Puget Energy (PSD) 10-Q 1 Aug 19 2019 Q2 Quarterly report Financial data

Document And Entity Information

Document And Entity Information	6 Months Ended
	Jun. 30, 2019shares
Entity Information [Line Items]
Entity Registrant Name	PUGET ENERGY INC /WA
Entity Central Index Key	0001085392
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	200
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2019
Entity Emerging Growth Company	false
Entity Small Business	true
Entity Shell Company	false
Subsidiaries [Member]
Entity Information [Line Items]
Entity Registrant Name	PUGET SOUND ENERGY INC
Entity Central Index Key	0000081100
Current Fiscal Year End Date	--12-13
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	85,903,791
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2019
Entity Emerging Growth Company	false
Entity Small Business	true
Entity Shell Company	false

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Operating revenue:
Electric	$ 510,742	$ 501,510	$ 1,309,670	$ 1,201,196
Natural gas	153,457	160,196	458,125	490,480
Other	6,731	10,146	17,974	18,184
Total operating revenue	670,930	671,852	1,785,769	1,709,860
Energy costs:
Purchased electricity	124,001	129,114	394,703	283,320
Electric generation fuel	37,601	29,750	114,800	72,173
Residential exchange	(15,972)	(16,091)	(41,135)	(40,035)
Purchased natural gas	41,116	53,872	140,503	181,487
Unrealized (gain) loss on derivative instruments, net	30,332	(6,911)	15,145	(7,907)
Utility operations and maintenance	149,424	140,131	307,379	300,655
Non-utility expense and other	10,620	8,419	24,377	21,249
Depreciation and amortization	164,715	152,105	345,412	336,617
Conservation amortization	20,029	24,025	53,315	60,888
Taxes other than income taxes	69,949	73,347	178,695	184,535
Total operating expenses	631,815	587,761	1,533,194	1,392,982
Operating income (loss)	39,115	84,091	252,575	316,878
Other income (expense):
Other income	15,439	8,116	29,003	21,573
Other expense	(1,825)	(2,330)	(3,601)	(4,428)
Interest charges:
AFUDC	3,570	3,318	6,920	6,201
Interest expense	(87,770)	(86,084)	(175,786)	(174,410)
Income (loss) before income taxes	(31,471)	7,111	109,111	165,814
Income tax (benefit) expense	1,481	3,469	9,909	15,272
Net income (loss)	(32,952)	3,642	99,202	150,542
Subsidiaries [Member]
Operating revenue:
Electric	510,742	501,510	1,309,670	1,201,196
Natural gas	153,457	160,196	458,125	490,480
Other	6,731	10,146	17,974	18,184
Total operating revenue	670,930	671,852	1,785,769	1,709,860
Energy costs:
Purchased electricity	124,001	129,114	394,703	283,320
Electric generation fuel	37,601	29,750	114,800	72,173
Residential exchange	(15,972)	(16,091)	(41,135)	(40,035)
Purchased natural gas	41,116	53,872	140,503	181,487
Unrealized (gain) loss on derivative instruments, net	30,332	(6,911)	15,145	(7,907)
Utility operations and maintenance	149,424	140,131	307,379	300,655
Non-utility expense and other	9,978	10,834	23,055	20,614
Depreciation and amortization	164,692	152,080	345,370	336,570
Conservation amortization	20,029	24,025	53,315	60,888
Taxes other than income taxes	69,949	73,347	178,695	184,535
Total operating expenses	631,150	590,151	1,531,830	1,392,300
Operating income (loss)	39,780	81,701	253,939	317,560
Other income (expense):
Other income	12,412	8,113	22,961	15,756
Other expense	(1,825)	(2,330)	(3,601)	(4,428)
Interest charges:
AFUDC	3,570	3,318	6,920	6,201
Interest expense	(59,935)	(57,020)	(120,085)	(116,575)
Income (loss) before income taxes	(5,998)	33,782	160,134	218,514
Income tax (benefit) expense	2,327	7,004	21,157	28,696
Net income (loss)	$ (8,325)	$ 26,778	$ 138,977	$ 189,818

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Net income (loss)	$ (32,952)	$ 3,642	$ 99,202	$ 150,542
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	91	226	183	453
Reclassification of stranded taxes to retained earnings due to tax reform	0	0	0	(5,230)
Other comprehensive income (loss)	91	226	183	(4,777)
Comprehensive income (loss)	(32,861)	3,868	99,385	145,765
Subsidiaries [Member]
Net income (loss)	(8,325)	26,778	138,977	189,818
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	2,512	2,864	5,022	5,727
Amortization of treasury interest rate swaps to earnings, net of tax of $26 and $26, respectively	96	96	192	192
Reclassification of stranded taxes to retained earnings due to tax reform	0	0	0	(27,333)
Other comprehensive income (loss)	2,608	2,960	5,214	(21,414)
Comprehensive income (loss)	$ (5,717)	$ 29,738	$ 144,191	$ 168,404

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Net unrealized gain (loss) from pension and postretirement plans, net of tax	$ 25	$ 60	$ 50	$ 120
Subsidiaries [Member]
Net unrealized gain (loss) from pension and postretirement plans, net of tax	667	761	1,335	1,522
Amortization of treasury interest rate swaps to earnings, net of tax	$ 26	$ 26	$ 51	$ 51

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Utility plant (at original cost, including construction work in progress of $615,782 and $550,466 respectively):
Electric plant	$ 8,644,737	$ 8,515,482
Natural gas plant	3,746,984	3,598,732
Common plant	1,060,836	1,027,023
Less: Accumulated depreciation and amortization	(3,038,181)	(2,832,321)
Net utility plant	10,414,376	10,308,916
Other property and investments:
Goodwill	1,656,513	1,656,513
Other property and investments	267,421	244,444
Total other property and investments	1,923,934	1,900,957
Current assets:
Cash and cash equivalents	8,028	37,521
Restricted cash	15,970	18,041
Accounts receivable, net of allowance for doubtful accounts of $10,403 and $8,408, respectively	205,508	338,782
Unbilled revenue	135,385	205,285
Purchased gas adjustment receivable	144,917	9,921
Materials and supplies, at average cost	119,949	116,180
Fuel and natural gas inventory, at average cost	58,689	53,351
Unrealized gain on derivative instruments	23,525	46,507
Prepaid expense and other	26,123	25,674
Power contract acquisition adjustment gain	7,453	6,114
Total current assets	745,547	857,376
Other long-term and regulatory assets:
Power cost adjustment mechanism	22,311	4,735
Regulatory assets related to power contracts	15,169	16,693
Other regulatory assets	721,669	773,552
Unrealized gain on derivative instruments	3,249	2,512
Power contract acquisition adjustment gain	151,715	156,597
Operating lease right of use asset	172,278	0
Other	87,456	77,523
Total other long-term and regulatory assets	1,173,847	1,031,612
Total assets	14,257,704	14,098,861
Capitalization:
Common stock	0	0
Additional paid-in capital	3,308,957	3,308,957
Retained earnings	692,128	629,003
Accumulated other comprehensive income (loss), net of tax	(77,019)	(77,202)
Total common shareholder’s equity	3,924,066	3,860,758
Long-term debt:
First mortgage bonds and senior notes	3,764,412	3,764,412
Pollution control bonds	161,860	161,860
Long-term debt	1,981,900	1,961,900
Debt discount, issuance costs and other	(209,646)	(215,681)
Total long-term debt	5,698,526	5,672,491
Total capitalization	9,622,592	9,533,249
Current liabilities:
Accounts payable	277,120	480,069
Short-term debt	540,000	379,297
Accrued expenses:
Taxes	97,314	118,112
Salaries and wages	40,611	50,785
Interest	69,789	70,099
Unrealized loss on derivative instruments	40,695	46,661
Power contract acquisition adjustment loss	2,492	2,547
Operating lease liabilities	14,713	0
Other	128,805	79,312
Total current liabilities	1,211,539	1,226,882
Other long-term and regulatory liabilities:
Deferred income taxes	807,145	789,297
Unrealized loss on derivative instruments	8,451	11,095
Regulatory liabilities	722,080	747,203
Regulatory liability for deferred income taxes	960,423	975,974
Regulatory liabilities related to power contracts	159,168	162,711
Power contract acquisition adjustment loss	12,677	14,146
Operating lease liabilities	163,698	0
Other deferred credits	589,931	638,304
Total other long-term and regulatory liabilities	3,423,573	3,338,730
Commitments and contingencies (Note 8)
Total capitalization and liabilities	14,257,704	14,098,861
Subsidiaries [Member]
Utility plant (at original cost, including construction work in progress of $615,782 and $550,466 respectively):
Electric plant	10,708,173	10,587,231
Natural gas plant	4,310,729	4,164,489
Common plant	1,086,056	1,052,544
Less: Accumulated depreciation and amortization	(5,690,582)	(5,495,348)
Net utility plant	10,414,376	10,308,916
Other property and investments:
Other property and investments	80,139	76,986
Total other property and investments	80,139	76,986
Current assets:
Cash and cash equivalents	7,732	35,452
Restricted cash	15,970	18,041
Accounts receivable, net of allowance for doubtful accounts of $10,403 and $8,408, respectively	209,923	346,251
Unbilled revenue	135,385	205,285
Purchased gas adjustment receivable	144,917	9,921
Materials and supplies, at average cost	119,949	116,180
Fuel and natural gas inventory, at average cost	57,366	52,028
Unrealized gain on derivative instruments	23,525	46,507
Prepaid expense and other	26,123	25,674
Total current assets	740,890	855,339
Other long-term and regulatory assets:
Power cost adjustment mechanism	22,311	4,735
Other regulatory assets	721,669	773,552
Unrealized gain on derivative instruments	3,249	2,512
Operating lease right of use asset	172,278	0
Other	85,682	75,483
Total other long-term and regulatory assets	1,005,189	856,282
Total assets	12,240,594	12,097,523
Capitalization:
Common stock	859	859
Additional paid-in capital	3,275,105	3,275,105
Retained earnings	677,833	622,844
Accumulated other comprehensive income (loss), net of tax	(185,670)	(190,884)
Total common shareholder’s equity	3,768,127	3,707,924
Long-term debt:
First mortgage bonds and senior notes	3,764,412	3,764,417
Pollution control bonds	161,860	161,860
Debt discount, issuance costs and other	(30,595)	(31,417)
Total long-term debt	3,895,677	3,894,860
Total capitalization	7,663,804	7,602,784
Current liabilities:
Accounts payable	277,188	480,195
Short-term debt	540,000	379,297
Accrued expenses:
Taxes	97,314	117,993
Salaries and wages	40,611	50,785
Interest	43,763	43,951
Unrealized loss on derivative instruments	40,695	46,661
Operating lease liabilities	14,713	0
Other	128,805	79,312
Total current liabilities	1,183,089	1,198,194
Other long-term and regulatory liabilities:
Deferred income taxes	952,124	926,403
Unrealized loss on derivative instruments	8,451	11,095
Regulatory liabilities	720,757	745,880
Regulatory liability for deferred income taxes	961,214	976,582
Operating lease liabilities	163,698	0
Other deferred credits	587,457	636,585
Total other long-term and regulatory liabilities	3,393,701	3,296,545
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$ 12,240,594	$ 12,097,523

