Notes (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net Income (Loss) Attributable to Parent									$ 210,708,000	$ 235,622,000	$ 175,194,000
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									203,761,000	182,702,000	184,624,000
Net Cash Provided by (Used in) Operating Activities									527,336,000	904,181,000	972,131,000
Net Cash Provided by (Used in) Investing Activities									(952,479,000)	(1,070,573,000)	(1,040,330,000)
Parent Company [Member]
Net Income (Loss) Attributable to Parent	$ 150,949,000	$ (39,443,000)	$ (32,952,000)	$ 132,154,000	$ 107,053,000	$ (21,970,000)	$ 3,642,000	$ 146,897,000	210,708,000	235,622,000	175,194,000
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									203,761,000	182,702,000	184,624,000
Net Cash Provided by (Used in) Operating Activities									68,724,000	79,176,000	139,005,000
Net Cash Provided by (Used in) Investing Activities									(251,708,000)	(59,864,000)	(102,814,000)
Subsidiaries [Member]
Net Income (Loss) Attributable to Parent	$ 169,204,000	$ (15,257,000)	$ (8,325,000)	$ 147,302,000	$ 123,456,000	$ 3,891,000	$ 26,778,000	$ 163,037,000	292,924,000	317,162,000	320,054,000
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									295,331,000	253,184,000	338,659,000
Net Cash Provided by (Used in) Operating Activities									623,924,000	995,904,000	1,086,803,000
Net Cash Provided by (Used in) Investing Activities									$ (912,363,000)	$ (1,008,409,000)	$ (963,411,000)

SCHEDULE II VALUATION AND QUALI

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) - SEC Schedule, 12-09, Allowance, Credit Loss [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount, Beginning Balance	$ 8,408	$ 8,901	$ 9,798
SEC Schedule, 12-09, Valuation Allowances and Reserves, Additions, Charge to Cost and Expense	17,633	24,846	26,266
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	17,747	25,339	27,163
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount, Ending Balance	$ 8,294	$ 8,408	$ 8,901