Puget Sound Energy 10-K 21 Feb 19 2018 FY Annual report Financial data

Document And Entity Information

Document And Entity Information	12 Months Ended
	Dec. 31, 2018shares	Jun. 30, 2016USD ($)
Entity Information [Line Items]
EBITDA to Interest Expense Denominator	1
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End	1
Entity Registrant Name	PUGET ENERGY INC /WA
Entity Central Index Key	1,085,392
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float | $		$ 0
Entity Common Stock, Shares Outstanding | shares	200
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Document Period End Date	Dec. 31, 2018
Subsidiaries [Member]
Entity Information [Line Items]
EBITDA to Interest Expense Denominator	1
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End	1
Entity Registrant Name	PUGET SOUND ENERGY INC
Entity Central Index Key	81,100
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float | $		$ 0
Entity Common Stock, Shares Outstanding | shares	85,903,791
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Document Period End Date	Dec. 31, 2018

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Parent [Line Items]
Regulated Operating Revenue, Electric, Non-Nuclear	$ 2,455,919	$ 2,420,663	$ 2,238,492
Regulated Operating Revenue, Gas	850,748	997,759	890,510
Operating revenue:
Other	39,829	41,854	35,299
Total operating revenue	3,346,496	3,460,276	3,164,301
Energy costs:
Utilities Operating Expense, Purchased Power	638,775	590,030	531,596
Electric generation fuel	204,174	206,275	215,331
Residential exchange	(77,454)	(75,933)	(69,824)
Purchased natural gas	296,699	360,009	313,954
Unrealized (gain) loss on derivative instruments, net	(41,662)	30,790	(83,795)
Utility operations and maintenance	602,638	592,277	572,933
Non-utility expense and other	54,519	53,864	42,620
Depreciation and amortization	666,432	481,969	439,579
Conservation amortization	111,714	121,216	107,784
Taxes other than income taxes	336,603	360,673	328,649
Total operating expenses	2,792,438	2,721,170	2,398,827
Operating income (loss)	554,058	739,106	765,474
Other income (deductions):
Other income	52,957	49,283	45,449
Other expense	(11,201)	(14,104)	(10,923)
Non-hedged interest rate swap expense	0	28	(1,062)
Interest charges:
AFUDC	13,695	10,826	9,304
Interest expense	(343,795)	(354,802)	(355,139)
Income (loss) before income taxes	265,714	430,337	453,103
Income tax (benefit) expense	30,092	255,143	140,204
Net income (loss)	235,622	175,194	312,899
Subsidiaries [Member]
Parent [Line Items]
Regulated Operating Revenue, Electric, Non-Nuclear	2,455,919	2,420,663	2,238,492
Regulated Operating Revenue, Gas	850,748	997,759	890,510
Operating revenue:
Other	39,829	41,854	35,616
Total operating revenue	3,346,496	3,460,276	3,164,618
Energy costs:
Utilities Operating Expense, Purchased Power	638,775	590,030	531,596
Electric generation fuel	204,174	206,275	215,331
Residential exchange	(77,454)	(75,933)	(69,824)
Purchased natural gas	296,699	360,009	313,954
Unrealized (gain) loss on derivative instruments, net	(41,662)	30,790	(83,795)
Utility operations and maintenance	602,638	592,277	572,933
Non-utility expense and other	51,549	52,389	37,859
Depreciation and amortization	666,324	481,955	439,579
Conservation amortization	111,714	121,216	107,784
Taxes other than income taxes	336,603	360,673	328,649
Total operating expenses	2,789,360	2,719,681	2,394,066
Operating income (loss)	557,136	740,595	770,552
Other income (deductions):
Other income	39,847	34,867	29,978
Other expense	(11,201)	(14,104)	(10,923)
Interest charges:
AFUDC	13,695	10,826	9,304
Interest expense	(231,615)	(240,144)	(242,983)
Income (loss) before income taxes	367,862	532,040	555,928
Income tax (benefit) expense	50,700	211,986	175,347
Net income (loss)	$ 317,162	$ 320,054	$ 380,581

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Parent [Line Items]
Net income (loss)	$ 235,622	$ 175,194	$ 312,899
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	(47,690)	9,430	(6,446)
Other Comprehensive Income Reclassification Of Net Unrealized Gain Loss On Interest Rate Swaps During Period Net Of Tax	5,230	0	0
Other comprehensive income (loss)	(52,920)	9,430	(6,446)
Comprehensive income (loss)	182,702	184,624	306,453
Subsidiaries [Member]
Parent [Line Items]
Net income (loss)	317,162	320,054	380,581
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	(37,030)	18,288	3,722
Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax	385	317	317
Amortization of treasury interest rate swaps to earnings, net of tax	(27,333)	0	0
Other comprehensive income (loss)	(63,978)	18,605	4,039
Comprehensive income (loss)	$ 253,184	$ 338,659	$ 384,620

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, tax	$ 0	$ 5,078	$ (3,471)
Reclassification of net unrealized loss on energy derivative instruments during the period, tax	0	0	0
Subsidiaries [Member]
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, tax	0	9,848	2,004
Reclassification of net unrealized loss on energy derivative instruments during the period, tax	0	0	0
Amortization of treasury interest rate swaps to earnings, tax	$ 0	$ 171	$ 171

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Utility Plant [Abstract]
Electric plant	$ 8,515,482	$ 8,135,847
Natural gas plant	3,598,732	3,307,545
Common plant	1,027,023	811,815
Less: Accumulated depreciation and amortization	(2,832,321)	(2,428,524)
Net utility plant	10,308,916	9,826,683
Other property and investments:
Goodwill	1,656,513	1,656,513
Other property and investments	244,444	182,355
Total other property and investments	1,900,957	1,838,868
Current assets:
Cash and cash equivalents	37,521	26,616
Restricted cash	18,041	10,145
Accounts receivable, net of allowance for doubtful accounts	338,782	341,110
Unbilled revenue	205,285	222,186
Purchased gas adjustment receivable	9,921	0
Materials and supplies, at average cost	116,180	107,003
Fuel and natural gas inventory, at average cost	53,351	49,908
Unrealized gain on derivative instruments	46,507	22,247
Prepaid expense and other	25,674	21,996
Power contract acquisition adjustment gain	6,114	12,207
Total current assets	857,376	813,418
Other long-term and regulatory assets:
Power cost adjustment mechanism	4,735	4,576
Regulatory assets related to power contracts	16,693	19,454
Other regulatory assets	773,552	948,532
Unrealized gain on derivative instruments	2,512	2,158
Power contract acquisition adjustment gain	156,597	162,711
Other	77,523	74,389
Total other long-term and regulatory assets	1,031,612	1,211,820
Total assets	14,098,861	13,690,789
Common shareholder’s equity:
Common stock	0	0
Additional paid-in capital	3,308,957	3,308,957
Retained earnings	629,003	465,355
Accumulated other comprehensive income (loss), net of tax	(77,202)	(24,282)
Total common shareholder’s equity	3,860,758	3,750,030
Long-term debt:
First mortgage bonds and senior notes	3,764,412	3,164,412
Pollution control bonds	161,860	161,860
Junior subordinated notes	0	250,000
Long-term debt	1,961,900	1,902,600
Debt discount, issuance costs and other	(215,681)	(220,943)
Total long-term debt	5,672,491	5,257,929
Total capitalization	9,533,249	9,007,959
Current liabilities:
Accounts payable	480,069	359,586
Short-term debt	379,297	329,463
Current maturities of long-term debt	0	200,000
Purchased gas adjustment payable	0	16,051
Accrued expenses:
Taxes	118,112	117,948
Salaries and wages	50,785	53,220
Interest	70,099	73,564
Unrealized loss on derivative instruments	46,661	64,859
Power Contract Acquisition Adjustment Loss Current	2,547	2,762
Other	79,312	80,206
Total current liabilities	1,226,882	1,297,659
Other Long-term and regulatory liabilities:
Deferred income taxes	789,297	746,868
Unrealized loss on derivative instruments	11,095	21,235
Regulatory liabilities	747,203	731,587
Deferred Tax Liabilities, Regulatory Assets and Liabilities	975,974	1,011,626
Regulatory Liabilities Related To Power Contracts	162,711	174,918
Power Contract Acquisition Adjustment Loss Non Current	14,146	16,693
Other deferred credits	638,304	682,244
Total other long-term and regulatory liabilities	3,338,730	3,385,171
Commitments and contingencies (Note 16)
Total capitalization and liabilities	14,098,861	13,690,789
Subsidiaries [Member]
Utility Plant [Abstract]
Electric plant	10,587,231	10,232,771
Natural gas plant	4,164,489	3,882,733
Common plant	1,052,544	843,145
Less: Accumulated depreciation and amortization	(5,495,348)	(5,131,966)
Net utility plant	10,308,916	9,826,683
Other property and investments:
Other property and investments	76,986	76,350
Total other property and investments	76,986	76,350
Current assets:
Cash and cash equivalents	35,452	25,864
Restricted cash	18,041	10,145
Accounts receivable, net of allowance for doubtful accounts	346,251	343,546
Unbilled revenue	205,285	222,186
Purchased gas adjustment receivable	9,921	0
Materials and supplies, at average cost	116,180	107,003
Fuel and natural gas inventory, at average cost	52,028	48,585
Unrealized gain on derivative instruments	46,507	22,247
Prepaid expense and other	25,674	21,996
Total current assets	855,339	801,572
Other long-term and regulatory assets:
Power cost adjustment mechanism	4,735	4,576
Other regulatory assets	773,552	948,540
Unrealized gain on derivative instruments	2,512	2,158
Other	75,483	71,827
Total other long-term and regulatory assets	856,282	1,027,101
Total assets	12,097,523	11,731,706
Common shareholder’s equity:
Common stock	859	859
Additional paid-in capital	3,275,105	3,275,105
Retained earnings	622,844	452,066
Accumulated other comprehensive income (loss), net of tax	(190,884)	(126,906)
Total common shareholder’s equity	3,707,924	3,601,124
Long-term debt:
First mortgage bonds and senior notes	3,764,417	3,164,412
Pollution control bonds	161,860	161,860
Junior subordinated notes	0	250,000
Debt discount, issuance costs and other	(31,417)	(26,361)
Total long-term debt	3,894,860	3,549,911
Total capitalization	7,602,784	7,151,035
Current liabilities:
Accounts payable	480,195	359,585
Short-term debt	379,297	329,463
Current maturities of long-term debt	0	200,000
Purchased gas adjustment payable	0	16,051
Accrued expenses:
Taxes	117,993	117,063
Salaries and wages	50,785	53,220
Interest	43,951	47,837
Unrealized loss on derivative instruments	46,661	64,859
Other	79,312	80,206
Total current liabilities	1,198,194	1,268,284
Other Long-term and regulatory liabilities:
Deferred income taxes	926,403	869,473
Unrealized loss on derivative instruments	11,095	21,235
Regulatory liabilities	745,880	730,273
Deferred Tax Liabilities, Regulatory Assets and Liabilities	976,582	1,012,260
Other deferred credits	636,585	679,146
Total other long-term and regulatory liabilities	3,296,545	3,312,387
Commitments and contingencies (Note 16)
Total capitalization and liabilities	$ 12,097,523	$ 11,731,706

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Assets:
Construction work in progress	$ 550,466	$ 495,937
Current assets:
Allowance for doubtful accounts	$ 8,408	$ 8,901
Common shareholder’s equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,000	1,000
Common stock, shares outstanding (in shares)	200	200
Subsidiaries [Member]
Assets:
Construction work in progress	$ 550,466	$ 495,937
Current assets:
Allowance for doubtful accounts	$ 8,408	$ 8,901
Common shareholder’s equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	150,000,000	150,000,000
Common stock, shares outstanding (in shares)	85,903,791	85,903,791

CONSOLIDATED STATEMENTS OF COMM

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Subsidiaries [Member]	Subsidiaries [Member]Common Stock	Subsidiaries [Member]Additional Paid-in Capital	Subsidiaries [Member]Retained Earnings	Subsidiaries [Member]Accumulated Other Comprehensive Income (Loss)
Balance at Dec. 31, 2015	$ 3,531,225		$ 3,308,957	$ 249,534	$ (27,266)	$ 3,362,992	$ 859	$ 3,275,105	$ 236,578	$ (149,550)
Balance (in shares) at Dec. 31, 2015		200					85,903,791
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	312,899			312,899		380,581			380,581
Common stock dividend paid	(148,965)			(148,965)		(257,364)			(257,364)
Other comprehensive income (loss)	(6,446)				(6,446)	4,039				4,039
Balance at Dec. 31, 2016	3,688,713		3,308,957	413,468	(33,712)	3,490,248	$ 859	3,275,105	359,795	(145,511)
Balance (in shares) at Dec. 31, 2016		200					85,903,791
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	175,194			175,194		320,054			320,054
Common stock dividend paid	(123,307)			(123,307)		(227,783)			(227,783)
Other comprehensive income (loss)	9,430				9,430	18,605				18,605
Balance at Dec. 31, 2017	$ 3,750,030		3,308,957	465,355	(24,282)	$ 3,601,124	$ 859	3,275,105	452,066	(126,906)
Balance (in shares) at Dec. 31, 2017	200	200				85,903,791	85,903,791
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 235,622			235,622		$ 317,162			317,162
Common stock dividend paid	(77,204)			(77,204)		(173,716)			(173,716)
Other comprehensive income (loss)	(52,920)				(52,920)	(63,978)				(63,978)
Balance at Dec. 31, 2018	$ 3,860,758		$ 3,308,957	629,003	$ (77,202)	$ 3,707,924	$ 859	$ 3,275,105	622,844	$ (190,884)
Balance (in shares) at Dec. 31, 2018	200	200				85,903,791	85,903,791
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	$ 5,200					$ 27,332			$ 27,332
Other Comprehensive Income (Loss) Reclassification of Stranded Taxes to RE for Pension Plans	$ 5,230			$ 5,230		$ 26,200