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
ASSETS
Construction work in progress	$ 615,782	$ 550,466
Current assets:
Allowance for doubtful accounts	$ 10,403	$ 8,408
Common shareholder’s equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,000	1,000
Common Stock, Shares, Outstanding	200	200
Subsidiaries [Member]
ASSETS
Construction work in progress	$ 615,782	$ 550,466
Current assets:
Allowance for doubtful accounts	$ 10,403	$ 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	85,903,791	85,903,791

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Operating activities:
Net income (loss)	$ 99,202	$ 150,542
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	345,412	336,617
Conservation amortization	53,315	60,888
Deferred income taxes and tax credits, net	2,248	10,567
Net unrealized (gain) loss on derivative instruments	15,145	(7,907)
AFUDC – equity	(6,591)	(7,146)
Production tax credit monetization	(41,111)	(51,181)
Other non-cash	7,427	7,377
Funding of pension liability	0	(9,000)
Regulatory assets and liabilities	(19,061)	4,591
Other long-term assets and liabilities	(13,238)	(12,611)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	203,174	220,207
Materials and supplies	(3,769)	(5,910)
Fuel and natural gas inventory	(5,338)	(1,176)
Prepayments and other	(85)	(1,422)
Purchased gas adjustment	(134,996)	22,594
Accounts payable	(179,533)	(47,040)
Taxes payable	(20,798)	(13,856)
Other	(10,692)	(16,937)
Net cash provided by (used in) operating activities	290,711	639,197
Investing activities:
Construction expenditures – excluding equity AFUDC	(470,335)	(490,623)
Other	(3,977)	1,956
Net cash provided by (used in) investing activities	(474,312)	(488,667)
Financing activities:
Change in short-term debt, net	160,703	(301,463)
Dividends paid	(36,077)	(55,525)
Proceeds from long-term debt and bonds issued	20,000	631,701
Redemption of bonds and notes	0	(450,000)
Other	7,411	6,196
Net cash provided by (used in) financing activities	152,037	(169,091)
Net increase (decrease) in cash, cash equivalents, and restricted cash	(31,564)	(18,561)
Cash, cash equivalents, and restricted cash at beginning of period	55,562	36,761
Cash, cash equivalents, and restricted cash at end of period	23,998	18,200
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	165,863	164,823
Cash payments (refunds) for income taxes	5,376	5,169
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	73,757	97,614
Subsidiaries [Member]
Operating activities:
Net income (loss)	138,977	189,818
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	345,370	336,570
Conservation amortization	53,315	60,888
Deferred income taxes and tax credits, net	8,967	18,519
Net unrealized (gain) loss on derivative instruments	15,145	(7,907)
AFUDC – equity	(6,591)	(7,146)
Production tax credit monetization	(41,111)	(51,181)
Other non-cash	2,210	2,197
Funding of pension liability	0	(9,000)
Regulatory assets and liabilities	(19,061)	4,591
Other long-term assets and liabilities	(9,822)	(5,956)
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	206,228	216,047
Materials and supplies	(3,769)	(5,910)
Fuel and natural gas inventory	(5,338)	(1,176)
Prepayments and other	(85)	(1,422)
Purchased gas adjustment	(134,996)	22,594
Accounts payable	(179,591)	(47,040)
Taxes payable	(20,679)	(12,971)
Other	(7,893)	(17,100)
Net cash provided by (used in) operating activities	341,276	684,415
Investing activities:
Construction expenditures – excluding equity AFUDC	(451,215)	(452,220)
Other	(3,977)	1,956
Net cash provided by (used in) investing activities	(455,192)	(450,264)
Financing activities:
Change in short-term debt, net	160,703	(301,463)
Dividends paid	(83,988)	(102,456)
Proceeds from long-term debt and bonds issued	0	594,750
Redemption of bonds and notes	0	(450,000)
Other	7,410	6,196
Net cash provided by (used in) financing activities	84,125	(252,973)
Net increase (decrease) in cash, cash equivalents, and restricted cash	(29,791)	(18,822)
Cash, cash equivalents, and restricted cash at beginning of period	53,493	36,009
Cash, cash equivalents, and restricted cash at end of period	23,702	17,187
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	112,058	112,354
Cash payments (refunds) for income taxes	9,784	9,631
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	73,757	97,614
Colstrip Regulatory Asset [Domain]
Non-cash financing and investing activities:
Reclassification of Colstrip from utility plant to a regulatory asset (Note 8)	47,516	0
Colstrip Regulatory Asset [Domain] | Subsidiaries [Member]
Non-cash financing and investing activities:
Reclassification of Colstrip from utility plant to a regulatory asset (Note 8)	$ (47,516)	$ 0

CONSOLIDATED STATEMENTS OF COMM

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY Statement - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	AOCI Attributable to Parent [Member]	Subsidiaries [Member]	Subsidiaries [Member]Common Stock [Member]	Subsidiaries [Member]Additional Paid-in Capital [Member]	Subsidiaries [Member]Retained Earnings [Member]	Subsidiaries [Member]AOCI Attributable to Parent [Member]
Common Stock, Shares, Outstanding at Dec. 31, 2017		200,000					85,903,791,000
Common Stock, Value, Outstanding at Dec. 31, 2017		$ 0					$ 859
Stockholders' Equity Attributable to Parent at Dec. 31, 2017	$ 3,750,030		$ 3,308,957	$ 465,355	$ (24,282)	$ 3,601,124		$ 3,275,105	$ 452,066	$ (126,906)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	146,897			146,897		163,037			163,037
Common stock dividend paid	(30,096)			30,096		(58,612)			58,612
Common stock dividend paid	(5,003)				(5,003)	(24,374)				(24,374)
Cumulative effect of accounting change	5,230			5,230		27,333			27,333
Common Stock, Shares, Outstanding at Mar. 31, 2018		200,000					85,903,791,000
Common Stock, Value, Outstanding at Mar. 31, 2018		$ 0					$ 859
Stockholders' Equity Attributable to Parent at Mar. 31, 2018	3,867,058		3,308,957	587,386	(29,285)	3,708,508		3,275,105	583,824	(151,280)
Common Stock, Shares, Outstanding at Dec. 31, 2017		200,000					85,903,791,000
Common Stock, Value, Outstanding at Dec. 31, 2017		$ 0					$ 859
Stockholders' Equity Attributable to Parent at Dec. 31, 2017	3,750,030		3,308,957	465,355	(24,282)	3,601,124		3,275,105	452,066	(126,906)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	150,542					189,818
Common stock dividend paid	(4,777)					(21,414)
Common Stock, Shares, Outstanding at Jun. 30, 2018		200,000					85,903,791,000
Common Stock, Value, Outstanding at Jun. 30, 2018		$ 0					$ 859
Stockholders' Equity Attributable to Parent at Jun. 30, 2018	3,845,497		3,308,957	565,599	(29,059)	3,694,402		3,275,105	566,758	(148,320)
Common Stock, Shares, Outstanding at Mar. 31, 2018		200,000					85,903,791,000
Common Stock, Value, Outstanding at Mar. 31, 2018		$ 0					$ 859
Stockholders' Equity Attributable to Parent at Mar. 31, 2018	3,867,058		3,308,957	587,386	(29,285)	3,708,508		3,275,105	583,824	(151,280)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	3,642			3,642		26,778			26,778
Common stock dividend paid	(25,429)			25,429		(43,844)			43,844
Common stock dividend paid	226				226	2,960				2,960
Common Stock, Shares, Outstanding at Jun. 30, 2018		200,000					85,903,791,000
Common Stock, Value, Outstanding at Jun. 30, 2018		$ 0					$ 859
Stockholders' Equity Attributable to Parent at Jun. 30, 2018	$ 3,845,497		3,308,957	565,599	(29,059)	$ 3,694,402		3,275,105	566,758	(148,320)
Common Stock, Shares, Outstanding at Dec. 31, 2018	200	200,000				85,903,791	85,903,791,000
Common Stock, Value, Outstanding at Dec. 31, 2018							$ 859
Stockholders' Equity Attributable to Parent at Dec. 31, 2018	$ 3,860,758		3,308,957	629,003	(77,202)	$ 3,707,924		3,275,105	622,844	(190,884)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	132,154			132,154		147,302			147,302
Common stock dividend paid	(35,994)			35,994		(64,604)			64,604
Common stock dividend paid	92				92	2,606				2,606
Common Stock, Shares, Outstanding at Mar. 31, 2019		200,000					85,903,791,000
Common Stock, Value, Outstanding at Mar. 31, 2019		$ 0					$ 859
Stockholders' Equity Attributable to Parent at Mar. 31, 2019	$ 3,957,010		3,308,957	725,163	(77,110)	$ 3,793,228		3,275,105	705,542	(188,278)
Common Stock, Shares, Outstanding at Dec. 31, 2018	200	200,000				85,903,791	85,903,791,000
Common Stock, Value, Outstanding at Dec. 31, 2018							$ 859
Stockholders' Equity Attributable to Parent at Dec. 31, 2018	$ 3,860,758		3,308,957	629,003	(77,202)	$ 3,707,924		3,275,105	622,844	(190,884)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	99,202					138,977
Common stock dividend paid	$ 183					$ 5,214
Common Stock, Shares, Outstanding at Jun. 30, 2019	200	200,000				85,903,791	85,903,791,000
Common Stock, Value, Outstanding at Jun. 30, 2019		$ 0					$ 859
Stockholders' Equity Attributable to Parent at Jun. 30, 2019	$ 3,924,066		3,308,957	692,128	(77,019)	$ 3,768,127		3,275,105	677,833	(185,670)
Common Stock, Shares, Outstanding at Mar. 31, 2019		200,000					85,903,791,000
Common Stock, Value, Outstanding at Mar. 31, 2019		$ 0					$ 859
Stockholders' Equity Attributable to Parent at Mar. 31, 2019	3,957,010		3,308,957	725,163	(77,110)	3,793,228		3,275,105	705,542	(188,278)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(32,952)			(32,952)		(8,325)			(8,325)
Common stock dividend paid	(83)			83		(19,384)			19,384
Common stock dividend paid	$ 91				91	$ 2,608				2,608
Common Stock, Shares, Outstanding at Jun. 30, 2019	200	200,000				85,903,791	85,903,791,000
Common Stock, Value, Outstanding at Jun. 30, 2019		$ 0					$ 859
Stockholders' Equity Attributable to Parent at Jun. 30, 2019	$ 3,924,066		$ 3,308,957	$ 692,128	$ (77,019)	$ 3,768,127		$ 3,275,105	$ 677,833	$ (185,670)

Summary of Consolidation and Si

Summary of Consolidation and Significant Accounting Policy	6 Months Ended
	Jun. 30, 2019
Accounting Policies [Abstract]
Summary of Consolidation and Significant Accounting Policy	Basis of Presentation Puget Energy is an energy services holding company that owns Puget Sound Energy. 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, which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma 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 FASB ASC 805, “Business Combinations”, as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any ASC 805, “Business Combinations” purchase accounting adjustments. The preparation of financial statements in conformity with U.S. 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. 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 early 2021. The Tacoma LNG facility is intended 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, the Puget Sound Clean Air Agency (PSCAA) determined a Supplemental Environmental Impact Statement (SEIS) is 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 may be impacted depending on the Puget Sound Clean Air Agency's timing and decision on the air quality permit. PSE received the SEIS which concluded the LNG facility would result in a net decrease in GHG emissions, provided in part that the natural gas for the facility was sourced from British Columbia or Alberta. PSE must now await the final determination by PSCAA. If delayed, the construction schedule and costs may be adversely impacted. Pursuant to an order by the Washington Utilities and Transportation Commission (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, $185.4 million of construction work in progress and $0.7 million of operating costs related to Puget LNG's portion of the Tacoma LNG facility are reported in the Puget Energy "Other property and investments" and "Non-utility expense and other" financial statement line items, respectively, as of June 30, 2019 . Additionally, $148.5 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 PSE is a regulated entity. 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 at commencement. As most of PSE's leases do not provide an implicit interest rate, PSE uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. For fleet, IT and wind farm leases, this rate is applied using a portfolio approach. The lease terms may include options to extend or terminate the lease when it is reasonably certain that PSE will exercise that option. On the statement of income, operating leases are generally accounted for under a straight-line expense model, while finance leases, which were previously referred to as capital leases, are generally accounted for under a financing model. Consistent with the previous lease guidance, however, the standard allows rate-regulated utilities to recognize expense consistent with the timing of recovery in rates. PSE has lease agreements with lease and non-lease components. Non-lease components comprise common area maintenance and utilities, and are accounted for separately from lease components.

New Accounting Pronouncements

New Accounting Pronouncements	6 Months Ended
	Jun. 30, 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 has 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 June 30, 2019 , in Note 9, "Leases", to the consolidated financial statements included in Item 1 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. 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 has not had 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 is currently evaluating the impact of adoption of the new standard on its 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 amendments in this update modify the disclosure requirements on fair value measurements in Topic 820, Fair Value Measurement, based on the concepts in the Concepts Statement, including the consideration of costs and benefits. The amendments are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The Company is in the process of evaluating potential impacts of these amendments to Note 5, "Fair Value Measurements", to the consolidated financial statements. 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 6, "Retirement Benefits", to the consolidated financial statements.

Revenue

Revenue	6 Months Ended
	Jun. 30, 2019
Revenue from Contract with Customer [Abstract]
Revenue	Revenue The following table presents disaggregated revenue from contracts with customers, and other revenue by major source: Puget Energy and Puget Sound Energy (Dollars in Thousands) Three Months Ended Six Months Ended Revenue from contracts with customers: 2019 2018 2019 2018 Electric retail $ 463,219 $ 468,378 $ 1,100,408 $ 1,099,184 Natural gas retail 145,222 158,544 467,782 492,578 Other 36,546 38,930 172,595 81,364 Total revenue from contracts with customers 644,987 665,852 1,740,785 1,673,126 Alternative revenue programs 4,351 (8,815 ) (20,880 ) (23,897 ) Other non-customer revenue 21,592 14,815 65,864 60,631 Total operating revenue $ 670,930 $ 671,852 $ 1,785,769 $ 1,709,860 Revenue at PSE is recognized when performance obligations under the terms of a contract or tariff with our customers are satisfied. Performance obligations are satisfied generally through performance of PSE's obligation over time or with transfer of control of electric power, natural gas, and other revenue from contracts with customers. Revenue is measured as the amount of consideration expected to be received in exchange for transferring goods and services. Electric and Natural Gas Retail Revenue Electric and natural gas retail revenue consists of tariff-based sales of electricity and natural gas to PSE's customers. For tariff contracts, PSE has elected the portfolio approach practical expedient model to apply the revenue from contracts with customers to groups of contracts. The Company determined that the portfolio approach will not differ from considering each contract or performance obligation separately. Electric and natural gas tariff contracts include the performance obligation of standing ready to perform electric and natural gas services. The electricity and natural gas the customer chooses to consume is considered an option and is recognized over time using the output method when the customer simultaneously consumes the electricity or natural gas. PSE has elected the right to invoice practical expedient for unbilled retail revenue. The obligation of standing ready to perform electric service and the consumption of electricity and natural gas at market value implies a right to consideration for performance completed to date. The Company believes that tariff prices approved by the Washington Commission represent stand-alone selling prices for the performance obligations under ASC 606. PSE collects Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes and presents the taxes on a gross basis, as PSE is the taxpayer for those excise and municipal taxes. Other Revenue from Contracts with Customers Other revenue from contracts with customers is primarily comprised of electric transmission, natural gas transportation, biogas, and wholesale revenue sold on an intra-month basis. Electric Transmission and Natural Gas Transportation Revenue Transmission and transportation tariff contracts include the performance obligation to transmit and transport electricity or natural gas. Transfer of control and recognition of revenue occurs over time as the customer simultaneously receives the transmission and transportation services. Measurement of satisfaction of this performance obligation is determined using the output method. Similar to retail revenue, the Company utilizes the right to invoice practical expedient as PSE’s right to consideration is tied directly to the value of power and natural gas transmitted and transported each month. The price is based on the tariff rates that were approved by the Washington Commission or the FERC and, therefore, corresponds directly to the value to the customer for performance completed to date. Biogas Revenue 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 Revenue 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.

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	6 Months Ended
	Jun. 30, 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 power cost adjustment (PCA). Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility of costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. PSE's hedging strategy includes a risk-responsive component for the core natural gas portfolio, which utilizes quantitative risk-based measures with defined objectives to balance both portfolio risk and hedge costs. PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. Currently, the Company does not apply cash flow hedge accounting and therefore records all mark-to-market gains or losses through earnings. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. The following table presents the volumes, fair values and classification of the Company's derivative instruments recorded on the balance sheets: Puget Energy and Puget Sound Energy At June 30, 2019 December 31, 2018 (Dollars in Thousands) Volumes Assets 1 Liabilities 2 Volumes Assets 1 Liabilities 2 Electric portfolio derivatives * $ 18,476 $ 27,617 * $ 33,287 $ 27,284 Natural gas derivatives (MMBtus) 3 293.7 million 8,298 21,529 336.6 million 15,732 30,472 Total derivative contracts $ 26,774 $ 49,146 $ 49,019 $ 57,756 Current $ 23,525 $ 40,695 $ 46,507 $ 46,661 Long-term 3,249 8,451 2,512 11,095 Total derivative contracts $ 26,774 $ 49,146 $ 49,019 $ 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 purchased gas adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 206.3 million One Million British Thermal Units (MMBtu) and purchased electricity of 10.2 million Megawatt Hours (MWhs) at June 30, 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 5, "Fair Value Measurements," to the consolidated financial statements included in Item 1 of this report. The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities: Puget Energy and Puget Sound Energy At June 30, 2019 Gross Amount Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position (Dollars in Thousands) Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 26,774 $ — $ 26,774 $ (19,661 ) $ — $ 7,113 Liabilities: Energy derivative contracts 49,146 — 49,146 (19,661 ) — 29,485 Puget Energy and Puget Sound Energy At December 31, 2018 Gross Amount Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position (Dollars in Thousands) Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 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. The following table presents the effect and classification of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income: Puget Energy and Three Months Ended Six Months Ended (Dollars in Thousands) Classification 2019 2018 2019 2018 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net $ (17,189 ) $ 5,357 $ (2,228 ) $ 7,669 Realized Electric generation fuel (1,333 ) (4,417 ) 11,995 (12,093 ) Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net (13,143 ) 1,554 (12,917 ) 238 Realized Purchased electricity 4,961 (2,836 ) 41,253 (5,225 ) Total gain (loss) recognized in income on derivatives $ (26,704 ) $ (342 ) $ 38,103 $ (9,411 ) The Company is exposed to credit risk primarily through buying and selling electricity and natural gas to serve its customers. Credit risk is the potential loss resulting from a counterparty's non-performance under an agreement. The Company manages credit risk with policies and procedures for, among other things, counterparty credit analysis, exposure measurement, and exposure monitoring and mitigation. The Company monitors counterparties for significant swings in credit default swap rates, credit rating changes by external rating agencies, ownership changes or financial distress. Where deemed appropriate, the Company may request collateral or other security from its counterparties to mitigate potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of June 30, 2019 , approximately 96.6% 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 3.4% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies. The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors in the determination of reserves, such as credit default swaps and bond spreads. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels. The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against the unrealized gain (loss) positions. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. PSE also transacts power futures contracts on the Intercontinental Exchange (ICE), and natural gas contracts on the ICE NGX exchange platform. Execution of contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of June 30, 2019 , PSE had cash posted as collateral of $5.8 million related to contracts executed on the ICE platform. Also, as of June 30, 2019 , PSE had $1.0 million in a letter of credit posted as a condition of transacting on the ICE NGX platform. PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades during the six months ended June 30, 2019 . 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 Puget Sound Energy (Dollars in Thousands) At June 30, 2019 At December 31, 2018 Fair Value 1 Posted Contingent Fair Value 1 Posted Contingent Contingent Feature Liability Collateral Collateral Liability Collateral Collateral Credit rating 2 $ 3,222 $ — $ 3,222 $ 574 $ — $ 574 Requested credit for adequate assurance 10,625 — — 18,495 — — Total $ 13,847 $ — $ 3,222 $ 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.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 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 totaling $50.5 million and $49.5 million at June 30, 2019 and December 31, 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 was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows: Puget Energy At June 30, 2019 At December 31, 2018 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Long-term debt (fixed-rate), net of discount 1 2 $ 5,516,626 $ 6,884,666 $ 5,510,591 $ 6,443,742 Long-term debt (variable-rate) 2 181,900 181,900 161,900 161,900 Total liabilities $ 5,698,526 $ 7,066,566 $ 5,672,491 $ 6,605,642 Puget Sound Energy At June 30, 2019 At December 31, 2018 (Dollars in Thousands) Level Carrying Fair Carrying Fair Liabilities: Long-term debt (fixed-rate), net of discount 2 2 $ 3,895,677 $ 4,981,972 $ 3,894,860 $ 4,574,611 Total liabilities $ 3,895,677 $ 4,981,972 $ 3,894,860 $ 4,574,611 _______________ 1 The carrying value includes debt issuances costs of $24.5 million and $26.1 million for June 30, 2019 and December 31, 2018 , respectively, which are not included in fair value. 2 The carrying value includes debt issuances costs of $23.9 million and $24.6 million for June 30, 2019 and December 31, 2018 , respectively, which are not included in fair value. Assets and Liabilities Measured at Fair Value on a Recurring Basis The following table presents the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis: Puget Energy and Puget Sound Energy Fair Value At June 30. 2019 Fair Value At December 31, 2018 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 17,093 $ 1,383 $ 18,476 $ 28,765 $ 4,522 $ 33,287 Natural gas derivative instruments 5,673 2,625 8,298 12,247 3,485 15,732 Total assets $ 22,766 $ 4,008 $ 26,774 $ 41,012 $ 8,007 $ 49,019 Liabilities: Electric derivative instruments $ 23,788 $ 3,829 $ 27,617 $ 24,124 $ 3,160 $ 27,284 Natural gas derivative instruments 21,302 227 21,529 28,660 1,812 30,472 Total liabilities $ 45,090 $ 4,056 $ 49,146 $ 52,784 $ 4,972 $ 57,756 The following table presents the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy and Puget Sound Energy Three Months Ended (Dollars in Thousands) 2019 2018 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ 5,012 $ 2,758 $ 7,770 $ 1,186 $ 5,096 $ 6,282 Changes during period: Realized and unrealized energy derivatives: Included in earnings 1 (6,190 ) — (6,190 ) 366 — 366 Included in regulatory assets / liabilities — 382 382 — 354 354 Settlements 574 (1,619 ) (1,045 ) (151 ) (1,800 ) (1,951 ) Transferred into Level 3 — — — — — — Transferred out of Level 3 (1,842 ) 877 (965 ) 608 299 907 Balance at end of period $ (2,446 ) $ 2,398 $ (48 ) $ 2,009 $ 3,949 $ 5,958 Puget Energy and Puget Sound Energy Six Months Ended (Dollars in Thousands) 2019 2018 Level 3 Roll-Forward Net Asset/(Liability) 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 Changes during period: Realized and unrealized energy derivatives: Included in earnings 2 6,135 — 6,135 1,985 — 1,985 Included in regulatory assets / liabilities — 2,279 2,279 — 5,329 5,329 Settlements (12,909 ) (2,718 ) (15,627 ) (654 ) (3,602 ) (4,256 ) Transferred into Level 3 4,391 (398 ) 3,993 (1,837 ) — (1,837 ) Transferred out of Level 3 (1,425 ) 1,562 137 1,417 299 1,716 Balance at end of period $ (2,446 ) $ 2,398 $ (48 ) $ 2,009 $ 3,949 $ 5,958 _______________ 1. Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(4.7) million and $0.7 million for the three months ended June 30, 2019 and 2018 , respectively. 2. Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(2.4) million and $1.7 million for the six months ended June 30, 2019 and 2018 , respectively. Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company's consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company's consolidated statements of income. 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 tables. The Company did not have any transfers between Level 1 and Level 2 during the reported periods. 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 forward 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. The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of June 30, 2019 : Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 1,383 $ 3,829 Discounted cash flow Power prices (per MWh) $ 8.95 $ 49.85 $ 34.16 Natural gas $ 2,625 $ 227 Discounted cash flow Natural gas prices (per MMBtu) $ 1.75 $ 2.67 $ 2.03 _______________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2018 : Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 4,522 $ 3,160 Discounted cash flow Power prices (per MWh) $ 11.35 $ 66.45 $ 29.63 Natural gas $ 3,485 $ 1,812 Discounted cash flow Natural gas prices (per MMBtu) $ 1.84 $ 5.80 $ 3.18 ____________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently, significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. As of June 30, 2019 and December 31, 2018 , a hypothetical 10.0% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $1.8 million and $2.6 million , respectively. Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis Puget Energy records the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle. ASC 360 requires long-lived assets to be tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. One such triggering event is a significant decrease in the forward market prices of power. As of June 30, 2019 , Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets and found no impairment. 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.