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating activities:
Net income (loss)	$ 235,622	$ 175,194	$ 312,899
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	666,432	481,969	439,579
Conservation amortization	111,714	121,216	107,784
Deferred income taxes and tax credits, net	19,457	254,524	139,640
Net unrealized (gain) loss on derivative instruments	(41,662)	30,650	(88,704)
AFUDC–equity	(17,191)	(15,027)	(12,576)
Production tax credits	(83,976)	(53,331)	0
Other non-cash	15,339	17,568	16,812
Funding of pension liability	(18,000)	(18,000)	(24,000)
Regulatory assets and liabilities	(71,348)	(88,875)	(153,643)
Other long-term assets and liabilities	2,695	(27,411)	16,435
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	17,659	132	(21,763)
Materials and supplies	(9,177)	(625)	(28,134)
Fuel and natural gas inventory	(3,443)	8,266	473
Prepayments and other	(3,679)	21,050	(25,927)
Purchased gas adjustment	(25,972)	18,836	(15,374)
Accounts payable	117,270	26,396	32,465
Taxes payable	164	6,520	(3,426)
Other	(7,723)	13,079	36,750
Net cash provided by (used in) operating activities	904,181	972,131	729,290
Investing activities:
Construction expenditures (excluding equity AFUDC)	(1,072,670)	(1,040,135)	(706,444)
Other	2,097	(195)	(1,921)
Net cash provided by (used in) investing activities	(1,070,573)	(1,040,330)	(708,365)
Financing activities:
Change in short-term debt, net	49,834	83,700	86,759
Dividends paid	(77,204)	(123,307)	(148,965)
Proceeds from long-term debt and bonds issued	804,050	90,120	12,481
Redemption of bonds and notes	(600,000)	0	0
Proceeds from (Payments for) Other Financing Activities	8,513	13,151	19,653
Net cash provided by (used in) financing activities	185,193	63,664	(30,072)
Net increase (decrease) in cash, cash equivalents, and restricted cash	18,801	(4,535)	(9,147)
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	322,476	326,798	329,603
Cash payments (refunds) for income taxes	8,303	1,649	0
Cash, cash equivalents, and restricted cash at beginning of period	36,761	41,296	50,443
Cash, cash equivalents, and restricted cash at end of period	55,562	36,761	41,296
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	97,673	92,959	76,813
Reclassification of hydro treasury grants to a regulatory liability	0	95,935	0
Subsidiaries [Member]
Operating activities:
Net income (loss)	317,162	320,054	380,581
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	666,324	481,955	439,579
Conservation amortization	111,714	121,216	107,784
Deferred income taxes and tax credits, net	30,995	210,842	174,776
Net unrealized (gain) loss on derivative instruments	(41,662)	30,790	(83,795)
AFUDC–equity	(17,191)	(15,027)	(12,576)
Production tax credits	(83,976)	(53,331)	0
Other non-cash	4,428	6,445	5,672
Funding of pension liability	(18,000)	(18,000)	(24,000)
Regulatory assets and liabilities	(71,348)	(88,875)	(152,786)
Other long-term assets and liabilities	16,917	(14,547)	30,235
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	12,626	13,285	(37,385)
Materials and supplies	(9,177)	(625)	(28,134)
Fuel and natural gas inventory	(3,443)	8,266	473
Prepayments and other	(3,679)	21,050	(25,927)
Purchased gas adjustment	(25,972)	18,836	(15,374)
Accounts payable	117,397	26,396	32,465
Taxes payable	930	5,635	(3,426)
Other	(8,141)	12,438	30,754
Net cash provided by (used in) operating activities	995,904	1,086,803	818,916
Investing activities:
Construction expenditures (excluding equity AFUDC)	(1,010,506)	(963,652)	(681,112)
Other	2,097	241	4,156
Net cash provided by (used in) investing activities	(1,008,409)	(963,411)	(676,956)
Financing activities:
Change in short-term debt, net	49,834	83,700	86,759
Dividends paid	(173,716)	(227,783)	(257,364)
Proceeds from long-term debt and bonds issued	594,750	0	0
Redemption of bonds and notes	(450,000)	0	0
Proceeds from (Payments for) Other Financing Activities	9,121	15,801	19,739
Net cash provided by (used in) financing activities	29,989	(128,282)	(150,866)
Net increase (decrease) in cash, cash equivalents, and restricted cash	17,484	(4,890)	(8,906)
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	221,155	224,423	227,668
Cash payments (refunds) for income taxes	18,124	3,058	0
Cash, cash equivalents, and restricted cash at beginning of period	36,009	40,899	49,805
Cash, cash equivalents, and restricted cash at end of period	53,493	36,009	40,899
Non-cash financing and investing activities:
Accounts payable for capital expenditures eliminated from cash flows	97,673	92,959	76,813
Reclassification of hydro treasury grants to a regulatory liability	0	95,935	0
Colstrip Units 1 – 4 Common Facilities
Non-cash financing and investing activities:
Reclassification of Colstrip from utility plant to a regulatory asset	$ (3,086)	$ (49,177)	$ 176,804

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Basis of Presentation Puget Energy is an energy services holding company that owns Puget Sound Energy (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma liquefied natural gas (LNG) facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that are incurred by PSE and allocated to Puget LNG are related party transactions by nature. In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805) purchase accounting adjustments. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. Utility Plant Puget Energy and PSE capitalize, at original cost, additions to utility plant, including renewals and betterments. Costs include indirect costs such as engineering, supervision, certain taxes, pension and other employee benefits and an allowance for funds used during construction (AFUDC). Replacements of minor items of property are included in maintenance expense. When the utility plant is retired and removed from service, the original cost of the property is charged to accumulated depreciation and costs associated with removal of the property, less salvage, are charged to the cost of removal regulatory liability. Planned Major Maintenance Planned major maintenance is an activity that typically occurs when PSE overhauls or substantially upgrades various systems and equipment on a scheduled basis. Costs related to planned major maintenance are deferred and amortized to the next scheduled major maintenance. This accounting method also follows the Washington Utilities and Transportation Commission (Washington Commission) regulatory treatment related to these generating facilities. Other Property and Investments For PSE, the costs of other property and investments (i.e., non-utility) are stated at historical cost. Expenditures for refurbishment and improvements that significantly add to productive capacity or extend useful life of an asset are capitalized. Replacements of minor items are expensed on a current basis. Gains and losses on assets sold or retired, which were previously recorded in utility plant, are apportioned between regulatory assets/liabilities and earnings. However, gains and losses on assets sold or retired, not previously recorded in utility plant, are reflected in earnings. Depreciation and Amortization The Company provides for depreciation and amortization on a straight-line basis. Amortization is recorded for intangibles such as regulatory assets and liabilities, computer software and franchises. The annual depreciation provision stated as a percent of a depreciable electric utility plant was 3.3% , 2.8% , and 2.8% in 2018 , 2017 and 2016 , respectively; depreciable natural gas utility plant was 2.8% , 3.4% , and 3.4% in 2018 , 2017 and 2016 , respectively; and depreciable common utility plant was 7.1% , 8.3% and 9.7% in 2018 , 2017 and 2016 , respectively. The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability. Goodwill In 2009, Puget Holdings completed its merger with Puget Energy. Puget Energy re-measured the carrying amount of all its assets and liabilities to fair value, which resulted in recognition of approximately $1.7 billion in goodwill. The goodwill recorded by Puget Energy represents the potential long-term return to the Company’s investors. ASC 350, “Intangibles - Goodwill and Other” (ASC 350), requires that goodwill be tested for impairment at the reporting unit level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. These events or circumstances could include a significant change in the Company’s business or regulatory outlook, legal factors, a sale or disposition of a significant portion of a reporting unit or significant changes in the financial markets which could influence the Company’s access to capital and interest rates. Application of the goodwill impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, assignment of goodwill to reporting units and the determination of the fair value of the reporting units. Management has determined Puget Energy has only one reporting unit. In testing goodwill and other indefinite-lived intangible assets for impairment, the Company has the option of first performing a qualitative assessment to determine whether it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform a quantitative impairment test. If, after assessing the totality of events or circumstances during a qualitative assessment, management determines it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then the entity shall perform a quantitative test to determine impairment. This requires a comparison of the fair value of our reporting unit to its carrying value. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not impaired. If the carrying amount of a reporting unit exceeds its fair value, an impairment loss shall be recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to that reporting unit. In 2018 , the Company elected to perform the qualitative assessment to determine if it was more-likely-than-not that the fair value of Puget Energy’s reporting unit was below carrying value. This qualitative assessment included the review of several qualitative factors, including the value of Puget Energy’s reporting unit from the previous quantitative tests and the excess of fair value over carrying value from these tests, macroeconomic conditions, industry and market considerations, the projected financial performance of Puget Energy’s reporting unit, as well as other factors. Based on our assessment, the Company concluded that it was more-likely-than-not that the fair value of Puget Energy’s reporting unit exceeded its carrying value and, therefore, did not result in an impairment as of October 1, 2018 . There were no known events or circumstances from the date of the assessment through December 31, 2018 that would impact management’s conclusion. The Company elected to perform a quantitative impairment assessment in 2017 as of the October 1, 2017, measurement date. The fair value of Puget Energy’s reporting unit was estimated using a combination of the discounted cash flow and market approach. The discounted cash flow approach requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term rate of growth for Puget Energy business, estimation of the useful life over which cash flows will occur, the selection of utility holding companies determined to be comparable to Puget Energy and determination of an appropriate weighted-average cost of capital or discount rate. The market approach estimates the fair value of the business based on market prices of stocks of comparable companies engaged in the same or similar lines of business. In addition, indications of market value are estimated by deriving multiples of equity or invested capital to various measures of revenue, earnings or cash flow. Changes in these estimates and/or assumptions could materially affect the determination of fair value and goodwill impairment of the reporting unit. Based on the test performed, management determined that there was no indication of impairment of Puget Energy’s goodwill as of October 1, 2017. There were no known events or circumstances from the date of the assessment through December 31, 2017, that would impact management’s conclusion. Tacoma LNG Facility 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 determined a Supplemental Environmental Impact Statement is necessary in order to rule on the air quality permit for the facility. As a result of requiring an 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. If delayed, the construction schedule and costs may be adversely impacted. Pursuant to an order by the Washington Commission, PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of the Tacoma LNG facility. The remaining 57.0% of common capital and operating costs of the Tacoma LNG facility will be allocated to Puget LNG. Per this allocation of costs, $165.6 million of construction work in progress and $2.0 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 December 31, 2018 . Additionally, $130.8 million of construction work in progress related to PSE’s portion of the Tacoma LNG facility is reported in the PSE “Utility plant - Natural gas plant” financial statement line item, as PSE is a regulated entity. Cash and Cash Equivalents Cash and cash equivalents consist of demand bank deposits and short-term highly liquid investments with original maturities of three months or less at the time of purchase. The carrying amounts of cash and cash equivalents are reported at cost and approximate fair value, due to the short-term maturity. Materials and Supplies Materials and supplies are used primarily in the operation and maintenance of electric and natural gas distribution and transmission systems as well as spare parts for combustion turbines used for the generation of electricity. The Company records these items at weighted-average cost. Fuel and Natural Gas Inventory Fuel and natural gas inventory is used in the generation of electricity and for future sales to the Company’s natural gas customers. Fuel inventory consists of coal, diesel and natural gas used for generation. Natural gas inventory consists of natural gas and LNG held in storage for future sales. The Company records these items at the lower of cost or net realizable value method. Regulatory Assets and Liabilities PSE accounts for its regulated operations in accordance with ASC 980, “Regulated Operations” (ASC 980). ASC 980 requires PSE to defer certain costs or losses that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. It similarly requires deferral of revenues or gains that are expected to be returned to customers in the future. Accounting under ASC 980 is appropriate as long as rates are established by or subject to approval by independent third-party regulators; rates are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that rates set at levels that will recover costs can be charged to and collected from customers. In most cases, PSE classifies regulatory assets and liabilities as long-term when amortization periods extend longer than one year. For further details regarding regulatory assets and liabilities, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report. Puget Energy recorded regulatory assets and liabilities at the time of the merger related to power purchase contracts. Allowance for Funds Used During Construction AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. The amount of AFUDC recorded in each accounting period varies depending primarily upon the level of construction work in progress and the AFUDC rate used. AFUDC is capitalized as a part of the cost of utility plant; the AFUDC debt portion is credited to interest expense, while the AFUDC equity portion is credited to other income. Cash inflow related to AFUDC does not occur until these charges are reflected in rates. The current AFUDC rate authorized by the Washington Commission for natural gas and electric utility plant additions through December 18, 2017 was 7.77% . Effective December 19, 2017 with the Washington Commission order, the new AFUDC rate authorized is 7.60% . The Washington Commission authorized the Company to calculate AFUDC using its allowed rate of return. To the extent amounts calculated using this rate exceed the AFUDC calculated rate using the Federal Energy Regulatory Commission (FERC) formula, PSE capitalizes the excess as a deferred asset, crediting other income. The deferred asset is being amortized over the average useful life of PSE’s non-project electric utility plant which is approximately 30 years . Revenue Recognition Operating utility revenue is recognized when the basis of services is rendered, which includes estimated unbilled revenue. Revenue from retail sales is billed based on tariff rates approved by the Washington Commission. PSE's estimate of unbilled revenue is based on a calculation using meter readings from its automated meter reading (AMR) system. The estimate calculates unbilled usage at the end of each month as the difference between the customer meter readings on the last day of the month and the last customer meter readings billed. The unbilled usage is then priced at published rates for each tariff rate schedule to estimate the unbilled revenues by customer. PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $239.3 million , $257.1 million and $235.3 million for 2018 , 2017 and 2016 , respectively. The Company reports the collection of such taxes on a gross basis in operation revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income. PSE's electric and natural gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, natural gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. The mechanism mitigates volatility in revenue and gross margin erosion due to weather and energy efficiency. Any differences in revenue are deferred to a regulatory asset for under recovery or regulatory liability for over recovery under alternative revenue recognition standard. Revenue is recognized under this program when deemed collectible within 24 months based on alternative revenue recognition guidance. Decoupled rate increases are effective May 1 of each year subject to a 3.0% cap of total revenue for decoupled rate schedules. Any excess revenue above 3.0% will be included in the following year's decoupled rate. The Company will be able to recognize revenue below the 3.0% cap of total revenue for decoupled rate schedules. For revenue deferrals exceeding the annual 3.0% rate cap of total revenue for decoupled rate schedules, the Company will assess the excess amount to determine its ability to be collected within 24 months. On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 general rate case (GRC) to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. The rate test which limits the amount of revenues PSE can collect in its annual filings increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The Company will not record any decoupling revenue that is expected to take longer than 24 months to collect following the end of the annual period in which the revenues would have otherwise been recognized. Once determined to be collectible within 24 months, any previously non-recognized amounts will be recognized. Revenues associated with energy costs under the power cost adjustment (PCA) mechanism and purchased gas adjustment (PGA) mechanism are excluded from the decoupling mechanism. Allowance for Doubtful Accounts Allowance for doubtful accounts are provided for electric and natural gas customer accounts based upon a historical experience rate of write-offs of energy accounts receivable along with information on future economic outlook. The allowance account is adjusted monthly for this experience rate. The allowance account is maintained until either receipt of payment or the likelihood of collection is considered remote at which time the allowance account and corresponding receivable balance are written off. The Company’s balance for allowance for doubtful accounts at December 31, 2018 and 2017 was $8.4 million and $8.9 million , respectively. Self-Insurance PSE is self-insured for storm damage and certain environmental contamination associated with current operations occurring on PSE-owned property. In addition, PSE is required to meet a deductible for a portion of the risk associated with comprehensive liability, workers’ compensation claims and catastrophic property losses other than those which are storm related. Under the December 5, 2017 Washington Commission order regarding PSE’s GRC, the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018. Additionally, costs may only be deferred if the outage meets the Institute of Electrical and Electronics Engineers (IEEE) outage criteria for system average interruption duration index. Federal Income Taxes For presentation in Puget Energy's and PSE’s separate financial statements, income taxes are allocated to the subsidiaries on the basis of separate company computations of tax, modified by allocating certain consolidated group limitations which are attributed to the separate company. Taxes payable or receivable are settled with Puget Holdings, which is the ultimate tax payer. Natural Gas Off-System Sales and Capacity Release PSE contracts for firm natural gas supplies and holds firm transportation and storage capacity sufficient to meet the expected peak winter demand for natural gas by its firm customers. Due to the variability in weather, winter peaking consumption of natural gas by most of its customers and other factors, PSE holds contractual rights to natural gas supplies and transportation and storage capacity in excess of its average annual requirements to serve firm customers on its distribution system. For much of the year, there is excess capacity available for third-party natural gas sales, exchanges and capacity releases. PSE sells excess natural gas supplies, enters into natural gas supply exchanges with third parties outside of its distribution area and releases to third parties excess interstate natural gas pipeline capacity and natural gas storage rights on a short-term basis to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. The proceeds from such activities, net of transactional costs, are accounted for as reductions in the cost of purchased natural gas and passed on to customers through the PGA mechanism, with no direct impact on net income. As a result, PSE nets the sales revenue and associated cost of sales for these transactions in purchased natural gas. As part of the Company’s electric operations, PSE purchases natural gas for its gas-fired generation facilities. The projected volume of natural gas for power is relative to the price of natural gas. Based on the market prices for natural gas, PSE may use the natural gas it has already purchased to generate power or PSE may sell the already purchased natural gas. The net proceeds from selling natural gas, previously purchased for power generation, are accounted for in electric operating revenue and are included in the PCA mechanism. Production Tax Credit Production Tax Credits (PTCs) represent federal income tax incentives available to taxpayers that generate energy from qualifying renewable sources during the first ten years of operation. From a regulatory perspective, the tax savings from these credits were intended to be refunded by PSE to its customers when monetized, used on the income tax return, through its revenue requirement as initially approved by the Washington Commission. As the Company has not generated taxable income and these credits have not been monetized, they have not been refunded to customers. Amounts to be refunded have been recorded as a liability with an offsetting reduction to revenue as it was intended to be refunded through the revenue requirement. A deferred tax asset and reduction to deferred tax expense were also recorded for PTCs not yet monetized. These entries resulted in no net income impact. In connection with the GRC settlement in 2017, the Washington Commission authorized the Company to utilize the tax savings associated with the monetization of the PTCs to fund the following: (i) Colstrip Community Transition Fund, (ii) unrecovered Colstrip plant and (iii) incurred decommissioning and remediation costs for Colstrip. As PTCs will no longer be refunded to customers through the revenue requirement, a non-cash increase to revenue and deferred tax expense will be recorded as the PTCs are monetized. These entries will result in no net income impact. At December 31, 2017 and 2018 , $2.1 million and $84.0 million of PTCs are estimated to be monetized through tax filings. Accounting for Derivatives ASC 815 requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value unless the contracts qualify for an exception. PSE enters into derivative contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts and swaps. Some of PSE’s physical electric supply contracts qualify for the normal purchase normal sale (NPNS) exception to derivative accounting rules. PSE may enter into financial fixed price contracts to economically hedge the variability of certain index-based contracts. Those contracts that do not meet the NPNS exception are marked-to-market to current earnings in the statements of income, subject to deferral under ASC 980, for natural gas related derivatives due to the PGA mechanism. For additional information, see Note 10 , "Accounting for Derivative Instruments and Hedging Activities" to the consolidated financial statements included in Item 8 of this report. Fair Value Measurements of Derivatives ASC 820, “Fair Value Measurements and Disclosures” (ASC 820), defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). As permitted under ASC 820, the Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements as it believes that the approach is used by market participants for these types of assets and liabilities. Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company values derivative instruments based on daily quoted prices from an independent external pricing service. When external quoted market prices are not available for derivative contracts, the Company uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves. All derivative instruments are sensitive to market price fluctuations that can occur on a daily basis. For additional information, see Note 11 , "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report. Debt Related Costs Debt premiums, discounts, expenses and amounts received or incurred to settle hedges are amortized over the life of the related debt for the Company. The premiums and costs associated with reacquired debt are deferred and amortized over the life of the related new issuance, in accordance with ratemaking treatment for PSE and presented net of long-term liabilities on the balance sheet.

New Accounting Pronouncements

New Accounting Pronouncements	12 Months Ended
	Dec. 31, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements	New Accounting Pronouncements Recently Adopted Accounting Guidance Retirement Benefits In March 2017, the FASB issued Accounting Standards Update (ASU) 2017-07, " Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost ". The amendments require that an employer report the service cost component in the same line items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The line item used in the income statement to present the other components of net benefit cost must be disclosed. Additionally, the service cost component of net benefit cost is the only eligible cost for capitalization. These amendments are effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company adopted ASU 2017-07 during the first quarter of fiscal year 2018 by applying the amendments related to the presentation of the service cost component and other components of net periodic pension cost retrospectively. For additional information, see Note 13, "Retirement Benefits" to the consolidated financial statements included in Item 8 of this report. Stranded Tax Effects in AOCI In February 2018, the FASB issued ASU 2018-02, " Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income " . The amendments in this update allow reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA and will improve the usefulness of information reported to financial statement users. These amendments are effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Early adoption is permitted, including adoption in any interim period for reporting periods for which financial statements have not yet been issued. The Company early adopted ASU 2018-02 as of January 1, 2018 and reclassified accumulated other comprehensive income to retained earnings, resulting in a $5.2 million increase for Puget Energy related to pension and post-retirement plans and a $27.3 million increase for PSE, comprised of $26.2 million related to pension and post-retirement plans and $1.1 million related to interest rate swaps. Statement of Cash Flows In August 2016, the FASB issued ASU 2016-15, " Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments ". The amendments in ASU 2016-15 provide guidance for eight specific cash flow issues that include (i) debt prepayment or debt extinguishment costs, (ii) settlement of zero-coupon debt instruments, (iii) contingent consideration payments made after a business combination, (iv) proceeds from the settlement of insurance claims, (v) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, (vi) distribution received from equity method investees, (vii) beneficial interest in securitization transactions, and (viii) separately identifiable cash flows and application of the predominance principle. This update is effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted for all entities upon issuance. The amendments in this update should be applied using a retrospective transition method to each period presented. The Company adopted ASU 2016-15 as of January 1, 2018, with the standard only impacting the classification of debt extinguishment costs as financing outflows. In November 2016, the FASB issued ASU 2016-18, " Statement of Cash Flows (Topic 230): Restricted Cash ". The amendments in this update require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The new standard is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company adopted ASU 2016-18 as of January 1, 2018, by moving the presentation of restricted cash in the statement of cash flows to net cash flows of total cash, cash equivalents, and restricted cash. Amounts included in restricted cash primarily represent funds required to be set aside for contractual obligations related to transmission and generation facilities. The following tables provide a reconciliation of cash, cash equivalents and restricted cash reported within the statements of cash flows: Puget Energy Twelve Months Ended December 31, (Dollars in Thousands) 2018 2017 Cash and cash equivalents $ 37,521 $ 26,616 Restricted cash 18,041 10,145 Total cash, cash equivalents and restricted cash shown in the statement of cash flows $ 55,562 $ 36,761 Puget Sound Energy Twelve Months Ended December 31, (Dollars in Thousands) 2018 2017 Cash and cash equivalents $ 35,452 $ 25,864 Restricted cash 18,041 10,145 Total cash, cash equivalents and restricted cash shown in the statement of cash flows $ 53,493 $ 36,009 Revenue Recognition In May 2014, the FASB issued ASU No. 2014-09, " Revenue from Contracts with Customers (Topic 606) ". ASU 2014-09 and the related amendments outline a single comprehensive model for use in accounting for revenue arising from contracts with customers and supersede most current revenue recognition guidance, including industry-specific guidance. The ASU is based on the principle that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to fulfill a contract. The Company implemented the standard as of January 1, 2018, using the modified retrospective method of adoption. As a result of implementation of this standard, the Company made no cumulative adjustments to revenue for contracts with customers open as of January 1, 2018. For the Twelve Months Ended December 31, the Company's revenue was 89.3% comprised of contracts with retail customers from rate-regulated sales of electricity and natural gas where revenue is recognized over time as delivered. Pursuant to the new standard, the Company has added enhanced quantitative and qualitative disclosures for revenue from contracts with customers and revenue outside the scope of the standard, in Note 3, "Revenue" to the consolidated financial statements included in Item 8 of this report. Accounting Standards Issued but Not Yet Adopted 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 will adopt this update prospectively beginning 2019 by evaluating future contracts for implementation costs incurred in hosting arrangements. The financial impact of this update has not yet been determined. 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 11, "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 13, "Retirement Benefits" to the consolidated financial statements. 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 (ROU) lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. To meet that objective, the FASB is amending the FASB ASC and creating 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 plans to elect this practical expedient, and will evaluate new and modified land easements prospectively, beginning January 1, 2019. 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. The Company is continuing to evaluate discount rate assumptions using the portfolio approach. 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 will adopt ASU 2016-02 as of January 1, 2019 and expects the adoption of the standard will result in recognition of right-of-use asset and lease liability financial statement line items that have not previously been recorded and will be material to the consolidated balance sheets. Adoption of the standard will not have a material impact on the income statement.

Regulation and Rates

Regulation and Rates	12 Months Ended
	Dec. 31, 2018
Regulated Operations [Abstract]
Regulation and Rates	(4) Regulation and Rates Regulatory Assets and Liabilities Regulatory accounting allows PSE to defer certain costs that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. It similarly requires deferral of revenues or gains that are expected to be returned to customers in the future. The net regulatory assets and liabilities at December 31, 2018 and 2017 , included the following: Puget Sound Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2018 2017 Storm damage costs electric 4 to 6 years 118,331 128,508 Chelan PUD contract initiation 12.8 years 90,964 98,052 Environmental remediation (a) 76,345 81,550 Lower Snake River 18.4 years 67,021 70,975 Decoupling deferrals and interest Less than 2 years 65,779 98,769 Baker Dam licensing operating and maintenance costs N/A 55,607 54,817 Deferred Washington Commission AFUDC 10 years 52,029 50,301 Property tax tracker Less than 2 years 45,621 36,517 Unamortized loss on reacquired debt 1 to 28 years 42,378 39,674 Colstrip 1 & 2 Regulatory Asset N/A 37,674 127,627 Energy conservation costs (a) 30,701 35,538 Generation plant major maintenance, excluding Colstrip 4 to 10 years 15,027 17,216 PGA deferral of unrealized losses on derivative instruments N/A 14,739 26,030 White River relicensing and other costs 3 years 12,966 19,502 Mint Farm ownership and operating costs 6.3 years 12,319 14,319 PGA receivable 1 year 9,922 — Snoqualmie licensing operating and maintenance costs N/A 7,407 7,341 Colstrip major maintenance 0.5 years 6,841 8,723 PCA mechanism N/A 4,735 4,576 Colstrip common property 6.4 years 3,903 4,618 Ferndale 0.8 years 3,316 7,295 Electron unrecovered loss Less than 1 year — 3,786 Various other regulatory assets (a) 14,583 17,382 Total PSE regulatory assets 788,208 953,116 Deferred income taxes (d) N/A (976,582 ) (1,012,260 ) Cost of removal (b) (424,727 ) (389,579 ) Treasury grants 20 years (168,884 ) (205,775 ) Production tax credits (c) (93,616 ) (93,616 ) Accumulated provision for rate refunds N/A (34,579 ) — Decoupling ROR excess earnings — (18,400 ) Decoupling deferrals and interest (13,758 ) (7,896 ) Total decoupling liability Less than 2 years (13,758 ) (26,296 ) Summit purchase option buy-out 1.8 years (2,888 ) (4,463 ) PGA payable 1 year — (16,051 ) Various other regulatory liabilities (a) (7,428 ) (10,544 ) Total PSE regulatory liabilities (1,722,462 ) (1,758,584 ) PSE net regulatory assets (liabilities) $ (934,254 ) $ (805,468 ) _______________ (a) Amortization periods vary depending on timing of underlying transactions. (b) The balance is dependent upon the cost of removal of underlying assets and the life of utility plant. (c) Amortization will begin once PTCs are utilized by PSE on its tax return. (d) For additional information, see Note 14,"Income Taxes" to the consolidated financial statements included in Item 8 of this report. Puget Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2018 2017 Total PSE regulatory assets (a) $ 788,208 $ 953,116 Puget Energy acquisition adjustments: Regulatory assets related to power contracts 1 to 20 years 16,693 19,454 Various other regulatory assets Varies — (8 ) Total Puget Energy regulatory assets 804,901 972,562 Total PSE regulatory liabilities (a) (1,722,462 ) (1,758,584 ) Puget Energy acquisition adjustments: Deferred income taxes 608 634 Regulatory liabilities related to power contracts 1 to 35 years (162,711 ) (174,918 ) Various other regulatory liabilities Varies (1,323 ) (1,314 ) Total Puget Energy regulatory liabilities (1,885,888 ) (1,934,182 ) Puget Energy net regulatory asset (liabilities) $ (1,080,987 ) $ (961,620 ) _______________ (a) Puget Energy’s regulatory assets and liabilities include purchase accounting adjustments under ASC 805. If the Company determines that it no longer meets the criteria for continued application of ASC 980, the Company would be required to write-off its regulatory assets and liabilities related to those operations not meeting ASC 980 requirements. Discontinuation of ASC 980 could have a material impact on the Company's financial statements. In accordance with guidance provided by ASC 410, “Asset Retirement and Environmental Obligations (ARO),” PSE reclassified from accumulated depreciation to a regulatory liability $424.7 million and $389.6 million in 2018 and 2017 , respectively, for the cost of removal of utility plant. These amounts are collected from PSE’s customers through depreciation rates. Expedited Rate Filing Rate Adjustment On November 7, 2018, PSE filed an expedited rate filing (ERF) with the Washington Commission. The filing is a request to change rates associated with PSE’s delivery and fixed production costs. It does not include variable power costs, purchased gas costs or natural gas pipeline replacement program costs, which are recovered in separate mechanisms. The filing is based on historical test year costs and rate base, and follows the reporting requirements of a Commission Basis Report, as defined by the Washington Administrative Code, but is filed using end of period rate base and certain annualizing adjustments. It does not include any forward-looking or pro-forma adjustments. Included in the filing is 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 resolve all issues in the filing. The settlement agreement was filed on January 30, 2019. The major points covered by the agreement are as follows. The agreed upon rate increases in the settlement are $21.5 million on natural gas and no rate increase on electric which would become effective March 1, 2019. Items that were not specifically identified in the settlement are deemed to offset these ARAM amounts to arrive at the settlement rate changes. The settlement agreement in PSE’s pending expedited rate change filing provides for the pass back beginning March 1, 2018 of the turnaround of plant related excess deferred income taxes on the average rate assumption method (ARAM) that resulted from the Tax Cuts and Jobs Act based on 2018 amounts in the amount of $6.1 million for natural gas and $25.9 million for electric. The settlement agreement leaves the determination for the regulatory treatment of the remaining items related to the TCJA to PSE’s next GRC: 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 through May 1, 2018, the requested effective date of the 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 to 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 that both deferrals should be or should not be recovered in the Company’s next GRC. The rate of return adopted in the settlement is the 7.49% included in the filing. The Washington Commission has suspended the procedural calendar in the proceeding and indicated it will not require a settlement hearing and will make their decision on whether or not to approve the settlement on the paper record in the filing. A ruling by the Washington Commission is expected in enough time to implement rates on March 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. 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. 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 ERF settlement, the excess deferred taxes associated with non-plant-related book/tax differences, the deferred balance associated with the over-collection of income tax expense 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 accounting petition in its next GRC. General Rate Case Filing In January 2017, PSE filed its GRC with the Washington Commission. The GRC filing included a required plan to address Colstrip Units 1 and 2 closures, requested that electric energy supply fixed costs be included in PSE's decoupling mechanism, and contained requests for two new mechanisms to address regulatory lag. The Washington Commission entered a final order accepting the multi-party settlement agreement and determined the contested issues in the case on December 5, 2017, and new rates became effective December 19, 2017. The settlement agreement provided for a weighted cost of capital of 7.6% , or 6.55% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.5% . The settlement also resulted in a combined electric tariff change that resulted in a net increase of $20.2 million , or 0.9% , annually, and a combined natural gas tariff change that resulted in a net decrease of $35.5 million , or 3.8% , annually. The GRC also re-purposed the benefit of PTCs and hydro-related treasury grants to fund and recover decommissioning and remediation costs for Colstrip Units 1 and 2. As the Company monetizes PTCs on its filed tax returns, the regulatory liability is transferred to a reserve for Colstrip Units 1 and 2 decommissioning and remediation costs. 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 December 31, 2018 , 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 $0.8 million of electric deferred revenue will not be collected within 24 months of the annual period; therefore, an adjustment was booked to 2018 decoupling revenue. The previously unrecognized decoupling deferrals of $20.8 million at December 31, 2016, were recognized as decoupling revenue in the year ended December 31, 2017 . 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. In 2018 and 2017 , PSE incurred $25.4 million and $30.4 million , respectively, in storm-related electric transmission and distribution system restoration costs, of which $15.1 million was deferred in 2018 and $21.6 million was deferred in 2017 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. Environmental Remediation The Company is subject to environmental laws and regulations by the federal, state and local authorities and is required to undertake certain environmental investigative and remedial efforts as a result of these laws and regulations. The Company has been named by the Environmental Protection Agency (EPA), the Washington State Department of Ecology and/or other third parties as potentially responsible at several contaminated sites and manufactured gas plant sites. In accordance with the guidance of ASC 450, “Contingencies,” the Company reviews its estimated future obligations and will record adjustments, if any, on a quarterly basis. Management believes it is probable and reasonably estimable that the impact of the potential outcomes of disputes with certain property owners and other potentially responsible parties will result in environmental remediation costs of $42.7 million for natural gas and $8.8 million for electric. The Company believes a significant portion of its past and future environmental remediation costs are recoverable from insurance companies, from third parties or from customers under a Washington Commission order. The Company is also subject to cost-sharing agreements with third parties regarding environmental remediation projects in Seattle, Washington and Bellingham, Washington. The Company has taken the lead for both projects, and as of December 31, 2018 , the Company’s share of future remediation costs is estimated to be approximately $32.2 million . The Company's deferred electric environmental costs are $14.1 million and $17.6 million at December 31, 2018 and 2017 , respectively, net of insurance proceeds. The Company's deferred natural gas environmental costs are $62.2 million and $63.9 million at December 31, 2018 and 2017 , respectively, net of insurance proceeds. In the GRC which became effective December 19, 2017, the Company had its third party recoveries and remediation costs incurred as of September 30, 2016, net of a portion of insurance, approved for amortization and inclusion in rates.