Retirement Benefits

Retirement Benefits	6 Months Ended
	Jun. 30, 2019
Retirement Benefits [Abstract]
Retirement Benefits	Retirement Benefits PSE has a defined benefit pension plan (Qualified Pension Benefits) covering a substantial majority of PSE employees. PSE also maintains a non-qualified supplemental executive retirement plan (SERP) for its key senior management employees. In addition to providing pension benefits, PSE provides legacy group health care and life insurance benefits (Other Benefits) for certain retired employees. Puget Energy's retirement plans were re-measured as a result of the merger in 2009, which represents the difference between Puget Energy and PSE's retirement plans. The following tables summarize the Company’s net periodic benefit cost for the three months and six months ended June 30, 2019 and 2018 : Puget Energy Qualified SERP Other Three Months Ended June 30, (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Components of net periodic benefit cost: Service cost $ 5,287 $ 5,425 $ 256 $ 212 $ 16 $ 17 Interest cost 7,216 6,780 578 530 112 110 Expected return on plan assets (12,624 ) (12,559 ) — — (98 ) (117 ) Amortization of prior service cost (495 ) (495 ) 83 11 — — Amortization of net loss (gain) 251 462 341 394 (63 ) (86 ) Net periodic benefit cost $ (365 ) $ (387 ) $ 1,258 $ 1,147 $ (33 ) $ (76 ) Puget Energy Qualified SERP Other Six Months Ended June 30, (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Components of net periodic benefit cost: Service cost $ 10,574 $ 10,851 $ 512 $ 423 $ 33 $ 35 Interest cost 14,433 13,560 1,157 1,060 224 220 Expected return on plan assets (25,248 ) (25,119 ) — — (195 ) (235 ) Amortization of prior service cost (990 ) (990 ) 166 22 — — Amortization of net loss (gain) 501 925 683 790 (125 ) (172 ) Net periodic benefit cost $ (730 ) $ (773 ) $ 2,518 $ 2,295 $ (63 ) $ (152 ) Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Three Months Ended June 30, (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Components of net periodic benefit cost: Service cost $ 5,287 $ 5,425 $ 256 $ 212 $ 16 $ 17 Interest cost 7,216 6,780 578 530 112 110 Expected return on plan assets (12,628 ) (12,569 ) — — (98 ) (117 ) Amortization of prior service cost (393 ) (393 ) 83 11 — — Amortization of net loss (gain) 3,165 3,630 433 517 (109 ) (142 ) Net periodic benefit cost $ 2,647 $ 2,873 $ 1,350 $ 1,270 $ (79 ) $ (132 ) Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Six Months Ended June 30, (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Components of net periodic benefit cost: Service cost $ 10,574 $ 10,851 $ 512 $ 423 $ 33 $ 35 Interest cost 14,433 13,560 1,157 1,060 224 220 Expected return on plan assets (25,257 ) (25,138 ) — — (195 ) (235 ) Amortization of prior service cost (787 ) (787 ) 167 22 — — Amortization of net loss (gain) 6,330 7,260 866 1,035 (219 ) (283 ) Net periodic benefit cost $ 5,293 $ 5,746 $ 2,702 $ 2,540 $ (157 ) $ (263 ) The following table summarizes the Company’s change in benefit obligation for the periods ended June 30, 2019 and December 31, 2018 : Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Six Months Ended Year Six Months Ended Year Six Months Ended Year (Dollars in Thousands) June 30, December 31, June 30, December 31, June 30, December 31, 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 — — Service cost 10,574 22,757 512 847 33 69 Interest cost 14,433 27,303 1,157 2,120 224 444 Actuarial loss (gain) — (29,067 ) — 1,122 — (379 ) Benefits paid (21,850 ) (42,662 ) (1,007 ) (5,581 ) (524 ) (1,037 ) Medicare part D subsidy received — — — — 226 85 Administrative Expense — (1,169 ) — — — — Benefit obligation at end of period $ 680,800 $ 677,643 $ 56,370 $ 55,708 $ 10,595 $ 10,636 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, 2019 are expected to be at least $18.0 million , $6.2 million and $0.3 million , respectively. During the three months ended June 30, 2019 the Company contributed $0.5 million to fund the SERP. During the six months ended June 30, 2019 the Company contributed $1.0 million to fund the SERP. The Company contributed an immaterial amount to fund the other postretirement plans.

Regulation and Rates

Regulation and Rates	6 Months Ended
	Jun. 30, 2019
Regulation and Rates [Abstract]
Regulation and Rates	Regulation and Rates General Rate Case PSE filed a general rate case (GRC) with the Washington Commission on June 20, 2019 requesting an overall increase in electric and natural gas rates of 6.9% and 7.9% respectively. PSE requested a return on equity of 9.8% with an overall rate of return of 7.62% . In addition to the traditional areas of focus (revenue requirements, cost allocation, rate design and cost of capital), the company included an attrition adjustment mechanism to address the expected regulatory lag in the rate year. Additionally, as the non-plant related excess deferred taxes that resulted from the Tax Cuts and Jobs Act (TCJA) remained outstanding from PSE’s Expedited Rate Filing (ERF) as discussed below, PSE requested in its general rate case to pass back the amounts over four years. PSE awaits suspension of the filing and for the Commission to set a procedural calendar. Expedited Rate Filing On November 7, 2018, PSE filed an ERF with the Washington Commission. The filing requested to change rates associated with PSE’s delivery and fixed production costs. It did not include variable power costs, purchased gas costs or natural gas pipeline replacement program costs, which are recovered in separate mechanisms. The filing was based on historical test year costs and rate base, and followed the reporting requirements of a Commission Basis Report, as defined by the Washington Administrative Code, but used end of period rate base and certain annualizing adjustments. It did not include any forward-looking or pro-forma adjustments. Included in the filing was a reduction to the overall authorized rate of return from 7.6% to 7.49% to recognize a reduction in debt costs associated with recent debt activity. PSE requested an overall increase in electric rates of $18.9 million annually, which is a 0.9% increase, and an overall increase in natural gas rates of $21.7 million annually, which is a 2.7% increase. On January 22, 2019, all parties in the proceeding reached an agreement on settlement terms that resolved all issues in the filing. The settlement agreement was filed on January 30, 2019. The parties agreed to a $21.5 million annual increase for natural gas and no rate increase for electric which became effective March 1, 2019. As is discussed below, these rates include the offsetting effect of passing back to customers plant related excess deferred income taxes that resulted from the Tax Cuts and Jobs Act (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 and $25.9 million for electric. 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, 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 next GRC. The rate of return adopted in the settlement for reporting and deferral purposes is 7.49% . On February 21, 2019, the Commission approved the settlement with one condition. The settlement requires that PSE pass back the deferred balance associated with the tax over-collection for the period from January 1, 2018 through April 30, 2018, discussed in item 2 above over a one-year period which began May 1, 2019. Washington Commission Tax Deferral Filing The Tax Cuts and Jobs Act (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 results in the tax rate change being captured in the deferred income tax balance with an offset to the regulatory liability for deferred income taxes for GAAP purposes. Additionally, on March 30, 2018, PSE filed for a rate change for electric and natural gas customers associated with TCJA to reflect the decrease in the federal corporate income tax rate from 35.0% to 21.0%. The overall impact of the rate change, based on the annual period from May 2018 through April 2019, is a revenue decrease of $72.9 million , or 3.4% for electric and $23.6 million , or 2.7% for natural gas and became effective May 1, 2018 by operation of law. The March 30, 2018, rate change filing did not address excess deferred taxes or the deferred balance associated with the over-collection of income tax expense of $34.6 million for the period January 1 through April 30, 2018 (the time period that encompasses the effective date of the TCJA through May 1, 2018, the effective date of the rate change). The $34.6 million tax over-collection decreased PSE's revenue and increased the regulatory liability for a refund to customers. As a result of the Washington Commission’s final order in the ERF, the excess deferred taxes associated with non-plant-related book/tax differences and the treatment of the excess deferred taxes associated with plant related book/tax differences from January 1, 2018 through February 28, 2019 will be addressed in PSE’s next GRC, which was filed June 20, 2019. The 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 June 30, 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 all of 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. Electric Regulation and Rates 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 six months ended June 30, 2019 , PSE incurred $39.2 million in storm-related electric transmission and distribution system restoration costs, of which the Company deferred $0.4 million and $28.3 million as regulatory assets related to storms that occurred in 2018 and 2019 , respectively. This compares to $8.9 million incurred in storm-related electric transmission and distribution system restoration costs for the six months ended June 30, 2018 , of which no amount was deferred to a regulatory asset. 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.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Colstrip PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in 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, 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. On June 11, 2019, Talen made a public announcement that Colstrip 1 and 2 will be shut down at the end of the year due to operational losses associated with the Units. The regulatory asset associated with early retirement of Colstrip Units 1 and 2 increased from $130.7 million as of December 31, 2018 to $178.2 million as of June 30, 2019 . The Washington Clean Energy Transition Act requires the WUTC 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. Other Commitments and Contingencies There have been no material changes to the contractual obligations and consolidated commercial commitments disclosed in Note 16, "Commitments and Contingencies" to the consolidated financial statements included in Item 8 of the Company's Form 10-K for the period ended December 31, 2018 .