Dividend Payment Restrictions

Dividend Payment Restrictions	12 Months Ended
	Dec. 31, 2018
Dividend Payment Restrictions [Abstract]
Dividend Payment Restrictions	Dividend Payment Restrictions The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s electric and natural gas mortgage indentures. At December 31, 2018 , approximately $783.0 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant. Pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciation and amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3.0 to 1.0 . The common equity ratio, calculated on a regulatory basis, was 47.6% at December 31, 2018 , and the EBITDA to interest expense was 5.6 to 1.0 for the twelve months ended December 31, 2018 . PSE’s ability to pay dividends is also limited by the terms of its credit facilities, pursuant to which PSE is not permitted to pay dividends during any Event of Default (as defined in the facilities), or if the payment of dividends would result in an Event of Default, such as failure to comply with certain financial covenants. Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission. Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than 2.0 to 1.0 . Puget Energy's EBITDA to interest expense was 3.7 to 1.0 for the twelve months ended December 31, 2018 . At December 31, 2018 , the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

Utility Plant

Utility Plant	12 Months Ended
	Dec. 31, 2018
Utility Plant [Abstract]
Utility Plant	Utility Plant The following table presents electric, natural gas and common utility plant classified by account: Puget Energy Puget Sound Energy Utility Plant Estimated Useful Life At December 31, At December 31, (Dollars in Thousands) (Years) 2018 2017 2018 2017 Distribution plant 20-65 $ 6,122,739 $ 5,670,351 $ 7,722,024 $ 7,289,998 Production plant 12-90 3,099,805 3,068,135 3,974,250 3,954,057 Transmission plant 43-75 1,442,854 1,361,495 1,550,950 1,471,337 General plant 5-75 682,976 586,226 718,105 628,179 Intangible plant (including capitalized software) NA 662,328 447,568 652,942 438,185 Plant acquisition adjustment NA 242,826 242,826 282,792 282,792 Underground storage 25-60 35,404 31,815 48,874 45,288 Liquefied natural gas storage 25-60 12,628 12,628 14,498 14,498 Plant held for future use NA 39,384 53,428 39,536 53,580 Recoverable Cushion Gas NA 8,655 8,655 8,655 8,655 Plant not classified NA 239,857 275,014 239,857 275,014 Capital leases, net of accumulated amortization 1 NA 1,315 1,129 1,315 1,129 Less: accumulated provision for depreciation (2,832,321 ) (2,428,524 ) (5,495,348 ) (5,131,966 ) Subtotal $ 9,758,450 $ 9,330,746 $ 9,758,450 $ 9,330,746 Construction work in progress NA 550,466 495,937 550,466 495,937 Net utility plant $ 10,308,916 $ 9,826,683 $ 10,308,916 $ 9,826,683 _______________ 1 At December 31, 2018 and 2017 , accumulated amortization of capital leases at Puget Energy and PSE was $1.3 million and $0.7 million , respectively. Jointly owned generating plant service costs are included in utility plant service cost at the Company's ownership share. The Company provides financing for its ownership interest in the jointly owned utility plants. The following tables indicate the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2018 . These amounts are also included in the Utility Plant table above. The Company's share of fuel costs and operating expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income. Puget Energy Jointly Owned Generating Plants (Dollars in Thousands) Energy Source (Fuel) Company’s Ownership Share Plant in Service at Cost Construction Work in Progress Accumulated Depreciation Colstrip Units 1 & 2 Coal 50.0% $ 239,341 $ — $ (62,420 ) Colstrip Units 3 & 4 Coal 25.0% 318,736 — (98,641 ) Colstrip Units 1 – 4 Common Facilities Coal various 83 — (38 ) Frederickson 1 Natural Gas 49.85% 61,790 — (8,500 ) Jackson Prairie Natural Gas Storage 33.34% 33,831 404 (7,355 ) Tacoma LNG LNG various — 296,324 — _______________ 1 As of December 31, 2018 , PE's ownership share in Colstrip 1 & 2 plant-in-service includes $ 130.7 million in regulatory assets related to the 2017 GRC update to depreciation rates for the expected shutdown date of July 1, 2022. Puget Sound Energy Jointly Owned Generating Plants Energy Source (Fuel) Company’s Ownership Share Plant in Service at Cost Construction Work in Progress Accumulated Depreciation Colstrip Units 1 & 2 1 Coal 50.0% $ 368,242 $ — $ (191,323 ) Colstrip Units 3 & 4 Coal 25.0% 578,008 — (357,914 ) Colstrip Units 1 – 4 Common Facilities Coal various 252 — (206 ) Frederickson 1 Natural Gas 49.85% 67,858 — (14,567 ) Jackson Prairie Natural Gas Storage 33.34% 47,975 404 (21,499 ) Tacoma LNG LNG various — 130,756 — _______________ 1 As of December 31, 2018 , PSE's ownership share in Colstrip 1 & 2 plant-in-service includes $ 130.7 million in regulatory assets related to the 2017 GRC update to depreciation rates for the expected shutdown date of July 1, 2022. Asset Retirement Obligation The Company has recorded liabilities for steam generation sites, combustion turbine generation sites, wind generation sites, distribution and transmission poles, natural gas mains, and leased facilities where disposal is governed by ASC 410 “Asset Retirement and Environmental Obligations" (ARO). On April 17, 2015, the U.S. Environmental Protection Agency (EPA) published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCR) under the Resource Conservation and Recovery Act, Subtitle D. The CCR ruling requires the Company to perform an extensive study on the effects of coal ash on the environment and public health. The rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments. The CCR rule and two new legal agreements which include a consent decree with the Sierra Club and a settlement agreement with the Sierra Club and the National Wildlife Federation in 2016 make significant changes to the Company’s Colstrip operations and those changes were reviewed by the Company and the plant operator in 2015 and 2016. PSE had previously recognized a legal obligation in 2003 under EPA rules to dispose of coal ash material at Colstrip. The actual ARO costs related to the CCR rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs. We will continue to gather additional data and coordinate with the plant operator to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, the Company will update the ARO obligation for these changes, which could be material. For the twelve months ended December 31, 2018 and 2017, the Company reviewed the estimated remediation costs at Colstrip and reduced the Colstrip ARO liability by $11.0 million and $5.5 million for Colstrip Units 1 and 2 and $1.8 million and $12.7 million for Colstrip Units 3 and 4, respectively. The 2018 reductions to the Colstrip ARO liability are primarily based on the plant site remedy report approved by the Montana Department of Environmental Quality. For the twelve months ended December 31, 2018 and 2017, the Company also recorded the Colstrip relief of liability of $4.8 million and $3.8 million , respectively. In addition, the Company recorded Tacoma LNG facility ARO liability of $2.7 million for PSE and $2.2 million for Puget LNG as of December 31, 2017 . The following table describes the changes to the Company’s ARO for the year ended December 31, 2018 : Puget Energy and At December 31, (Dollars in Thousands) 2018 2017 Asset retirement obligation at beginning of the period $ 191,176 $ 200,345 New asset retirement obligation recognized in the period 501 2,881 Relief of liability (4,750 ) (3,841 ) Revisions in estimated cash flows (10,512 ) (13,748 ) Accretion expense 5,788 5,539 Asset retirement obligation at end of period 1 $ 182,203 $ 191,176 _______________ 1 Asset retirement obligations include $1.7 million and $2.2 million for Puget LNG held only at PE as of December 31, 2018 and 2017 , respectively. The Company has identified the following obligations, as defined by ASC 410, “ARO,” which were not recognized because the liability for these assets cannot be reasonably estimated at December 31, 2018 : • A legal obligation under Federal Dangerous Waste Regulations to dispose of asbestos-containing material in facilities that are not scheduled for remodeling, demolition or sales. The disposal cost related to these facilities could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated; • An obligation under Washington state law to decommission the wells at the Jackson Prairie natural gas storage facility upon termination of the project. Since the project is expected to continue as long as the Northwest pipeline continues to operate, the liability cannot be reasonably estimated; • An obligation to pay its share of decommissioning costs at the end of the functional life of the major transmission lines. The major transmission lines are expected to be used indefinitely; therefore, the liability cannot be reasonably estimated; • A legal obligation under Washington state environmental laws to remove and properly dispose of certain under and above ground fuel storage tanks. The disposal costs related to under and above ground storage tanks could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated; • An obligation to pay decommissioning costs at the end of utility service franchise agreements to restore the surface of the franchise area. The decommissioning costs related to facilities at the franchise area could not be measured since the decommissioning date is indeterminable; therefore, the liability cannot be reasonably estimated; and • A potential legal obligation may arise upon the expiration of an existing FERC hydropower license if FERC orders the project to be decommissioned, although PSE contends that FERC does not have such authority. Given the value of ongoing generation, flood control and other benefits provided by these projects, PSE believes that the potential for decommissioning is remote and cannot be reasonably estimated.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2018
Long-term Debt, Unclassified [Abstract]
Long-term Debt	Long-Term Debt The following table presents outstanding long-term debt principal amounts and due dates as of 2018 and 2017 : (Dollars in Thousands) At December 31, Series Type Due 2018 2017 Puget Sound Energy: 6.740% Senior Secured Note 1 2018 $ — $ 200,000 5.500% Promissory Note 2020 2,412 2,412 7.150% First Mortgage Bond 2025 15,000 15,000 7.200% First Mortgage Bond 2025 2,000 2,000 7.020% Senior Secured Note 2027 300,000 300,000 7.000% Senior Secured Note 2029 100,000 100,000 3.900% Pollution Control Bond 2031 138,460 138,460 4.000% Pollution Control Bond 2031 23,400 23,400 5.483% Senior Secured Note 2035 250,000 250,000 6.724% Senior Secured Note 2036 250,000 250,000 6.274% Senior Secured Note 2037 300,000 300,000 5.757% Senior Secured Note 2039 350,000 350,000 5.795% Senior Secured Note 2040 325,000 325,000 5.764% Senior Secured Note 2040 250,000 250,000 4.434% Senior Secured Note 2041 250,000 250,000 5.638% Senior Secured Note 2041 300,000 300,000 4.300% Senior Secured Note 2045 425,000 425,000 4.223% Senior Secured Note 2048 600,000 — 4.700% Senior Secured Note 2051 45,000 45,000 6.974% Junior Subordinated Note 2067 — 250,000 * Debt discount, issuance cost and other * (31,412 ) (26,361 ) Total PSE long-term debt 3,894,860 3,749,911 Puget Energy: * Fair value adjustment of PSE long-term debt * (182,372 ) (190,895 ) * Revolving Credit Agreement 2022 11,900 102,600 * Term Loan Agreement 2021 150,000 — 6.500% Senior Secured Note 2020 450,000 450,000 6.000% Senior Secured Note 2021 500,000 500,000 5.625% Senior Secured Note 2022 450,000 450,000 3.650% Senior Secured Note 2025 400,000 400,000 * Debt discount, issuance cost and other * (1,897 ) (3,687 ) Total Puget Energy long-term debt $ 5,672,491 $ 5,457,929 _______________ * Not Applicable. 1 6.74% Senior Secured Note in the amount of $200.0 million was classified on the Balance Sheet as a current maturity of long-term debt as of June 15, 2017. PSE's senior secured notes will cease to be secured by the pledged first mortgage bonds on the date that all of the first mortgage bonds issued and outstanding under the electric or natural gas utility mortgage indenture have been retired. As of December 31, 2018 , the latest maturity date of the first mortgage bonds, other than pledged first mortgage bonds, is December 22, 2025. Puget Energy Long-Term Debt On October 1, 2018, Puget Energy entered into a $150.0 million , three -year term loan agreement with a small group of banks. The agreement allows Puget Energy to borrow at either the banks' prime rate or at LIBOR plus a spread based on credit rating. The Term Loan Agreement also includes an expansion feature, pursuant to which Puget Energy may request to increase the aggregate amount of the Term Loan Agreement, obtain incremental term loans or any combination of increases and incremental term loans in an amount up to $100.0 million . The proceeds from the term loan will be used to repay borrowings under the revolving credit facility, which carries a higher interest rate. Puget Sound Energy Long-Term Debt PSE has in effect a shelf registration statement ("the existing shelf") under which it may issue, as of the date of this report, up to $200.0 million aggregate principal amount of senior notes secured by first mortgage bonds. The existing shelf will expire in November 2019. Substantially all utility properties owned by PSE are subject to the lien of the Company’s electric and natural gas mortgage indentures. To issue additional first mortgage bonds under these indentures, PSE’s earnings available for interest must exceed certain minimums as defined in the indentures. At December 31, 2018 , the earnings available for interest exceeded the required amount. On March 5, 2018, PSE commenced a tender offer and related consent solicitation to purchase any and all of the outstanding $250.0 million 6.974% Series A Enhanced Junior Subordinated Notes due June 1, 2067. Holders of the notes received $1,005 per $1,000 principal amount of notes plus accrued and unpaid interest for notes tendered and accepted by the early tender payment deadline of March 16, 2018. Holders of notes tendered after the early tender payment deadline, but prior to the tender offer expiration on April 2, 2018 were to receive the tender offer consideration of $975 per $1,000 of principal amount of the notes plus accrued but unpaid interest. A total of $193.4 million in principal amount of notes were tendered by the early payment deadline and no notes were tendered after the early payment deadline. On March 20, 2018, $194.9 million was paid to the holders of the tendered notes. This amount included the principal, early tender consideration and accrued interest up to, but not including March 20, 2018. Concurrently with the tender offer, PSE solicited consents from a majority (in principal amount) of the holders of PSE’s 6.274% Senior Notes due March 15, 2037 to terminate the replacement capital covenant granted to the holders of those notes. The termination of the covenant was necessary because it included restrictions related to repurchases, redemptions and repayments of the 6.974% Series A Enhanced Junior Subordinated Notes. PSE received consents from holders of 87.7% of the 6.274% Senior Notes and paid a consent fee totaling $2.6 million to those holders on March 19, 2018. On March 28, 2018, PSE issued a notice of redemption, effective April 27, 2018, for the remaining $56.6 million principal amount of the 6.974% Series A Enhanced Junior Subordinated Notes. The notes were redeemed at a price equal to 100% of their principal amount plus accrued and unpaid interest up to, but excluding the redemption date. On June 4, 2018, PSE issued $600.0 million of 30 -year Senior Notes under its senior note indenture at an interest rate of 4.223% with a maturity date of June 15, 2048. The proceeds from the issuance were used to pay the principal and accrued interest on the Company’s $200.0 million Secured Notes that matured on June 15, 2018, outstanding commercial paper borrowings of $348.0 million and other general corporate expenses. Long-Term Debt Maturities The principal amounts of long-term debt maturities for the next five years and thereafter are as follows: (Dollars in Thousands) 2019 2020 2021 2022 2023 Thereafter Total Maturities of: PSE $ — $ 2,412 $ — $ — $ — $ 3,923,860 $ 3,926,272 Puget Energy — 450,000 650,000 461,900 — 400,000 1,961,900 Total long-term debt $ — $ 452,412 $ 650,000 $ 461,900 $ — $ 4,323,860 $ 5,888,172

Liquidity Facilities and Other

Liquidity Facilities and Other Financing Arrangements	12 Months Ended
	Dec. 31, 2018
Liquidity Facilities and Other Financing Arrangements [Abstract]
Liquidity Facilities and Other Financing Arrangements	Liquidity Facilities and Other Financing Arrangements As of December 31, 2018 and 2017 , PSE had $379.3 million and $329.5 million in short-term debt outstanding, respectively. Outside of the consolidation of PSE’s short-term debt, Puget Energy had no short-term debt outstanding in either year as borrowings under its credit facility are classified as long-term. PSE’s weighted-average interest rate on short-term debt, including borrowing rate, commitment fees and the amortization of debt issuance costs, during 2018 and 2017 was 3.4% and 3.5% , respectively. As of December 31, 2018 , PSE and Puget Energy had several committed credit facilities that are described below. Puget Sound Energy Credit Facility In October 2017, PSE entered into a new $800.0 million credit facility which consolidates the two previous facilities into a single, smaller facility. All other features including fees, interest rate options, letter of credit, same day swingline borrowings, financial covenant and accordion feature remain substantially the same. The credit facility includes a swingline feature allowing same day availability on borrowings up to $ 75.0 million . The credit facility also has an expansion feature which, upon the banks' approval, would increase the total size of the facility to $ 1.4 billion . The unsecured revolving credit facility matures in October 2022. The credit agreement is syndicated among numerous lenders and contains usual and customary affirmative and negative covenants that, among other things, places limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreement also contains a financial covenant of total debt to total capitalization of 65% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of December 31, 2018 , PSE was in compliance with all applicable covenant ratios. The credit agreement provides PSE with the ability to borrow at different interest rate options. The credit agreement allows PSE to borrow at the bank's prime rate or to make floating rate advances at the London Interbank Offered Rate (LIBOR) plus a spread that is based upon PSE's credit rating. PSE must pay a commitment fee on the unused portion of the credit facility. The spreads and the commitment fee depend on PSE's credit ratings. As of the date of this report, the spread to the LIBOR is 1.25% and the commitment fee is 0.175% . As of December 31, 2018 , no amounts were drawn and outstanding under PSE's credit facility. No letters of credit were outstanding and $379.3 million was outstanding under the commercial paper program. Outside of the credit agreement, PSE had a $3.0 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada. Demand Promissory Note In 2006, PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a demand promissory note (Note) pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy. Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lower of the weighted-average interest rates of PSE’s outstanding commercial paper interest rate or PSE’s senior unsecured revolving credit facility. Absent such borrowings, interest is charged at one-month LIBOR plus 0.25% . As of December 31, 2018 , there was no outstanding balance under the Note. Puget Energy Credit Facility In October 2017, Puget Energy entered into a new $800.0 million credit facility to replace the existing facility. The terms and conditions, including fees, interest rate options, financial covenant, and expansion feature remain substantially the same. The new facility matures in October 2022. As of December 31, 2018 , there was $11.9 million drawn and outstanding under the facility. The Puget Energy revolving senior secured credit facility also has an expansion feature which, upon the banks' approval, would increase the size of the facility to $ 1.3 billion . The revolving senior secured credit facility provides Puget Energy the ability to borrow at different interest rate options and includes variable fee levels. Interest rates may be based on the bank's prime rate or LIBOR plus a spread based on Puget Energy's credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of the date of this report, the spread over LIBOR was 1.75% and the commitment fee was 0.275% . The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains a maximum leverage ratio financial covenant as defined in the agreement governing the senior secured credit facility. As of December 31, 2018 , Puget Energy was in compliance with all applicable covenants.

Leases

Leases	12 Months Ended
	Dec. 31, 2018
Leases [Abstract]
Leases	Leases PSE leases buildings and assets under operating leases. Certain leases contain purchase options, renewal options and escalation provisions. Payments received for the subleases of properties were immaterial for each of the years ended 2018 , 2017 and 2016 . Operating lease expenses net of sublease receipts were: (Dollars in Thousands) At December 31, Operating Lease Expense Years 2018 $ 34,093 2017 35,198 2016 31,786 The following table summarizes the Company’s estimated future minimum lease payments for non-cancelable leases net of sublease receipts, through the terms of its existing contracts: (Dollars in Thousands) Future Minimum Lease Payments At December 31, Years Operating Capital 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

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Accounting for Derivative Instruments and Hedging Activities	Accounting for Derivative Instruments and Hedging Activities PSE employs various energy portfolio optimization strategies, but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the PCA. Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility in costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. PSE's hedging strategy includes a risk-responsive component for the core natural gas portfolio, which utilizes quantitative risk-based measures with defined objectives to balance both portfolio risk and hedge costs. PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. Currently, the Company does not apply cash flow hedge accounting, and therefore records all mark-to-market gains or losses through earnings. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program, and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. The following table presents the volumes, fair values and classification of the Company's derivative instruments recorded on the balance sheets: Puget Energy and Puget Sound Energy At Year Ended December 31, (Dollars in Thousands) Volumes (millions) Assets 1 Liabilities² 2018 2017 2018 2017 2018 2017 Electric portfolio derivatives * * 33,287 13,391 27,284 49,050 Natural gas derivatives (MMBtus) 3 336.6 332.1 15,732 11,014 30,472 37,044 Total derivative contracts $ 49,019 $ 24,405 $ 57,756 $ 86,094 Current $ 46,507 $ 22,247 $ 46,661 $ 64,859 Long-term 2,512 2,158 11,095 21,235 Total derivative contracts $ 49,019 $ 24,405 $ 57,756 $ 86,094 _______________ 1 Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments. 2 Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments. 3 All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 194.8 million One Million British Thermal Units (MMBtus) and purchased electricity of 6.6 million megawatt hours (MWhs) at December 31, 2018 and 166.8 million MMBtus and 2.9 million MWhs at December 31, 2017 . It is the Company's policy to record all derivative transactions on a gross basis at the contract level without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements, which standardize physical power contracts; International Swaps and Derivatives Association (ISDA) agreements, which standardize financial natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical natural gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as the right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount. For further details regarding the fair value of derivative instruments, see Note 11, "Fair Value Measurements," to the consolidated financial statements included in Item 8 of this report. The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities: Puget Energy and Puget Sound Energy At December 31, 2018 (Dollars in Thousands) Gross Amounts Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 49,019 $ — $ 49,019 $ (25,388 ) $ — $ 23,631 Liabilities: Energy derivative contracts 57,756 — 57,756 (25,388 ) — 32,368 Puget Energy and Puget Sound Energy At December 31, 2017 (Dollars in Thousands) Gross Amounts Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 24,405 $ — $ 24,405 $ (17,940 ) $ — $ 6,465 Liabilities: Energy derivative contracts 86,094 — 86,094 (17,940 ) (353 ) 67,801 _______________ 1 All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of set-off. The following tables present the effect and locations of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income: Puget Energy and Year Ended December 31, (Dollars in Thousands) Location 2018 2017 2016 Interest rate contracts 1 : Non-hedged interest rate swap (expense) income $ — $ 28 $ (1,062 ) Interest expense — — — Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 23,186 (32,492 ) 62,318 Realized Electric generation fuel 26,222 (23,195 ) (39,656 ) Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 18,476 1,702 21,477 Realized Purchased electricity 12,240 (17,873 ) (21,998 ) Total gain (loss) recognized in income on derivatives $ 80,124 $ (71,830 ) $ 21,079 _______________ 1 Interest rate swap contracts were held at Puget Energy, and matured January 2017. The Company is exposed to credit risk primarily through buying and selling electricity and natural gas to serve its customers. Credit risk is the potential loss resulting from a counterparty's non-performance under an agreement. The Company manages credit risk with policies and procedures for, among other things, counterparty credit analysis, exposure measurement, and exposure monitoring and mitigation. The Company monitors counterparties for significant swings in credit default rates, credit rating changes by external rating agencies, ownership changes or financial distress. Where deemed appropriate, the Company may request collateral or other security from its counterparties to mitigate potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of December 31, 2018 , approximately 95.8% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, is with counterparties that are rated investment grade by rating agencies and 4.2% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies. The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors, such as credit default swaps and bond spreads, in the determination of reserves. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels. The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against unrealized gain (loss) positions. As of December 31, 2018 , the Company was in a net liability position with the majority of counterparties, so the default factors of counterparties did not have a significant impact on reserves for the period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. PSE also transacts power futures contracts on the Intercontinental Exchange (ICE), and natural gas contracts on the ICE NGX exchange platform. Execution of contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of December 31, 2018 , PSE had cash posted as collateral of $6.4 million related to contracts executed on the ICE platform. Also, as of December 31, 2018 , PSE has a $1.0 million letter of credit posted as collateral as a condition of transacting on the ICE NGX exchange. PSE did not trigger any collateral requirements with any of its counterparties during the twelve months ended December 31, 2018 , nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades. The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post: Puget Energy and Puget Sound Energy At December 31, (Dollars in Thousands) 2018 2017 Contingent Feature Fair Value 1 Liability Posted Collateral Contingent Collateral Fair Value 1 Liability Posted Collateral Contingent Collateral Credit rating 2 $ 574 $ — $ 574 $ 3,187 $ — $ 3,187 Requested credit for adequate assurance 18,495 — — 37,374 — — Forward value of contract 3 — — — 353 2,639 — Total $ 19,069 $ — $ 574 $ 40,914 $ 2,639 $ 3,187 _______________ 1 Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable. 2 Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral. 3 Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements ASC 820 established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy categorizes the inputs into three levels with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority given to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows: Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Equity securities that are also classified as cash equivalents are considered Level 1 if there are unadjusted quoted prices in active markets for identical assets or liabilities. Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options. Level 3 - Pricing inputs include significant inputs that have little or no observability as of the reporting date. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves, contract terms and prices, credit-risk adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs as substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service. The Company considers its electric and natural gas contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes are classified as Level 3 in the fair value hierarchy. Management's assessment is based on the trading activity in real-time and forward electric and natural gas markets. Each quarter, the Company confirms the validity of pricing-service quoted prices used to value Level 2 commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter. Assets and Liabilities with Estimated Fair Value The carrying values of cash and cash equivalents, restricted cash, and short-term debt as reported on the balance sheet are reasonable estimates of their fair value due to the short-term nature of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of other investments of $49.5 million and $48.5 million at December 31, 2018 and 2017 , respectively, are included in "Other property and investments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions. The fair value of the junior subordinated and long-term notes were estimated using the discounted cash flow method with U.S. Treasury yields and Company's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows: Puget Energy At December 31, 2018 At December 31, 2017 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ — $ — $ 250,000 $ 238,935 Long-term debt (fixed-rate), net of discount 1 2 5,510,591 6,443,742 5,105,329 6,520,515 Long-term debt (variable-rate) 2 161,900 161,900 102,600 102,600 Total $ 5,672,491 $ 6,605,642 $ 5,457,929 $ 6,862,050 Puget Sound Energy At December 31, 2018 At December 31, 2017 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ — $ — $ 250,000 $ 238,935 Long-term debt (fixed-rate), net of discount 2 2 3,894,860 4,574,611 3,499,911 4,550,130 Total $ 3,894,860 $ 4,574,611 $ 3,749,911 $ 4,789,065 _______________ 1 The carrying value includes debt issuances costs of $26.1 million and $27.9 million for December 31, 2018 and 2017 , respectively, which are not included in fair value. 2 The carrying value includes debt issuances costs of $24.6 million and $24.6 million for December 31, 2018 and 2017 , respectively, which are not included in fair value. Assets and Liabilities Measured at Fair Value on a Recurring Basis The following tables present the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis and the reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy and Fair Value Fair Value At December 31, 2018 At December 31, 2017 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 28,765 $ 4,522 $ 33,287 $ 9,866 $ 3,525 $ 13,391 Natural gas derivative instruments 12,247 3,485 15,732 6,973 4,041 11,014 Total derivative assets $ 41,012 $ 8,007 $ 49,019 $ 16,839 $ 7,566 $ 24,405 Liabilities: Electric derivative instruments 24,124 3,160 27,284 46,623 2,427 49,050 Natural gas derivative instruments 28,660 1,812 30,472 34,926 2,118 37,044 Total derivative liabilities $ 52,784 $ 4,972 $ 57,756 $ 81,549 $ 4,545 $ 86,094 Puget Energy and Puget Sound Energy Year Ended December 31, Level 3 Roll-Forward Net Asset(Liability) 2018 2017 2016 (Dollars in Thousands) Electric NaturalGas Total Electric NaturalGas Total Electric NaturalGas Total Balance at beginning of period $ 1,098 $ 1,923 $ 3,021 $ 972 $ 625 $ 1,597 $ (7,345 ) $ (2,383 ) $ (9,728 ) Changes during period Realized and unrealized energy derivatives: Included in earnings 1 34,604 — 34,604 2,781 — 2,781 4,007 — 4,007 Included in regulatory assets / liabilities — 6,075 6,075 — 6,346 6,346 — 4,312 4,312 Settlements 2 (33,067 ) (7,197 ) (40,264 ) (6,549 ) (6,372 ) (12,921 ) (1,129 ) (2,679 ) (3,808 ) Transferred into Level 3 (1,987 ) — (1,987 ) 523 (553 ) (30 ) (3,021 ) — (3,021 ) Transferred out Level 3 714 872 1,586 3,371 1,877 5,248 8,460 1,375 9,835 Balance at end of period $ 1,362 $ 1,673 $ 3,035 $ 1,098 $ 1,923 $ 3,021 $ 972 $ 625 $ 1,597 _______________ 1 Income Statement classification: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $1.1 million , $1.5 million and $2.0 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. 2 The Company had no purchases, sales or issuances during the reported periods. Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company's consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company's consolidated statements of income. In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company's commodity contracts extend beyond what is considered observable as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next, and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month, and reported in the Level 3 Roll-forward table above. The Company did not have any transfers between Level 2 and Level 1 during the years ended December 31, 2018 , 2017 and 2016 . The Company does periodically transact at locations, or market price points, that are illiquid or for which no prices are available from the independent pricing service. In such circumstances the Company uses a more liquid price point and performs a 15-month regression against the illiquid locations to serve as a proxy for market prices. Such transactions are classified as Level 3. The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs. The only significant unobservable input into the fair value measurement of the Company's Level 3 assets and liabilities is the forward price for electric and natural gas contracts. Below are the forward price ranges for the Company's commodity contracts, as of December 31, 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. At December 31, 2018 , a hypothetical 10% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $2.6 million . Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis Puget Energy records the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle. ASC 360 requires long-lived assets to be tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. One such triggering event is a significant decrease in the forward market prices of power. During 2018 and 2017 , Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. In 2018 and 2017 , due to decreases in forward power prices and decreases in forecasted revenue and cost estimates, the following impairments were recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability as follows: Puget Energy (Dollars in Thousands) Valuation Date Contract Name Carrying Value Fair Value Write Down March 31, 2018 Wells Hydro $ 4,302 $ 2,395 $ 1,907 Total 2018 Impairments $ 1,907 September 30, 2017 Wells Hydro $ 10,621 $ 9,609 $ 1,012 March 31, 2017 Wells Hydro 14,879 13,067 1,812 Rocky Reach 235,331 159,818 75,513 Priest Rapids RP 5,665 2,657 3,008 Total 2017 Impairments $ 81,345 The valuations were measured using a discounted cash flow, income-based valuation methodology. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates classified as Level 3 within the fair value hierarchy. A less significant input is the discount rate reflective of PSE's cost of capital used in the valuation. Below are significant unobservable inputs used in estimating the impaired long term power purchase contracts' fair value in 2018 and 2017 : Puget Energy Valuation Date Contract Unobservable Input Low High Average March 31, 2018 Wells Hydro Power prices (per MWh) $ 9.69 $ 25.30 $ 17.50 Power contract costs per quarter (in thousands) $ 4,126 $ 4,126 $ 4,126 September 30, 2017 Wells Hydro Power prices (per MWh) $ 14.06 $ 26.86 $ 22.24 Power contract costs per quarter (in thousands) $ 4,126 $ 4,126 $ 4,126 March 31, 2017 Wells Hydro Power prices (per MWh) $ 8.76 $ 26.70 $ 20.86 Power contract costs per quarter (in thousands) $ 3,965 $ 4,223 $ 4,051 Rocky Reach Power prices (per MWh) $ 8.53 $ 48.21 $ 27.69 Power contract costs per quarter (in thousands) $ 5,827 $ 6,780 $ 6,150 Priest Rapids RP Power prices (per MWh) $ 13.70 $ 29.38 $ 23.14 Power contract costs per year (in thousands) $ 620 $ 4,022 $ 2,306