Leases (Notes)

Leases (Notes)	6 Months Ended
	Jun. 30, 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 26 years, some of which include options to extend the leases for up to 25 years. The components of lease expense were as follows: Puget Energy and Three Months Ended June 30, Six Months Ended (Dollars in Thousands) 2019 2019 Finance lease cost: Amortization of right-of-use asset $ 124 $ 282 Interest on lease liabilities 10 19 Total finance lease cost $ 134 $ 301 Operating lease cost 1 $ 5,223 $ 10,007 _______________ 1 Includes $0.5 million allocated to PLNG at PE related to the Tacoma land lease. Supplemental cash flow information related to leases was as follows: Puget Energy and Three Months Ended June 30, Six Months Ended (Dollars in Thousands) 2019 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ (4,785 ) $ (9,131 ) Investing cash flow for operating leases 1 (438 ) (876 ) Operating cash flow for finance leases (10 ) (19 ) Financing cash flows for finances leases (124 ) (282 ) _______________ 1 Includes $0.5 million allocated to PLNG at PE related to the Tacoma land lease. Supplemental balance sheet information related to leases was as follows: Puget Sound Energy (Dollars in Thousands) At June 30, Operating Leases 2019 Operating lease right-of-use asset $ 172,278 Operating leases liabilities current $ (14,713 ) Operating lease liabilities long-term (163,698 ) Total Operating lease liabilities: $ (178,411 ) Finance Leases Common Plant $ 1,397 Other current liabilities $ (599 ) Other deferred credits (813 ) Total finance lease liabilities $ (1,412 ) Weighted Average Remaining Lease Term Operating leases 13.30 years Finance leases 2.89 years Weighted Average Discount Rate Operating leases 3.77 % Finance leases 2.98 % The following tables summarize the Company’s estimated future minimum lease payments as of June 30, 2019 , and December 31, 2018 , respectively: Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At June 30, Operating Leases Finance Leases 2019 (remaining six months) $ 11,822 $ 308 2020 21,506 545 2021 21,762 409 2022 20,800 181 2023 20,716 24 Thereafter 134,067 — Total lease payments 230,673 1,467 Less imputed interest (52,262 ) (55 ) Total $ 178,411 $ 1,412 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 minimum lease payments $ 234,283 $ 1,334
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 26 years, some of which include options to extend the leases for up to 25 years. The components of lease expense were as follows: Puget Energy and Three Months Ended June 30, Six Months Ended (Dollars in Thousands) 2019 2019 Finance lease cost: Amortization of right-of-use asset $ 124 $ 282 Interest on lease liabilities 10 19 Total finance lease cost $ 134 $ 301 Operating lease cost 1 $ 5,223 $ 10,007 _______________ 1 Includes $0.5 million allocated to PLNG at PE related to the Tacoma land lease. Supplemental cash flow information related to leases was as follows: Puget Energy and Three Months Ended June 30, Six Months Ended (Dollars in Thousands) 2019 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ (4,785 ) $ (9,131 ) Investing cash flow for operating leases 1 (438 ) (876 ) Operating cash flow for finance leases (10 ) (19 ) Financing cash flows for finances leases (124 ) (282 ) _______________ 1 Includes $0.5 million allocated to PLNG at PE related to the Tacoma land lease. Supplemental balance sheet information related to leases was as follows: Puget Sound Energy (Dollars in Thousands) At June 30, Operating Leases 2019 Operating lease right-of-use asset $ 172,278 Operating leases liabilities current $ (14,713 ) Operating lease liabilities long-term (163,698 ) Total Operating lease liabilities: $ (178,411 ) Finance Leases Common Plant $ 1,397 Other current liabilities $ (599 ) Other deferred credits (813 ) Total finance lease liabilities $ (1,412 ) Weighted Average Remaining Lease Term Operating leases 13.30 years Finance leases 2.89 years Weighted Average Discount Rate Operating leases 3.77 % Finance leases 2.98 % The following tables summarize the Company’s estimated future minimum lease payments as of June 30, 2019 , and December 31, 2018 , respectively: Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At June 30, Operating Leases Finance Leases 2019 (remaining six months) $ 11,822 $ 308 2020 21,506 545 2021 21,762 409 2022 20,800 181 2023 20,716 24 Thereafter 134,067 — Total lease payments 230,673 1,467 Less imputed interest (52,262 ) (55 ) Total $ 178,411 $ 1,412 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 minimum lease payments $ 234,283 $ 1,334

Other

Other	6 Months Ended
	Jun. 30, 2019
Other [Abstract]
Other	Other Long-Term Debt In April 2019, Puget Energy entered into an additional $24.0 million of supplemental loans under the expansion feature of the term loan agreement with the existing lenders. All other terms and conditions of the agreement remain unchanged. The proceeds from the term loan and supplemental loans will be used to repay borrowings under the revolving credit facility, which carries a higher interest rate. For further information, see Note 7, "Long-Term Debt" and Note 8, "Liquidity Facilities and Other Financing Arrangements" in the Company's most recent Annual Report on Form 10K for the year ended December 31, 2018.

Summary of Consolidation and _2

Summary of Consolidation and Significant Accounting Policy (Policies)	6 Months Ended
	Jun. 30, 2019
Accounting Policies [Abstract]
Significant Accounting Policies	Summary of Consolidation and Significant Accounting Policy Basis of Presentation Puget Energy is an energy services holding company that owns Puget Sound Energy. 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, which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma 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 FASB ASC 805, “Business Combinations”, as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any ASC 805, “Business Combinations” purchase accounting adjustments. The preparation of financial statements in conformity with U.S. 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. 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 early 2021. The Tacoma LNG facility is intended 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, the Puget Sound Clean Air Agency (PSCAA) determined a Supplemental Environmental Impact Statement (SEIS) is 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 may be impacted depending on the Puget Sound Clean Air Agency's timing and decision on the air quality permit. PSE received the SEIS which concluded the LNG facility would result in a net decrease in GHG emissions, provided in part that the natural gas for the facility was sourced from British Columbia or Alberta. PSE must now await the final determination by PSCAA. If delayed, the construction schedule and costs may be adversely impacted. Pursuant to an order by the Washington Utilities and Transportation Commission (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, $185.4 million of construction work in progress and $0.7 million of operating costs related to Puget LNG's portion of the Tacoma LNG facility are reported in the Puget Energy "Other property and investments" and "Non-utility expense and other" financial statement line items, respectively, as of June 30, 2019 . Additionally, $148.5 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 PSE is a regulated entity. 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 at commencement. As most of PSE's leases do not provide an implicit interest rate, PSE uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. For fleet, IT and wind farm leases, this rate is applied using a portfolio approach. The lease terms may include options to extend or terminate the lease when it is reasonably certain that PSE will exercise that option. On the statement of income, operating leases are generally accounted for under a straight-line expense model, while finance leases, which were previously referred to as capital leases, are generally accounted for under a financing model. Consistent with the previous lease guidance, however, the standard allows rate-regulated utilities to recognize expense consistent with the timing of recovery in rates. PSE has lease agreements with lease and non-lease components. Non-lease components comprise common area maintenance and utilities, and are accounted for separately from lease components.

Revenue (Tables)

Revenue (Tables)	6 Months Ended
	Jun. 30, 2019
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	The following table presents disaggregated revenue from contracts with customers, and other revenue by major source: Puget Energy and Puget Sound Energy (Dollars in Thousands) Three Months Ended Six Months Ended Revenue from contracts with customers: 2019 2018 2019 2018 Electric retail $ 463,219 $ 468,378 $ 1,100,408 $ 1,099,184 Natural gas retail 145,222 158,544 467,782 492,578 Other 36,546 38,930 172,595 81,364 Total revenue from contracts with customers 644,987 665,852 1,740,785 1,673,126 Alternative revenue programs 4,351 (8,815 ) (20,880 ) (23,897 ) Other non-customer revenue 21,592 14,815 65,864 60,631 Total operating revenue $ 670,930 $ 671,852 $ 1,785,769 $ 1,709,860