Employee Investment Plans

Employee Investment Plans	12 Months Ended
	Dec. 31, 2018
Employee Investment Plans [Abstract]
Employee Investment Plans	Employee Investment Plans The Company's Investment Plan is a qualified employee 401(k) plan, under which employee salary deferrals and after-tax contributions are used to purchase several different investment fund options. PSE’s contributions to the employee Investment Plan were $20.7 million , $19.2 million and $17.2 million for the years 2018 , 2017 and 2016 , respectively. The employee Investment Plan eligibility requirements are set forth in the plan documents. Non-represented employees and United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry (UA) represented employees hired before January 1, 2014, and International Brotherhood of Electrical Workers Local Union 77 (IBEW) represented employees hired before December 12, 2014, have the following company contributions: • For employees under the Cash Balance retirement plan formula, PSE will match 100% of an employee's contribution up to 6.0% of plan compensation each paycheck, and will make an additional year-end contribution equal to 1.0% of base pay. • For employees grandfathered under the Final Average Earning retirement plan formula, PSE will match 55.0% of an employee’s contribution up to 6.0% of plan compensation each paycheck. Non-represented and UA-represented employees hired on or after January 1, 2014 along with IBEW-represented employees hired on or after December 12, 2014, will have access to the 401(k) plan. The two contribution sources from PSE are below: • 401(k) Company Matching: New non-represented, UA-represented and IBEW-represented employees will receive company match each paycheck based on a new schedule: 100% match on the first 3.0% of pay contributed and 50.0% match on the next 3.0% of pay contributed. An employee who contributes 6.0% of pay will receive 4.5% of pay in company match. Company matching will be immediately vested. • Company Contribution: New UA-represented employees will receive an annual company contribution of 4.0% of eligible pay placed in the Cash Balance retirement plan. New non-represented and IBEW-represented employees will receive an annual company contribution of 4.0% of eligible pay, placed either in the Investment Plan 401(k) plan or in PSE’s Cash Balance retirement plan. New non-represented and IBEW-represented employees will make a one-time election within 30 days of hire and direct that PSE put the 4.0% contribution either into the 401(k) plan or into an account in the Cash Balance retirement plan. The Company’s 4.0% contribution will vest after three years of service.

Retirement Benefits

Retirement Benefits	12 Months Ended
	Dec. 31, 2018
Retirement Benefits [Abstract]
Retirement Benefits	Retirement Benefits PSE has a defined benefit pension plan (Qualified Pension Benefits) covering a substantial majority of PSE employees. Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates. Starting with January 1, 2014, all United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry (UA) represented employees will receive annual pay contributions of 4.0% of eligible pay each year in the cash balance formula plan of the defined benefit pension. Starting January 1, 2014, for non-represented employees, and December 12, 2014 for employees represented by the IBEW, participants will receive annual employer contributions of 4.0% of eligible pay each year in the cash balance formula of the defined benefit pension or 401k plan account. Those employees receiving contributions in the cash balance formula plan also receive interest credits, which are at least 1.0% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, they will have annuity and lump sum options for distribution. PSE also 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. These benefits are provided principally through an insurance company. The insurance premiums, paid primarily by retirees, are based on the benefits provided during the prior year. Puget Energy's retirement plans were remeasured as a result of the merger in 2009, which represents the difference between Puget Energy and PSE's retirement plans. In March 2017, the FASB issued ASU 2017-07, requiring that an employer report the service cost component in the same line items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. Pursuant to the standard, the Company has retrospectively included in the consolidated statements of income: (i) the components of service cost within utility operations and maintenance for PSE and within non-utility expense and other for Puget Energy, and (ii) all non-service cost components in other income. The following tables summarize the Company’s change in benefit obligation, change in plan assets and amounts recognized in the Statements of Financial Position for the years ended December 31, 2018 and 2017 : Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2018 2017 2018 2017 2018 2017 Change in benefit obligation: Benefit obligation at beginning of period $ 700,481 $ 652,607 $ 55,754 $ 51,734 $ 11,454 $ 11,194 Amendments — — 1,446 — — — Service cost 22,757 20,081 847 913 69 72 Interest cost 27,303 28,373 2,120 2,285 444 500 Actuarial loss (gain) (29,067 ) 40,945 1,122 2,722 (379 ) 725 Benefits paid (42,662 ) (40,594 ) (5,581 ) (1,900 ) (1,037 ) (1,137 ) Medicare part D subsidy received — — — — 85 100 Administrative expense (1,169 ) (931 ) — — — — Benefit obligation at end of period $ 677,643 $ 700,481 $ 55,708 $ 55,754 $ 10,636 $ 11,454 Puget Energy and Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2018 2017 2018 2017 2018 2017 Change in plan assets: Fair value of plan assets at beginning of period $ 704,360 $ 620,260 $ — $ — $ 7,138 $ 7,200 Actual return on plan assets (38,379 ) 107,836 — — (395 ) 784 Employer contribution 18,000 18,000 5,581 1,900 254 291 Benefits paid (42,662 ) (40,594 ) (5,581 ) (1,900 ) (1,037 ) (1,137 ) Administrative expense (1,077 ) (1,142 ) — — — — Fair value of plan assets at end of period $ 640,242 $ 704,360 $ — $ — $ 5,960 $ 7,138 Funded status at end of period $ (37,401 ) $ 3,879 $ (55,708 ) $ (55,754 ) $ (4,676 ) $ (4,316 ) Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2018 2017 2018 2017 2018 2017 Amounts recognized in Statement of Financial Position consist of: Noncurrent assets $ — $ 3,879 $ — $ — $ — $ — Current liabilities — — (6,249 ) (5,486 ) (332 ) (317 ) Noncurrent liabilities (37,401 ) — (49,459 ) (50,268 ) (4,344 ) (3,999 ) Net assets (liabilities) $ (37,401 ) $ 3,879 $ (55,708 ) $ (55,754 ) $ (4,676 ) $ (4,316 ) Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2018 2017 2018 2017 2018 2017 Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets: Projected benefit obligation $ 677,643 $ 700,481 $ 55,708 $ 55,754 $ 10,636 $ 11,454 Accumulated benefit obligation 668,469 688,908 51,031 52,681 10,557 11,367 Fair value of plan assets 640,242 704,360 — — 5,960 7,138 The following tables summarize Puget Energy's and PSE's pension benefit amounts recognized in AOCI for the years ended December 31, 2018 and 2017 : Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2018 2017 2018 2017 2018 2017 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 94,929 $ 37,693 $ 9,612 $ 10,689 $ (2,564 ) $ (3,386 ) Prior service cost (credit) (5,863 ) (7,843 ) 1,607 204 — — Total $ 89,066 $ 29,850 $ 11,219 $ 10,893 $ (2,564 ) $ (3,386 ) Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2018 2017 2018 2017 2018 2017 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 229,819 $ 185,277 $ 11,450 $ 13,134 $ (3,857 ) $ (4,901 ) Prior service cost (credit) (4,659 ) (6,232 ) 1,609 208 — — Total $ 225,160 $ 179,045 $ 13,059 $ 13,342 $ (3,857 ) $ (4,901 ) The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, 2018 , 2017 and 2016 : Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2018 2017 2016 2018 2017 2016 2018 2017 2016 Components of net periodic benefit cost: Service cost $ 22,757 $ 20,081 $ 18,913 $ 847 $ 913 $ 1,085 $ 69 $ 72 $ 93 Interest cost 27,303 28,373 28,689 2,120 2,285 2,325 444 500 533 Expected return on plan assets (50,202 ) (47,784 ) (46,619 ) — — — (472 ) (461 ) (446 ) Amortization of prior service cost (credit) (1,980 ) (1,980 ) (1,980 ) 1,580 42 42 — — — Amortization of net loss (gain) 2,187 — — 42 1,077 911 (335 ) (402 ) (386 ) Net periodic benefit cost $ 65 $ (1,310 ) $ (997 ) $ 4,589 $ 4,317 $ 4,363 $ (294 ) $ (291 ) $ (206 ) Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2018 2017 2016 2018 2017 2016 2018 2017 2016 Components of net periodic benefit cost: Service cost $ 22,757 $ 20,081 $ 18,913 $ 847 $ 913 $ 1,085 $ 69 $ 72 $ 93 Interest cost 27,303 28,373 28,689 2,120 2,285 2,325 444 500 533 Expected return on plan assets (50,240 ) (47,862 ) (46,814 ) — — — (472 ) (461 ) (446 ) Amortization of prior service cost (credit) (1,573 ) (1,573 ) (1,573 ) 44 44 44 — — — Amortization of net loss (gain) 14,917 13,048 15,257 2,069 1,565 1,330 (556 ) (641 ) (632 ) Net periodic benefit cost $ 13,164 $ 12,067 $ 14,472 $ 5,080 $ 4,807 $ 4,784 $ (515 ) $ (530 ) $ (452 ) The following tables summarize Puget Energy's and PSE's benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, 2018 and 2017 : Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2018 2017 2018 2017 2018 2017 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 59,422 $ (18,896 ) $ 1,122 $ 2,722 $ 488 $ 403 Amortization of net (loss) gain (2,187 ) — (1,580 ) (1,076 ) 335 401 Settlements, mergers, sales, and closures — — (619 ) — — — Prior service cost (credit) — — 1,446 — — — Amortization of prior service (cost) credit 1,980 1,980 (42 ) (42 ) — — Total change in other comprehensive income for year $ 59,215 $ (16,916 ) $ 327 $ 1,604 $ 823 $ 804 Puget Sound Energy Qualified Pension Benefit SERP Pension Benefits Other Benefits (Dollars in Thousands) 2018 2017 2018 2017 2018 2017 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 59,460 $ (18,817 ) $ 1,122 $ 2,722 $ 488 $ 452 Amortization of net (loss) gain (14,917 ) (13,048 ) (2,069 ) (1,565 ) 556 641 Settlements, mergers, sales, and closures — — (737 ) — — — Prior service cost (credit) — — 1,446 — — — Amortization of prior service (cost) credit 1,573 1,573 (44 ) (44 ) — — Total change in other comprehensive income for year $ 46,116 $ (30,292 ) $ (282 ) $ 1,113 $ 1,044 $ 1,093 The estimated net (loss) gain and prior service cost (credit) for the pension plans that will be amortized from AOCI into net periodic benefit cost in 2019 by PSE include a $12.7 million net loss and a $1.6 million credit, respectively. The estimated net (loss) gain for the SERP that will be amortized from AOCI into net periodic benefit cost in 2019 is a net loss of $1.7 million . The estimated prior service cost (credit) for the SERP that will be amortized from AOCI into net periodic benefit cost in 2019 is a net loss of $0.3 million . The estimated net (loss) gain and prior service cost (credit) for the other postretirement plans that will be amortized from AOCI into net periodic benefit cost in 2019 is a net loss of $0.4 million . For Puget Energy, the overall amounts expected to be amortized from AOCI into net period benefit cost in 2019 is a net loss of $0.5 million . The aggregate expected contributions by the Company to fund the qualified pension plan, SERP and the other postretirement plans for the year ending December 31, 2019 are expected to be at least $18.0 million , $6.2 million and $0.3 million , respectively. Assumptions In accounting for pension and other benefit obligations and costs under the plans, the following weighted-average actuarial assumptions were used by the Company: Qualified Pension Benefits SERP Pension Benefits Other Benefits Benefit Obligation Assumptions 2018 2017 2016 2018 2017 2016 2018 2017 2016 Discount rate 4.40 % 4.00 % 4.50 % 4.40 % 4.00 % 4.50 % 4.40 % 4.00 % 4.50 % Rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Medical trend rate — — — — — — 7.60 6.80 8.80 Benefit Cost Assumptions Discount rate 4.40 % 4.50 % 4.65 % 4.40 % 4.50 % 4.65 % 4.40 % 4.50 % 4.65 % Return on plan assets 7.50 7.45 7.75 — — — 7.00 6.75 6.75 Rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Medical trend rate — — — — — — 7.60 9.50 5.30 The assumed medical inflation rate used to determine benefit obligations is 7.60% in 2019 grading down to 3.90% in 2020 . A 1.0% change in the assumed medical inflation rate would have the following effects: 2018 2017 (Dollars in Thousands) 1% Increase 1% Decrease 1% Increase 1% Decrease Effect on post-retirement benefit obligation $ 19 $ (18 ) $ 23 $ (22 ) Effect on service and interest cost components 1 (1 ) 1 (1 ) The Company has selected the expected return on plan assets based on a historical analysis of rates of return and the Company’s investment mix, market conditions, inflation and other factors. The expected rate of return is reviewed annually based on these factors. The Company’s accounting policy for calculating the market-related value of assets for the Company’s retirement plan is based on a five-year smoothing of asset gains (losses) measured from the expected return on market-related assets. This is a calculated value that recognizes changes in fair value in a systematic and rational manner over five years. The same manner of calculating market-related value is used for all classes of assets, and is applied consistently from year to year. Puget Energy’s pension and other postretirement benefits income or costs depend on several factors and assumptions, including plan design, timing and amount of cash contributions to the plan, earnings on plan assets, discount rate, expected long-term rate of return, and mortality and health care costs trends. Changes in any of these factors or assumptions will affect the amount of income or expense that Puget Energy records in its financial statements in future years and its projected benefit obligation. Puget Energy has selected an expected return on plan assets based on a historical analysis of rates of return and Puget Energy’s investment mix, market conditions, inflation and other factors. As required by merger accounting rules, market-related value was reset to market value effective with the merger. The discount rates were determined by using market interest rate data and the weighted-average discount rate from Citigroup Pension Liability Index Curve. The Company also takes into account in determining the discount rate the expected changes in market interest rates and anticipated changes in the duration of the plan liabilities. Plan Benefits The expected total benefits to be paid during the next five years and the aggregate total to be paid for the five years thereafter are as follows: (Dollars in Thousands) 2019 2020 2021 2022 2023 2024-2027 Qualified Pension total benefits $ 43,700 $ 45,100 $ 45,900 $ 47,100 $ 48,500 $ 252,400 SERP Pension total benefits 6,249 4,993 1,887 5,378 3,678 39,400 Other Benefits total with Medicare Part D subsidy 1,112 1,094 1,064 1,038 1,008 4,410 Other Benefits total without Medicare Part D subsidy 892 863 899 872 841 3,704 Plan Assets Plan contributions and the actuarial present value of accumulated plan benefits are prepared based on certain assumptions pertaining to interest rates, inflation rates and employee demographics, all of which are subject to change. Due to uncertainties inherent in the estimations and assumptions process, changes in these estimates and assumptions in the near term may be material to the financial statements. The Company has a Retirement Plan Committee that establishes investment policies, objectives and strategies designed to balance expected return with a prudent level of risk. All changes to the investment policies are reviewed and approved by the Retirement Plan Committee prior to being implemented. The Retirement Plan Committee invests trust assets with investment managers who have historically achieved above-median long-term investment performance within the risk and asset allocation limits that have been established. Interim evaluations are routinely performed with the assistance of an outside investment consultant. To obtain the desired return needed to fund the pension benefit plans, the Retirement Plan Committee has established investment allocation percentages by asset classes as follows: Allocation Asset Class Minimum Target Maximum Domestic large cap equity 25 % 31 % 40 % Domestic small cap equity — 9 15 Non-U.S. equity 10 25 30 Fixed income 15 25 30 Real estate — — 10 Absolute return 5 10 15 Cash — — 5 Plan Fair Value Measurements ASC 715, “Compensation – Retirement Benefits” (ASC 715) directs companies to provide additional disclosures about plan assets of a defined benefit pension or other postretirement plan. The objectives of the disclosures are to disclose the following: (i) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies; (ii) major categories of plan assets; (iii) inputs and valuation techniques used to measure the fair value of plan assets; (iv) effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period; and (v) significant concentrations of risk within plan assets. ASC 820 allows the reporting entity, as a practical expedient, to measure the fair value of investments that do not have readily determinable fair values on the basis of the net asset value per share of the investment if the net asset value of the investment is calculated in a matter consistent with ASC 946, “Financial Services – Investment Companies”. The standard requires disclosures about the nature and risk of the investments and whether the investments are probable of being sold at amounts different from the net asset value per share. The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, 2018 and 2017 : Recurring Fair Value Measures Recurring Fair Value Measures As of December 31, 2018 As of December 31, 2017 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual Funds $ 103,661 $ — $ 103,661 $ 117,796 $ — $ 117,796 Common Stock 177,949 — 177,949 209,504 — 209,504 Government Securities — — — 18,316 23,782 42,098 Corporate Bonds — — — — 34,588 34,588 Cash and cash equivalents — 702 702 2,684 9,304 11,988 Subtotal $ 281,610 $ 702 282,312 $ 348,300 $ 67,674 415,974 Investments measured at NAV 1 356,586 237,427 Net (payable) receivable 1,345 50,959 Total assets $ 640,243 $ 704,360 _______________ 1 In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that were measured at NAV per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV primarily consist of common/collective trust funds and two partnerships held as of December 31, 2018 . Mesirow Institutional Multi-Strategy Fund Partnership, L.P. utilizes a combination of long and short strategies through investments in investment funds. The major strategy allocations of the investment funds include (1) Investments in debt obligations of public and private entities; typically, in financial duress, and (2) Investments in equity positions on a global basis utilizing fundamental analysis. Grosvenor Institutional Partners Fund, L.P invests substantially all of the fund assets available in the Grosvenor Master Fund, a Cayman Islands exempted company which is sponsored, managed and has the same investment objective as the Partnership fund. In addition to the Master Fund, investments are made primarily in offshore investment funds, investment partnerships, and pooled investment vehicles; collectively referred to as Portfolio Funds, which generally implement "nontraditional" or "alternative" investment strategies. The following table sets forth by level, within the fair value hierarchy, the Other Benefits plan assets which consist of insurance benefits for retired employees, at fair value: Recurring Fair Value Measures Recurring Fair Value Measures As of December 31, 2018 As of December 31, 2017 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual fund 1 $ 5,910 $ — $ 5,910 $ 7,089 $ — $ 7,089 Investments measured at NAV 2 50 49 Total assets $ 5,960 $ 7,138 _______________ 1 This is a publicly traded balanced mutual fund. The fund seeks regular income, conservation of principal, and an opportunity for long-term growth of principal and income. The fair value is determined by taking the number of shares owned by the plan, and multiplying by the market price as of December 31, 2018 . 2 In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that were measured at NAV per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV consist of a common/collective trust fund as of December 31, 2018 .

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The details of income tax (benefit) expense are as follows: Puget Energy Year Ended December 31, (Dollars in Thousands) 2018 2017 2016 Charged to operating expenses: Current: Federal $ 10,382 $ 1,127 $ — State 263 17 20 Deferred: Federal 19,451 254,420 140,315 State (4 ) (421 ) (131 ) Total income tax expense $ 30,092 $ 255,143 $ 140,204 Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2018 2017 2016 Charged to operating expenses: Current: Federal $ 19,283 $ 1,127 $ — State 438 17 20 Deferred: Federal 30,979 210,842 175,327 State — — — Total income tax expense $ 50,700 $ 211,986 $ 175,347 The following reconciliation compares pre-tax book income at the federal statutory rate of 21.0% in 2018 and 35.0% in 2017 and 2016 to the actual income tax expense in the Statements of Income: Puget Energy Year Ended December 31, (Dollars in Thousands) 2018 2017 2016 Income taxes at the statutory rate $ 55,800 $ 148,847 $ 158,586 Increase (decrease): Production tax credit 1 — — (12,925 ) Utility plant differences 2 (25,871 ) — 3,966 Executive compensation 4,439 — — Treasury grant amortization (4,861 ) (9,537 ) (9,788 ) Tax reform — 117,185 — Other–net 585 (1,352 ) 365 Total income tax expense $ 30,092 $ 255,143 $ 140,204 Effective tax rate 11.3 % 60.0 % 30.9 % Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2018 2017 2016 Income taxes at the statutory rate $ 77,251 $ 185,430 $ 194,572 Increase (decrease): Production tax credit 1 — — (12,925 ) Utility plant differences 2 (25,871 ) — 3,966 Executive Compensation 4,439 — — Treasury grant amortization (4,861 ) (9,537 ) (9,788 ) Tax reform — 36,328 — Other–net (258 ) (235 ) (478 ) Total income tax expense $ 50,700 $ 211,986 $ 175,347 Effective tax rate 13.8 % 40.0 % 31.5 % _______________ 1 PSE's Wild Horse wind plant earned its last PTCs in December 2016. No further PTCs are expected. 2 Utility plant differences include the reversal of excess deferred taxes using the average rate assumption method in the amount of $29.8 million in 2018. The Company’s net deferred tax liability at December 31, 2018 and 2017 is composed of amounts related to the following types of temporary differences: Puget Energy At December 31, (Dollars in Thousands) 2018 2017 Utility plant and equipment $ 1,998,721 $ 2,034,328 Other deferred tax liabilities 113,051 172,048 Subtotal deferred tax liabilities 2,111,772 2,206,376 Net operating loss carryforward (224,885 ) (212,168 ) Net regulatory liability for income taxes (975,974 ) (1,011,626 ) Production tax credit carryforward (121,616 ) (187,617 ) Net other deferred tax assets — (48,097 ) Subtotal deferred tax assets (1,322,475 ) (1,459,508 ) Total net deferred tax liabilities $ 789,297 $ 746,868 Puget Sound Energy At December 31, (Dollars in Thousands) 2018 2017 Utility plant and equipment $ 1,998,721 $ 2,034,328 Other, net deferred tax liabilities 25,880 86,933 Subtotal deferred tax liabilities 2,024,601 2,121,261 Net regulatory liability for income taxes (976,582 ) (1,012,260 ) Production tax credit carryforward (121,616 ) (187,617 ) Net other deferred tax assets — (51,911 ) Subtotal deferred tax assets (1,098,198 ) (1,251,788 ) Total net deferred tax liabilities $ 926,403 $ 869,473 On December 22, 2017 , President Trump signed into law legislation referred to as the TCJA. Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017 . The TCJA includes significant changes to the Internal Revenue Code of 1986 (as amended, the Code), including amendments which significantly change the taxation of business entities and includes specific provisions related to regulated public utilities including PSE. The most significant change that impacts the Company included in the TCJA is the reduction in the corporate federal income tax rate from 35.0% to 21.0% and the limitation of deductibility of executive compensation. The specific provisions related to regulated public utilities in the TCJA generally allow for the continued deductibility of interest expense, the elimination of full expensing for tax purposes of certain property acquired after December 31, 2017, and continues normalization requirements for accelerated depreciation benefits. Under generally accepted accounting principles (US GAAP), specifically ASC Topic 740, Income Taxes, the tax effects of changes in tax laws must be recognized in the period in which the law is enacted and deferred tax assets and liabilities are to be re-measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. For PSE, the change in deferred taxes is recorded as either an offset to a regulatory asset or liability and is subject to approval by the Washington Commission. For Puget Energy, the change in deferred taxes is recorded as an adjustment to Puget Energy’s income tax expense, which decreased Puget Energy’s net income. Upon enactment of the TCJA, the Company re-measured its deferred tax assets and liabilities based upon the TCJA’s 21.0% percent corporate federal income tax rate. The corporate tax rate change for PSE is captured in the deferred tax balance with an offset to the regulatory liability for deferred income taxes. The balance of the regulatory deferred tax account at the beginning of 2017, before tax reform, was a $71.5 million asset. As a result of tax reform, the balance is a liability of $1,012.3 million . Since PSE is in a net regulatory liability position with respect to these income tax matters, PSE netted the regulatory asset for deferred income taxes against the regulatory liability for deferred income taxes. Under the normalization requirements continued by the TCJA, $919.8 million of the net regulatory liability related to certain accelerated tax depreciation benefits is to be reversed over the remaining lives of the related assets using ARAM. The remainder of the net regulatory liability of $92.5 million is available for PSE and the Washington Commission regulatory process to determine how the amounts will be refunded to customers. PSE requested to delay the impact of tax reform in an accounting petition which was filed with the Washington Commission on December 29, 2017 . For further details regarding PSE's ERF and Accounting Petition, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report. In 2018, the Company reversed excess deferred taxes for plant-related items using ARAM in the amount of $29.8 million . The impact of the TCJA to income tax expense as of December 31, 2017 was $36.3 million of which $3.0 million relates to deferred tax balances that are not subject to regulatory treatment. In addition, $33.3 million relates to the revaluation of the deferred tax for regulatory liability on PTC balances. The regulatory liability owed to customers for PTCs, which previously reduced revenue upon generation of the PTCs, was also revalued at the new rate of 21% . The change in the liability owed to customers for PTCs increased revenue by $51.2 million , which increased tax expense by $17.9 million , to reverse the initial deferral. The changes in the deferred tax and the liability owed to customers for PTCs had no impact on net income. Incrementally, Puget Energy increased its tax expense by $80.9 million primarily due to the revaluation of Puget Energy's net deferred tax asset on its net operating loss carryforward. The staff of the US Securities and Exchange Commission (SEC) has recognized the complexity of reflecting the impacts of the TCJA and on December 22, 2017, issued guidance in Staff Accounting Bulletin 118 (SAB 118). The guidance clarifies accounting for income taxes under ASC 740 if information is not yet available or complete and provides for up to a one year period in which to complete the required analysis and accounting (the measurement period). The Company completed the required analysis and accounting for the effects of the TCJA's enactment and did not identify any additional adjustments required. The Company calculates its deferred tax assets and liabilities under ASC 740, “Income Taxes” (ASC 740). ASC 740 requires recording deferred tax balances, at the currently enacted tax rate, on assets and liabilities that are reported differently for income tax purposes than for financial reporting purposes. The utilization of deferred tax assets requires sufficient taxable income in future years. ASC 740 requires a valuation allowance on deferred tax assets when it is more likely than not that the deferred tax assets will not be realized. PSE’s PTC carryforwards expire from 2031 through 2036. Puget Energy’s net operating loss carryforwards expire from 2029 through 2037. Net operating losses generated in 2018 and thereafter have no expiration date. No valuation allowance has been provided for PTC or net operating loss carryforwards. The Company accounts for uncertain tax positions under ASC 740, which clarifies the accounting for uncertainty in income taxes recognized in the financial statements. ASC 740 requires the use of a two-step approach for recognizing and measuring tax positions taken or expected to be taken in a tax return. First, a tax position should only be recognized when it is more likely than not, based on technical merits, that the position will be sustained upon challenge by the taxing authorities and taken by management to the court of last resort. Second, a tax position that meets the recognition threshold should be measured at the largest amount that has a greater than 50.0% likelihood of being sustained. As of December 31, 2018 and 2017 , the Company had no material unrecognized tax benefits. As a result, no interest or penalties were accrued for unrecognized tax benefits during the year. The Company has open tax years from 2015 through 2018. The Company classifies interest as interest expense and penalties as other expense in the financial statements.