Accounting for Derivative Ins_2

Accounting for Derivative Instruments and Hedging Activities (Tables)	6 Months Ended
	Jun. 30, 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 Puget Sound Energy At June 30, 2019 December 31, 2018 (Dollars in Thousands) Volumes Assets 1 Liabilities 2 Volumes Assets 1 Liabilities 2 Electric portfolio derivatives * $ 18,476 $ 27,617 * $ 33,287 $ 27,284 Natural gas derivatives (MMBtus) 3 293.7 million 8,298 21,529 336.6 million 15,732 30,472 Total derivative contracts $ 26,774 $ 49,146 $ 49,019 $ 57,756 Current $ 23,525 $ 40,695 $ 46,507 $ 46,661 Long-term 3,249 8,451 2,512 11,095 Total derivative contracts $ 26,774 $ 49,146 $ 49,019 $ 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 purchased gas adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 206.3 million One Million British Thermal Units (MMBtu) and purchased electricity of 10.2 million Megawatt Hours (MWhs) at June 30, 2019 , and 194.8 million MMBtus and 6.6 million MWhs at December 31, 2018 .
Offsetting Assets and Liabilities	The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities: Puget Energy and Puget Sound Energy At June 30, 2019 Gross Amount Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position (Dollars in Thousands) Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 26,774 $ — $ 26,774 $ (19,661 ) $ — $ 7,113 Liabilities: Energy derivative contracts 49,146 — 49,146 (19,661 ) — 29,485 Puget Energy and Puget Sound Energy At December 31, 2018 Gross Amount Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position (Dollars in Thousands) Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 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.
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance	The following table presents the effect and classification of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income: Puget Energy and Three Months Ended Six Months Ended (Dollars in Thousands) Classification 2019 2018 2019 2018 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net $ (17,189 ) $ 5,357 $ (2,228 ) $ 7,669 Realized Electric generation fuel (1,333 ) (4,417 ) 11,995 (12,093 ) Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net (13,143 ) 1,554 (12,917 ) 238 Realized Purchased electricity 4,961 (2,836 ) 41,253 (5,225 ) Total gain (loss) recognized in income on derivatives $ (26,704 ) $ (342 ) $ 38,103 $ (9,411 )
Schedule of Credit Risk Related Contingent Features	The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post: Puget Energy and Puget Sound Energy (Dollars in Thousands) At June 30, 2019 At December 31, 2018 Fair Value 1 Posted Contingent Fair Value 1 Posted Contingent Contingent Feature Liability Collateral Collateral Liability Collateral Collateral Credit rating 2 $ 3,222 $ — $ 3,222 $ 574 $ — $ 574 Requested credit for adequate assurance 10,625 — — 18,495 — — Total $ 13,847 $ — $ 3,222 $ 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.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2019
Fair Value Disclosures [Abstract]
Fair Value Inputs, Liabilities, Quantitative Information	The fair value of the junior subordinated and long-term notes was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows: Puget Energy At June 30, 2019 At December 31, 2018 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Long-term debt (fixed-rate), net of discount 1 2 $ 5,516,626 $ 6,884,666 $ 5,510,591 $ 6,443,742 Long-term debt (variable-rate) 2 181,900 181,900 161,900 161,900 Total liabilities $ 5,698,526 $ 7,066,566 $ 5,672,491 $ 6,605,642 Puget Sound Energy At June 30, 2019 At December 31, 2018 (Dollars in Thousands) Level Carrying Fair Carrying Fair Liabilities: Long-term debt (fixed-rate), net of discount 2 2 $ 3,895,677 $ 4,981,972 $ 3,894,860 $ 4,574,611 Total liabilities $ 3,895,677 $ 4,981,972 $ 3,894,860 $ 4,574,611 _______________ 1 The carrying value includes debt issuances costs of $24.5 million and $26.1 million for June 30, 2019 and December 31, 2018 , respectively, which are not included in fair value. 2 The carrying value includes debt issuances costs of $23.9 million and $24.6 million for June 30, 2019 and December 31, 2018 , respectively, which are not included in fair value.
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following table presents the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis: Puget Energy and Puget Sound Energy Fair Value At June 30. 2019 Fair Value At December 31, 2018 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 17,093 $ 1,383 $ 18,476 $ 28,765 $ 4,522 $ 33,287 Natural gas derivative instruments 5,673 2,625 8,298 12,247 3,485 15,732 Total assets $ 22,766 $ 4,008 $ 26,774 $ 41,012 $ 8,007 $ 49,019 Liabilities: Electric derivative instruments $ 23,788 $ 3,829 $ 27,617 $ 24,124 $ 3,160 $ 27,284 Natural gas derivative instruments 21,302 227 21,529 28,660 1,812 30,472 Total liabilities $ 45,090 $ 4,056 $ 49,146 $ 52,784 $ 4,972 $ 57,756
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation	The following table presents the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy and Puget Sound Energy Three Months Ended (Dollars in Thousands) 2019 2018 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ 5,012 $ 2,758 $ 7,770 $ 1,186 $ 5,096 $ 6,282 Changes during period: Realized and unrealized energy derivatives: Included in earnings 1 (6,190 ) — (6,190 ) 366 — 366 Included in regulatory assets / liabilities — 382 382 — 354 354 Settlements 574 (1,619 ) (1,045 ) (151 ) (1,800 ) (1,951 ) Transferred into Level 3 — — — — — — Transferred out of Level 3 (1,842 ) 877 (965 ) 608 299 907 Balance at end of period $ (2,446 ) $ 2,398 $ (48 ) $ 2,009 $ 3,949 $ 5,958 Puget Energy and Puget Sound Energy Six Months Ended (Dollars in Thousands) 2019 2018 Level 3 Roll-Forward Net Asset/(Liability) 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 Changes during period: Realized and unrealized energy derivatives: Included in earnings 2 6,135 — 6,135 1,985 — 1,985 Included in regulatory assets / liabilities — 2,279 2,279 — 5,329 5,329 Settlements (12,909 ) (2,718 ) (15,627 ) (654 ) (3,602 ) (4,256 ) Transferred into Level 3 4,391 (398 ) 3,993 (1,837 ) — (1,837 ) Transferred out of Level 3 (1,425 ) 1,562 137 1,417 299 1,716 Balance at end of period $ (2,446 ) $ 2,398 $ (48 ) $ 2,009 $ 3,949 $ 5,958 _______________ 1. Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(4.7) million and $0.7 million for the three months ended June 30, 2019 and 2018 , respectively. 2. Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(2.4) million and $1.7 million for the six months ended June 30, 2019 and 2018 , respectively.
Fair Value Inputs, Assets and Liabilities, Quantitative Information	The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of June 30, 2019 : Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 1,383 $ 3,829 Discounted cash flow Power prices (per MWh) $ 8.95 $ 49.85 $ 34.16 Natural gas $ 2,625 $ 227 Discounted cash flow Natural gas prices (per MMBtu) $ 1.75 $ 2.67 $ 2.03 _______________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2018 : Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 4,522 $ 3,160 Discounted cash flow Power prices (per MWh) $ 11.35 $ 66.45 $ 29.63 Natural gas $ 3,485 $ 1,812 Discounted cash flow Natural gas prices (per MMBtu) $ 1.84 $ 5.80 $ 3.18 ____________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

Retirement Benefits (Tables)

Retirement Benefits (Tables)	6 Months Ended
	Jun. 30, 2019
Retirement Benefits [Abstract]
Schedule of Net Benefit Costs	The following tables summarize the Company’s net periodic benefit cost for the three months and six months ended June 30, 2019 and 2018 : Puget Energy Qualified SERP Other Three Months Ended June 30, (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Components of net periodic benefit cost: Service cost $ 5,287 $ 5,425 $ 256 $ 212 $ 16 $ 17 Interest cost 7,216 6,780 578 530 112 110 Expected return on plan assets (12,624 ) (12,559 ) — — (98 ) (117 ) Amortization of prior service cost (495 ) (495 ) 83 11 — — Amortization of net loss (gain) 251 462 341 394 (63 ) (86 ) Net periodic benefit cost $ (365 ) $ (387 ) $ 1,258 $ 1,147 $ (33 ) $ (76 ) Puget Energy Qualified SERP Other Six Months Ended June 30, (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Components of net periodic benefit cost: Service cost $ 10,574 $ 10,851 $ 512 $ 423 $ 33 $ 35 Interest cost 14,433 13,560 1,157 1,060 224 220 Expected return on plan assets (25,248 ) (25,119 ) — — (195 ) (235 ) Amortization of prior service cost (990 ) (990 ) 166 22 — — Amortization of net loss (gain) 501 925 683 790 (125 ) (172 ) Net periodic benefit cost $ (730 ) $ (773 ) $ 2,518 $ 2,295 $ (63 ) $ (152 ) Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Three Months Ended June 30, (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Components of net periodic benefit cost: Service cost $ 5,287 $ 5,425 $ 256 $ 212 $ 16 $ 17 Interest cost 7,216 6,780 578 530 112 110 Expected return on plan assets (12,628 ) (12,569 ) — — (98 ) (117 ) Amortization of prior service cost (393 ) (393 ) 83 11 — — Amortization of net loss (gain) 3,165 3,630 433 517 (109 ) (142 ) Net periodic benefit cost $ 2,647 $ 2,873 $ 1,350 $ 1,270 $ (79 ) $ (132 ) Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Six Months Ended June 30, (Dollars in Thousands) 2019 2018 2019 2018 2019 2018 Components of net periodic benefit cost: Service cost $ 10,574 $ 10,851 $ 512 $ 423 $ 33 $ 35 Interest cost 14,433 13,560 1,157 1,060 224 220 Expected return on plan assets (25,257 ) (25,138 ) — — (195 ) (235 ) Amortization of prior service cost (787 ) (787 ) 167 22 — — Amortization of net loss (gain) 6,330 7,260 866 1,035 (219 ) (283 ) Net periodic benefit cost $ 5,293 $ 5,746 $ 2,702 $ 2,540 $ (157 ) $ (263 )
Schedule of Changes in Projected Benefit Obligations	The following table summarizes the Company’s change in benefit obligation for the periods ended June 30, 2019 and December 31, 2018 : Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Six Months Ended Year Six Months Ended Year Six Months Ended Year (Dollars in Thousands) June 30, December 31, June 30, December 31, June 30, December 31, 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 — — Service cost 10,574 22,757 512 847 33 69 Interest cost 14,433 27,303 1,157 2,120 224 444 Actuarial loss (gain) — (29,067 ) — 1,122 — (379 ) Benefits paid (21,850 ) (42,662 ) (1,007 ) (5,581 ) (524 ) (1,037 ) Medicare part D subsidy received — — — — 226 85 Administrative Expense — (1,169 ) — — — — Benefit obligation at end of period $ 680,800 $ 677,643 $ 56,370 $ 55,708 $ 10,595 $ 10,636

Leases (Tables)

Leases (Tables)	6 Months Ended
	Jun. 30, 2019
Leases [Abstract]
Schedule of lease cost	The components of lease expense were as follows: Puget Energy and Three Months Ended June 30, Six Months Ended (Dollars in Thousands) 2019 2019 Finance lease cost: Amortization of right-of-use asset $ 124 $ 282 Interest on lease liabilities 10 19 Total finance lease cost $ 134 $ 301 Operating lease cost 1 $ 5,223 $ 10,007 _______________ 1 Includes $0.5 million allocated to PLNG at PE related to the Tacoma land lease. Supplemental cash flow information related to leases was as follows: Puget Energy and Three Months Ended June 30, Six Months Ended (Dollars in Thousands) 2019 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ (4,785 ) $ (9,131 ) Investing cash flow for operating leases 1 (438 ) (876 ) Operating cash flow for finance leases (10 ) (19 ) Financing cash flows for finances leases (124 ) (282 ) _______________ 1 Includes $0.5 million allocated to PLNG at PE related to the Tacoma land lease.
Schedule of lease assets and liabilities	Supplemental balance sheet information related to leases was as follows: Puget Sound Energy (Dollars in Thousands) At June 30, Operating Leases 2019 Operating lease right-of-use asset $ 172,278 Operating leases liabilities current $ (14,713 ) Operating lease liabilities long-term (163,698 ) Total Operating lease liabilities: $ (178,411 ) Finance Leases Common Plant $ 1,397 Other current liabilities $ (599 ) Other deferred credits (813 ) Total finance lease liabilities $ (1,412 ) Weighted Average Remaining Lease Term Operating leases 13.30 years Finance leases 2.89 years Weighted Average Discount Rate Operating leases 3.77 % Finance leases 2.98 %
Schedule of maturity of operating lease liability	The following tables summarize the Company’s estimated future minimum lease payments as of June 30, 2019 , and December 31, 2018 , respectively: Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At June 30, Operating Leases Finance Leases 2019 (remaining six months) $ 11,822 $ 308 2020 21,506 545 2021 21,762 409 2022 20,800 181 2023 20,716 24 Thereafter 134,067 — Total lease payments 230,673 1,467 Less imputed interest (52,262 ) (55 ) Total $ 178,411 $ 1,412
Schedule of maturity of finance lease liability	The following tables summarize the Company’s estimated future minimum lease payments as of June 30, 2019 , and December 31, 2018 , respectively: Maturities of lease liabilities Future Minimum Lease Payments (Dollars in Thousands) At June 30, Operating Leases Finance Leases 2019 (remaining six months) $ 11,822 $ 308 2020 21,506 545 2021 21,762 409 2022 20,800 181 2023 20,716 24 Thereafter 134,067 — Total lease payments 230,673 1,467 Less imputed interest (52,262 ) (55 ) Total $ 178,411 $ 1,412
Schedule of future minimum lease payments	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 minimum lease payments $ 234,283 $ 1,334
Schedule of future minimum lease payments	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 minimum lease payments $ 234,283 $ 1,334

Summary of Consolidation and _3

Summary of Consolidation and Significant Accounting Policy (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019USD ($)mi²	Jun. 30, 2018USD ($)	Jun. 30, 2019USD ($)mi²	Jun. 30, 2018USD ($)
Summary of Consolidation Policy
Non-utility expense and other	$ 10,620	$ 8,419	$ 24,377	$ 21,249
Subsidiaries [Member]
Summary of Consolidation Policy
Area of Service Territory (in sqmi) | mi²	6,000		6,000
Non-utility expense and other	$ 9,978	$ 10,834	$ 23,055	$ 20,614
Subsidiaries [Member] | Tacoma LNG [Member]
Summary of Consolidation Policy
Jointly Owned Non-Utility Plant Share	43.00%		43.00%
Construction in Progress, Gross	$ 148,500		$ 148,500
Puget LNG [Member]
Summary of Consolidation Policy
Jointly Owned Non-Utility Plant Share	57.00%		57.00%
Construction in Progress, Gross	$ 185,400		$ 185,400
Puget LNG [Member]
Summary of Consolidation Policy
Non-utility expense and other			$ 700

Revenue (Details)

Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	$ 644,987	$ 665,852	$ 1,740,785	$ 1,673,126
Regulated Operating Revenue, Other	6,731	10,146	17,974	18,184
Total operating revenue	670,930	671,852	1,785,769	1,709,860
Electricity, US Regulated [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	463,219	468,378	1,100,408	1,099,184
Natural Gas, US Regulated [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	145,222	158,544	467,782	492,578
Other Revenue From Contracts with Customers [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	36,546	38,930	172,595	81,364
Decoupling over-collection [Domain]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	4,351	(8,815)	(20,880)	(23,897)
Other Non-606 Revenue [Member]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	21,592	14,815	65,864	60,631
Subsidiaries [Member]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Other	6,731	10,146	17,974	18,184
Total operating revenue	$ 670,930	$ 671,852	$ 1,785,769	$ 1,709,860

Accounting for Derivative Ins_3

Accounting for Derivative Instruments and Hedging Activities Narrative (Details) $ in Millions	3 Months Ended
	Jun. 30, 2019USD ($)
Subsidiaries [Member]
Derivative [Line Items]
Hedging strategy number of years extended	3 years
External Credit Rating, Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage	96.60%
External Credit Rating, Non Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage	3.40%
Credit Rating [Member]
Derivative [Line Items]
Posted Collateral	$ 5.8	[1]
Credit Rating [Member] | Natural Gas Portfolio [Member]
Derivative [Line Items]
Posted Collateral	$ 1	[1]
[1]	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.

Accounting for Derivative Ins_4

Accounting for Derivative Instruments and Hedging Activities Derivative Assets and Liabilities (Details) $ in Thousands, MWh in Millions, MMBTU in Millions		Jun. 30, 2019USD ($)MWhMMBTU	Dec. 31, 2018USD ($)MWhMMBTU
Derivative [Line Items]
Current, Assets		$ 23,525	$ 46,507
Long-term, Assets		3,249	2,512
Current, Liabilities		40,695	46,661
Long-term, Liabilities		8,451	11,095
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Current, Assets	[1]	23,525	46,507
Long-term, Assets	[1]	3,249	2,512
Assets	[1]	26,774	49,019
Current, Liabilities	[2]	40,695	46,661
Long-term, Liabilities	[2]	8,451	11,095
Derivative Liability	[2]	$ 49,146	$ 57,756
Not Designated as Hedging Instrument [Member] | Natural Gas Derivatives [Member]
Derivative [Line Items]
Volumes | MMBTU	[3]	293.7	336.6
Not Designated as Hedging Instrument [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Assets	[1]	$ 18,476	$ 33,287
Derivative Liability	[2]	27,617	27,284
Not Designated as Hedging Instrument [Member] | Natural Gas Portfolio [Member]
Derivative [Line Items]
Assets	[1],[3]	8,298	15,732
Derivative Liability	[2],[3]	$ 21,529	$ 30,472
Not Designated as Hedging Instrument [Member] | Electric Generation Fuel [Member]
Derivative [Line Items]
Volumes | MMBTU		206.3	194.8
Not Designated as Hedging Instrument [Member] | Purchased Electricity [Member]
Derivative [Line Items]
Volumes | MWh		10.2	6.6
[1]	_______________1 Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments.
[2]	2 Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments.
[3]	3 All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the purchased gas adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.

Accounting for Derivative Ins_5

Accounting for Derivative Instruments and Hedging Activities Net Amount of Derivatives Reported in the Statement of Financial Position (Details) - Commodity Contract [Member] - USD ($) $ in Thousands		Jun. 30, 2019	Dec. 31, 2018
Assets:
Gross Amount Recognized in the Statement of Financial Position	[1]	$ 26,774	$ 49,019
Gross Amounts Offset in the Statement of Financial Position		0	0
Assets		26,774	49,019
Commodity Contracts		(19,661)	(25,388)
Cash Collateral Received		0	0
Net Amount		7,113	23,631
Liabilities:
Gross Amount Recognized in the Statement of Financial Position	[1]	49,146	57,756
Gross Amounts Offset in the Statement of Financial Position		0	0
Derivative Liability		49,146	57,756
Commodity Contracts		(19,661)	(25,388)
Cash Collateral Posted		0	0
Net Amount		$ 29,485	$ 32,368
[1]	1 All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off.

Accounting for Derivative Ins_6

Accounting for Derivative Instruments and Hedging Activities Recognized in Statement of Income (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	$ (30,332)	$ 6,911	$ (15,145)	$ 7,907
Not Designated as Hedging Instrument [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(26,704)	(342)	38,103	(9,411)
Not Designated as Hedging Instrument [Member] | Electric Generation Fuel [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(17,189)	5,357	(2,228)	7,669
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Electric Generation Fuel [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(1,333)	(4,417)	11,995	(12,093)
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Purchased Electricity [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	4,961	(2,836)	41,253	(5,225)
Not Designated as Hedging Instrument [Member] | Electricity, US Regulated [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	$ (13,143)	$ 1,554	$ (12,917)	$ 238

Accounting for Derivative Ins_7

Accounting for Derivative Instruments and Hedging Activities Contractual Contingent Liability (Details) - USD ($) $ in Thousands		Jun. 30, 2019	Dec. 31, 2018
Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	[1]	$ 13,847	$ 19,069
Posted Collateral		0	0
Additional Collateral, Aggregate Fair Value		3,222	574
Credit Rating [Member]
Derivative [Line Items]
Posted Collateral	[2]	5,800
Credit Rating [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	[1],[2]	3,222	574
Posted Collateral	[2]	0	0
Additional Collateral, Aggregate Fair Value	[2]	3,222	574
Requested Credit for Adequate Assurance [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	[1]	10,625	18,495
Posted Collateral		0	0
Additional Collateral, Aggregate Fair Value		$ 0	$ 0
[1]	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]	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.

Fair Value Measurements Debt at

Fair Value Measurements Debt at at Carrying and Fair Value (Details) - USD ($) $ in Thousands		Jun. 30, 2019	Dec. 31, 2018
Liabilities:
Total long-term debt		$ 5,698,526	$ 5,672,491
Carrying Value [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments, Fair Value Disclosure		50,500	49,500
Subsidiaries [Member]
Liabilities:
Total long-term debt		3,895,677	3,894,860
Discounted cash flow [Member] | Carrying Value [Member]
Liabilities:
Total long-term debt		5,698,526	5,672,491
Discounted cash flow [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount	[1]	5,516,626	5,510,591
Long-term debt (variable-rate)		181,900	161,900
Debt issuance costs		24,500	26,100
Discounted cash flow [Member] | Fair Value [Member]
Liabilities:
Total long-term debt		7,066,566	6,605,642
Discounted cash flow [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount	[1]	6,884,666	6,443,742
Long-term debt (variable-rate)		181,900	161,900
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member]
Liabilities:
Total long-term debt		3,895,677	3,894,860
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount	[2]	3,895,677	3,894,860
Debt issuance costs		23,900	24,600
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member]
Liabilities:
Total long-term debt		4,981,972	4,574,611
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount	[2]	$ 4,981,972	$ 4,574,611
[1]	1 The carrying value includes debt issuances costs of $24.5 million and $26.1 million for June 30, 2019 and December 31, 2018, respectively, which are not included in fair value.
[2]	2 The carrying value includes debt issuances costs of $23.9 million and $24.6 million for June 30, 2019 and December 31, 2018, respectively, which are not included in fair value.

Fair Value Measurements Assets

Fair Value Measurements Assets and Liabilities (Details) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2019		Jun. 30, 2018		Jun. 30, 2019		Jun. 30, 2018		Dec. 31, 2018
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	$ 7,770		$ 6,282		$ 3,035		$ 3,021
Included in earnings	(6,190)	[1]	366	[1]	6,135	[2]	1,985	[2]
Included in regulatory assets/liabilities	382		354		2,279		5,329
Settlements	(1,045)		(1,951)		(15,627)		(4,256)
Transferred into Level 3	0		0		3,993		(1,837)
Transferred out of Level 3	(965)		907		137		1,716
Balance at end of period	(48)		5,958		(48)		5,958
Electric Portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	5,012		1,186		1,362		1,098
Included in earnings	(6,190)	[1]	366	[1]	6,135	[2]	1,985	[2]
Included in regulatory assets/liabilities	0		0		0		0
Settlements	574		(151)		(12,909)		(654)
Transferred into Level 3	0		0		4,391		(1,837)
Transferred out of Level 3	(1,842)		608		(1,425)		1,417
Balance at end of period	(2,446)		2,009		(2,446)		2,009
Gain (loss) on derivatives	(4,700)		700		(2,400)		1,700
Natural Gas Portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	2,758		5,096		1,673		1,923
Included in earnings	0	[1]	0	[1]	0	[2]	0	[2]
Included in regulatory assets/liabilities	382		354		2,279		5,329
Settlements	(1,619)		(1,800)		(2,718)		(3,602)
Transferred into Level 3	0		0		(398)		0
Transferred out of Level 3	877		299		1,562		299
Balance at end of period	2,398		$ 3,949		2,398		$ 3,949
Fair Value, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	26,774				26,774				$ 49,019
Derivative Liability	49,146				49,146				57,756
Fair Value, Recurring [Member] | Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	18,476				18,476				33,287
Derivative Liability	27,617				27,617				27,284
Fair Value, Recurring [Member] | Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	8,298				8,298				15,732
Derivative Liability	21,529				21,529				30,472
Fair Value, Recurring [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	22,766				22,766				41,012
Derivative Liability	45,090				45,090				52,784
Fair Value, Recurring [Member] | Level 2 [Member] | Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	17,093				17,093				28,765
Derivative Liability	23,788				23,788				24,124
Fair Value, Recurring [Member] | Level 2 [Member] | Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	5,673				5,673				12,247
Derivative Liability	21,302				21,302				28,660
Fair Value, Recurring [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	4,008				4,008				8,007
Derivative Liability	4,056				4,056				4,972
Fair Value, Recurring [Member] | Level 3 [Member] | Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	1,383	[3]			1,383	[3]			4,522	[4]
Derivative Liability	3,829	[3]			3,829	[3]			3,160	[4]
Fair Value, Recurring [Member] | Level 3 [Member] | Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	2,625	[3]			2,625	[3]			3,485	[4]
Derivative Liability	$ 227	[3]			$ 227	[3]			$ 1,812	[4]
[1]	1. Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(4.7) million and $0.7 million for the three months ended June 30, 2019 and 2018, respectively.
[2]	2. Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(2.4) million and $1.7 million for the six months ended June 30, 2019 and 2018, respectively.
[3]	1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.
[4]	1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

Fair Value Measurements Valuati

Fair Value Measurements Valuation Techniques for Measurement with Unobservable Inputs (Details) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2019USD ($)	Dec. 31, 2018USD ($)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value measurement, sensitivity analysis, hypothetical increase or decrease of market prices, result on fair value	10.00%
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value	$ 1,800	$ 2,600
Fair Value, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	26,774	49,019
Derivative Liability	$ 49,146	$ 57,756
Electric Portfolio [Member] | Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh)	8.95	11.35
Electric Portfolio [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh)	49.85	66.45
Electric Portfolio [Member] | Discounted cash flow [Member] | Weighted Average [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh)	34.16	29.63
Electric Portfolio [Member] | Fair Value, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	$ 18,476	$ 33,287
Derivative Liability	$ 27,617	$ 27,284
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MMBtu)	1.75	1.84
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MMBtu)	2.67	5.80
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | Weighted Average [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MMBtu)	2.03	3.18
Natural Gas Portfolio [Member] | Fair Value, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	$ 8,298	$ 15,732
Derivative Liability	$ 21,529	$ 30,472

Retirement Benefits Net Periodi

Retirement Benefits Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost			$ 10,574		$ 22,757
Interest cost			14,433		27,303
Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost			512		847
Interest cost			1,157		2,120
Other Benefit [Member]
Components of net periodic benefit cost:
Service cost			33		69
Interest cost			224		$ 444
Parent Company [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	$ 5,287	$ 5,425	10,574	$ 10,851
Interest cost	7,216	6,780	14,433	13,560
Expected return on plan assets	(12,624)	(12,559)	(25,248)	(25,119)
Amortization of prior service cost	(495)	(495)	(990)	(990)
Amortization of net loss (gain)	251	462	501	925
Net periodic benefit cost	(365)	(387)	(730)	(773)
Parent Company [Member] | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	256	212	512	423
Interest cost	578	530	1,157	1,060
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	83	11	166	22
Amortization of net loss (gain)	341	394	683	790
Net periodic benefit cost	1,258	1,147	2,518	2,295
Parent Company [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	16	17	33	35
Interest cost	112	110	224	220
Expected return on plan assets	(98)	(117)	(195)	(235)
Amortization of prior service cost	0	0	0	0
Amortization of net loss (gain)	(63)	(86)	(125)	(172)
Net periodic benefit cost	(33)	(76)	(63)	(152)
Subsidiaries [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	5,287	5,425	10,574	10,851
Interest cost	7,216	6,780	14,433	13,560
Expected return on plan assets	(12,628)	(12,569)	(25,257)	(25,138)
Amortization of prior service cost	(393)	(393)	(787)	(787)
Amortization of net loss (gain)	3,165	3,630	6,330	7,260
Net periodic benefit cost	2,647	2,873	5,293	5,746
Subsidiaries [Member] | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	256	212	512	423
Interest cost	578	530	1,157	1,060
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	83	11	167	22
Amortization of net loss (gain)	433	517	866	1,035
Net periodic benefit cost	1,350	1,270	2,702	2,540
Subsidiaries [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	16	17	33	35
Interest cost	112	110	224	220
Expected return on plan assets	(98)	(117)	(195)	(235)
Amortization of prior service cost	0	0	0	0
Amortization of net loss (gain)	(109)	(142)	(219)	(283)
Net periodic benefit cost	$ (79)	$ (132)	$ (157)	$ (263)

Retirement Benefits Change in N

Retirement Benefits Change in Net Benefit Obligation (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2019	Dec. 31, 2018
Qualified Pension Benefits [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	10,574	22,757
Interest cost	14,433	27,303
Actuarial loss (gain)	0	(29,067)
Benefits paid	(21,850)	(42,662)
Medicare part D subsidy received	0	0
Administrative Expense	0	(1,169)
Benefit obligation at end of period	680,800	677,643
Supplemental Employee Retirement 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	512	847
Interest cost	1,157	2,120
Actuarial loss (gain)	0	1,122
Benefits paid	(1,007)	(5,581)
Medicare part D subsidy received	0	0
Administrative Expense	0	0
Benefit obligation at end of period	56,370	55,708
Other Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	10,636	11,454
Amendments	0	0
Service cost	33	69
Interest cost	224	444
Actuarial loss (gain)	0	(379)
Benefits paid	(524)	(1,037)
Medicare part D subsidy received	226	85
Administrative Expense	0	0
Benefit obligation at end of period	$ 10,595	$ 10,636

Retirement Benefits Activity (D

Retirement Benefits Activity (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019	Dec. 31, 2019
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employer contributions	$ 0.5	$ 1
Forecast [Member] | Qualified Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			$ 18
Forecast [Member] | Supplemental Employee Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			6.2
Forecast [Member] | Other Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			$ 0.3

Regulation and Rates (Details)

Regulation and Rates (Details) - USD ($)

Jun. 20, 2019

Mar. 01, 2019

Nov. 07, 2018

May 01, 2018

Mar. 01, 2018

Dec. 19, 2017

Dec. 18, 2017

Jun. 30, 2019

Jun. 30, 2018

Jun. 30, 2019

Jun. 30, 2018

Apr. 30, 2019

Jan. 01, 2018

Regulatory Assets [Line Items]

Income tax (benefit) expense

$ 1,481,000

$ 3,469,000

$ 9,909,000

$ 15,272,000

Subsidiaries [Member]

Regulatory Assets [Line Items]

Income tax (benefit) expense

$ 34,600,000

2,327,000

$ 7,004,000

21,157,000

28,696,000

Subsidiaries [Member] | Electricity, US Regulated [Member]

Regulatory Assets [Line Items]

Storm Damage Costs Incurred During Period

39,200,000

8,900,000

Storm Damage Costs Deferred During Period

0

Public Utilities, Rate Case, Deferred Storm Costs Threshold

$ 8,000,000

8,000,000

$ 10,000,000

Public Utilities, Rate Case, Deferred Storm Qualifying Costs

$ 500,000

General Rate Case [Member] | Subsidiaries [Member]

Regulatory Assets [Line Items]

Public Utilities, Requested Return on Equity, Percentage

9.80%

Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities

7.62%

7.49%

7.60%

General Rate Case [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]

Regulatory Assets [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Percentage

6.90%

General Rate Case [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]

Regulatory Assets [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Percentage

7.90%

Expedited Rate Filing (ERF) [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]

Regulatory Assets [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Percentage

0.90%

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 18,900,000

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 0

Expedited Rate Filing (ERF) [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]

Regulatory Assets [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Percentage

2.70%

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 21,700,000

$ 6,100,000

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 21,500,000

$ 25,900,000

Tax Cuts and Jobs Act [Member] | Natural Gas, US Regulated [Member]

Regulatory Assets [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage

(2.70%)

Tax Cuts and Jobs Act [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]

Regulatory Assets [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

$ (72,900,000)

Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage

(3.40%)

Tax Cuts and Jobs Act [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]

Regulatory Assets [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

$ (23,600,000)

Decoupling Mechanism [Member] | Maximum [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]

Regulatory Assets [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

3.00%

Decoupling Mechanism [Member] | Maximum [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]

Regulatory Assets [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

5.00%

3.00%

Storm That Occurred In 2018 [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]

Regulatory Assets [Line Items]

Storm Damage Costs Deferred During Period

$ 388,286.08

Storm That Occurred In 2019 [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]

Regulatory Assets [Line Items]

Storm Damage Costs Deferred During Period

$ 28,326,408.10

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	Jun. 30, 2019USD ($)	Dec. 31, 2018USD ($)
Colstrip Units 1 and 2 [Member]
Loss Contingencies [Line Items]
Ownership interest (percent)	50.00%
Jointly owned utility plant	2
Colstrip Units 3 and 4 [Member]
Loss Contingencies [Line Items]
Ownership interest (percent)	25.00%
Colstrip Regulatory Asset [Domain]
Loss Contingencies [Line Items]
Regulatory Assets	$ 178.2	$ 130.7

Leases (Details)

Leases (Details)	6 Months Ended
	Jun. 30, 2019
Leases [Abstract]
Remaining lease term (less than)	26 years
Lessee, lease, renewal term (up to)	25 years

Leases - Schedule of the compon

Leases - Schedule of the components of lease expense (Details) - USD ($) $ in Thousands		3 Months Ended	6 Months Ended
		Jun. 30, 2019	Jun. 30, 2019
Related Party Transaction [Line Items]
Amortization of right-of-use asset		$ 124	$ 282
Interest on lease liabilities		10	19
Total finance lease cost		134	301
Operating lease cost	[1]	$ 5,223	10,007
Land | Subsidiaries
Related Party Transaction [Line Items]
Operating lease cost			$ 500
[1]	1 Includes $0.5 million allocated to PLNG at PE related to the Tacoma land lease.

Leases - Supplemental cash flow

Leases - Supplemental cash flow information related to leases (Details) - USD ($) $ in Thousands		3 Months Ended	6 Months Ended
		Jun. 30, 2019	Jun. 30, 2019
Leases [Abstract]
Operating cash flows for operating leases		$ (4,785)	$ (9,131)
Investing cash flow from operating leases	[1]	(438)	(876)
Operating cash flow for finance leases		(10)	(19)
Financing cash flows for finances leases		(124)	(282)
Related Party Transaction [Line Items]
Investing cash flow from operating leases	[1]	$ (438)	(876)
Land | Subsidiaries
Leases [Abstract]
Investing cash flow from operating leases			(500)
Related Party Transaction [Line Items]
Investing cash flow from operating leases			$ (500)
[1]	1 Includes $0.5 million allocated to PLNG at PE related to the Tacoma land lease.

Leases - Supplemental balance s

Leases - Supplemental balance sheet information related to leases (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Operating Leases
Operating lease right-of-use asset	$ 172,278	$ 0
Operating leases liabilities current	(14,713)	0
Operating lease liabilities long-term	(163,698)	$ 0
Total Operating lease liabilities:	178,411
Finance Leases
Common Plant	1,397
Other current liabilities	(599)
Other deferred credits	(813)
Total finance lease liabilities	$ 1,412
Weighted Average Remaining Lease Term
Operating leases	13 years 3 months 19 days
Finance leases	2 years 10 months 21 days
Weighted Average Discount Rate
Operating leases	3.77%
Finance leases	2.98%

Leases - Schedule of future min

Leases - Schedule of future minimyn lease payments (Details) $ in Thousands	Jun. 30, 2019USD ($)
Operating Leases
2019	$ 11,822
2020	21,506
2021	21,762
2022	20,800
2023	20,716
Thereafter	134,067
Total lease payments	230,673
Less imputed interest	(52,262)
Total	178,411
Finance Leases
2019	308
2020	545
2021	409
2022	181
2023	24
Thereafter	0
Total lease payments	1,467
Less imputed interest	(55)
Total	$ 1,412

Leases - Schedule of future m_2

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

Other (Details)

Other (Details) $ in Millions	Apr. 01, 2019USD ($)
Term Loan Expansion [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 24