Litigation

Litigation	12 Months Ended
	Dec. 31, 2018
Litigation Disclosure [Abstract]
Litigation	Litigation From time to time, the Company is involved in litigation or legislative rulemaking proceedings relating to its operations in the normal course of business. The following is a description of pending proceedings that are material to PSE’s operations: Colstrip PSE has a 50% ownership interest in Colstrip Units 1 and 2, and a 25% interest in 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 by no later than July 1, 2022. The Washington Commission allows full recovery in rates of the net book value (NBV) at retirement and related decommissioning costs consistent with prior precedents. 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. The increase in depreciation caused the Colstrip Units 1 and 2 regulatory asset to be reduced to $127.6 million as of December 31, 2017 . The balance of the Colstrip Units 1 and 2 regulatory asset was $130.7 million as of December 31, 2018 . The full scope of decommissioning activities and costs may vary from the estimates that are available at this time. The GRC also repurposed PTCs and hydro-related treasury grants to fund and recover decommissioning and remediation costs for Colstrip Units 1 and 2. Additionally, PSE will accelerate the depreciation of Colstrip Units 3 and 4, per the terms of the GRC settlement, to December 31, 2027. Greenwood In March 2016, a natural gas explosion occurred in the Greenwood neighborhood of Seattle, WA, damaging multiple structures. The Washington Commission Staff completed its investigation of the incident and filed a complaint in September 2016. In March 2017, pipeline safety regulators and PSE reached a settlement in response to the complaint. As part of the agreement, PSE paid a penalty of $1.5 million in 2017 , and is currently implementing a comprehensive inspection and remediation program. Regional Haze Rule In January 2017, the U.S. Environmental Protection Agency (EPA) published revisions to the Regional Haze Rule. Among other things, these revisions delayed new Regional Haze review from 2018 to 2021, however the end date will remain 2028. In January 2018, EPA announced that it was reconsidering certain aspects of these revisions and PSE is unable to predict the outcome. Clean Air Act 111(d)/EPA Clean Power Plan In June 2014, the EPA issued a proposed Clean Power Plan (CPP) rule under Section 111(d) of the Clean Air Act designed to regulate GHG emissions from existing power plants. The proposed rule includes state-specific goals and guidelines for states to develop plans for meeting these goals. The EPA published a final rule in October 2015. In March 2017, then EPA Administrator, Scott Pruitt, signed a notice of withdrawal of the proposed CPP federal plan and model trading rules and, in October 2017, the EPA proposed to repeal the CPP rule. In August 2018, the EPA proposed the Affordable Clean Energy rule to replace the 2015 Clean Power Plan. The Affordable Clean Energy establishes emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired power plants. Public comment closed on the proposed rule in October 2018 and PSE cannot yet predict a final outcome. Washington Clean Air Rule The CAR was adopted in September 2016, in Washington State and attempts to reduce greenhouse gas emissions from “covered entities” located within Washington State. Included under the new rule are large manufacturers, petroleum producers and natural gas utilities, including PSE. The CAR sets a cap on emissions associated with covered entities, which decreases over time approximately 5.0% every three years. Entities must reduce their carbon emissions, or purchase emission reduction units (ERUs), as defined under the rule, from others. In September 2016, PSE, along with Avista Corporation, Cascade Natural Gas Corporation and NW Natural, filed a lawsuit in the U.S. District Court for the Eastern District of Washington challenging the CAR. In September 2016, the four companies filed a similar challenge to the CAR in Thurston County Superior Court. In March 2018, the Thurston County Superior Court invalidated the CAR. The Department of Ecology appealed the Superior Court decision in May 2018. As a result of the appeal, direct review to the Washington State Supreme Court was granted and oral argument will be in the end of March 2019. The federal court litigation has been held in abeyance pending resolution of the state case.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies For the year ended December 31, 2018 , approximately 13.7% of the Company’s energy output was obtained at an average cost of approximately $0.023 per Kilowatt Hour (kWh) through long-term contracts with three of the Washington Public Utility Districts (PUDs) that own hydroelectric projects on the Columbia River. The purchase of power from the Columbia River projects is on a pro rata share basis under which the Company pays a proportionate share of the annual debt service, operating and maintenance costs and other expenses associated with each project, in proportion to the contractual share of power that PSE obtains from that project. In these instances, PSE’s payments are not contingent upon the projects being operable; therefore, PSE is required to make the payments even if power is not delivered. These projects are financed substantially through debt service payments and their annual costs should not vary significantly over the term of the contracts unless additional financing is required to meet the costs of major maintenance, repairs or replacements, or license requirements. The Company’s share of the costs and the output of the projects is subject to reduction due to various withdrawal rights of the PUDs and others over the contract lives. The Company's expenses under these PUD contracts were as follows for the years ended December 31: (Dollars in Thousands) 2018 2017 2016 PUD contract costs $ 80,165 $ 73,827 $ 77,667 As of December 31, 2018 , the Company purchased portions of the power output of the PUDs' projects as set forth in the following table: Company's Current Share of (Dollars in Thousands) Contract Expiration Percent of Output Megawatt Capacity Estimated 2019 Costs 2019 Debt Service Costs Interest included in 2019 Debt Service Costs Debt Outstanding Chelan County PUD: Rock Island Project 2031 25.0 % 156 $ 29,794 $ 10,058 $ 5,053 $ 80,058 Rocky Reach Project 2031 25.0 325 30,378 5,240 2,297 36,289 Douglas County PUD: Wells Project 1 2028 25.3 212 32,662 — — — Grant County PUD: Priest Rapids Development 2052 0.6 6 2,099 1,166 1,166 13,040 Wanapum Development 2052 0.6 7 2,099 1,166 1,166 13,040 Total 706 $ 97,032 $ 17,630 $ 9,682 $ 142,427 _______________ 1 In March 2017, PSE entered a new PPA with Douglas County PUD for Wells Project output that begins upon expiration of the existing contract on August 31, 2018 and continues through September 30, 2028. The following table summarizes the Company’s estimated payment obligations for power purchases from the Columbia River projects, contracts with other utilities, contracts with non-utilities and short term electric supply contracts. These contracts have varying terms and may include escalation and termination provisions. (Dollars in Thousands) 2019 2020 2021 2022 2023 Thereafter Total Columbia River projects $ 92,905 $ 86,691 $ 76,378 $ 85,807 $ 87,452 $ 631,283 $ 1,060,516 Other utilities 888 — — — — — 888 Non-utility contracts 216,539 255,193 264,262 264,740 269,886 1,221,204 2,491,824 Short-term electric supply contracts 117,040 4,029 — — — — 121,069 Total $ 427,372 $ 345,913 $ 340,640 $ 350,547 $ 357,338 $ 1,852,487 $ 3,674,297 Total purchased power contracts provided the Company with approximately 14.1 million , 14.5 million and 13.0 million MWhs of firm energy at a cost of approximately $508.2 million , $456.4 million and $402.5 million for the years 2018 , 2017 and 2016 , respectively. Natural Gas Supply Obligations The Company has entered into various firm supply, transportation and storage service contracts in order to ensure adequate availability of natural gas supply for its customers and generation requirements. The Company contracts for its long-term natural gas supply on a firm basis, which means the Company has a 100% daily take obligation and the supplier has a 100% daily delivery obligation to ensure service to PSE’s customers and generation requirements. The transportation and storage contracts, which have remaining terms from 1 year to 26 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. The Company incurred demand charges for 2018 for firm transportation, storage and peaking services for its natural gas customers of $119.9 million . The Company incurred demand charges in 2018 for firm transportation and storage services for the natural gas supply for its combustion turbines in the amount of $44.5 million . The following table summarizes the Company’s obligations for future natural gas supply and demand charges through the primary terms of its existing contracts. The quantified obligations are based on the FERC and NEB (National Energy Board) currently authorized rates, which are subject to change. Natural Gas Supply and Demand Charge Obligations (Dollars in Thousands) 2019 2020 2021 2022 2023 Thereafter Total Natural gas supply $ 311,601 $ 162,384 $ 157,156 $ 144,008 $ 91,851 $ — $ 867,000 Firm transportation service 165,719 160,053 140,239 139,343 120,486 209,215 935,055 Firm storage service 8,899 7,908 3,108 1,619 504 353 22,391 Short-term natural gas supply contracts 37,589 5,734 931 — — — 44,254 Total $ 523,808 $ 336,079 $ 301,434 $ 284,970 $ 212,841 $ 209,568 $ 1,868,700 Service Contracts The following table summarizes the Company’s estimated obligations for service contracts through the terms of its existing contracts. Service Contract Obligations (Dollars in Thousands) 2019 2020 2021 2022 2023 Thereafter Total Energy production service contracts $ 27,243 $ 27,915 $ 28,650 $ 29,345 $ 30,056 $ 124,646 $ 267,855 Automated meter reading system 45,080 44,193 44,741 45,416 46,106 142,724 368,260 Total $ 72,323 $ 72,108 $ 73,391 $ 74,761 $ 76,162 $ 267,370 $ 636,115 Other Commitments and Contingencies For information regarding PSE's environmental remediation obligations, see Note 4, "Regulation and Rates," to the consolidated financial statements included in Item 8 of this report.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Scott Armstrong serves on the Board of Directors of the Company and, until its acquisition by Kaiser Permanente on February 1, 2017 , was the President and Chief Executive Officer of Group Health Cooperative (Group Health), a health insurance and medical care provider. Certain employees of PSE elected Group Health as their medical provider prior to its acquisition by Kaiser Permanente and as a result, PSE paid Group Health a total of $3.9 million and $23.3 million for medical coverage for the year ended December 31, 2017 and 2016 . Kaiser Permanente is not considered a related party to PSE.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Segment Information	Segment Information Puget Energy and PSE operate one reportable segment referred to as the regulated utility segment. Puget Energy’s regulated utility operation generates, purchases and sells electricity and purchases, transports and sells natural gas. The service territory of PSE covers approximately 6,000 square miles in the state of Washington.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2018
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss ) The following tables present the changes in the Company’s (loss) AOCI by component for the years ended December 31, 2018 , 2017 and 2016 , respectively: Puget Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on energy derivative instruments Changes in AOCI, net of tax (Dollars in Thousands) Total Balance at December 31, 2015 $ (27,266 ) $ — $ (27,266 ) Other comprehensive income (loss) before reclassifications (5,528 ) — (5,528 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax (918 ) — (918 ) Net current-period other comprehensive income (loss) (6,446 ) — (6,446 ) Balance at December 31, 2016 $ (33,712 ) $ — $ (33,712 ) Other comprehensive income (loss) before reclassifications 10,251 — 10,251 Amounts reclassified from accumulated other comprehensive income (loss), net of tax (821 ) — (821 ) Net current-period other comprehensive income (loss) 9,430 — 9,430 Balance at December 31, 2017 $ (24,282 ) $ — $ (24,282 ) Other comprehensive income (loss) before reclassifications (48,870 ) — (48,870 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 1,180 — 1,180 Reclassification of stranded taxes to retained earnings due to tax reform (5,230 ) — (5,230 ) Net current-period other comprehensive income (loss) (52,920 ) — (52,920 ) Balance at December 31, 2018 $ (77,202 ) $ — $ (77,202 ) Puget Sound Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on energy derivative instruments Net unrealized gain (loss) on treasury interest rate swaps Changes in AOCI, net of tax (Dollars in Thousands) Total Balance at December 31, 2015 $ (143,877 ) $ — $ (5,673 ) $ (149,550 ) Other comprehensive income (loss) before reclassifications (5,655 ) — — (5,655 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 9,377 — 317 9,694 Net current-period other comprehensive income (loss) 3,722 — 317 4,039 Balance at December 31, 2016 $ (140,155 ) $ — $ (5,356 ) $ (145,511 ) Other comprehensive income (loss) before reclassifications 10,200 — — 10,200 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 8,088 — 317 8,405 Net current-period other comprehensive income (loss) 18,288 — 317 18,605 Balance at December 31, 2017 $ (121,867 ) $ — $ (5,039 ) $ (126,906 ) Other comprehensive income (loss) before reclassifications (48,802 ) — — (48,802 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 11,772 — 385 12,157 Reclassification of stranded taxes to retained earnings due to tax reform (26,233 ) — (1,100 ) (27,333 ) Net current-period other comprehensive income (loss) (63,263 ) — (715 ) (63,978 ) Balance at December 31, 2018 $ (185,130 ) $ — $ (5,754 ) $ (190,884 ) Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2018 , 2017 and 2016 , respectively, are as follows: Puget Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented Amount reclassified from accumulated other comprehensive income (loss) 2018 2017 2016 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,937 $ 1,938 $ 1,938 Amortization of net gain (loss) (a) (3,431 ) (675 ) (525 ) Total before tax (1,494 ) 1,263 1,413 Tax (expense) or benefit 314 (442 ) (495 ) Net of Tax (1,180 ) 821 918 Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: Electric derivatives Purchased electricity — — — Tax (expense) or benefit — — — Net of Tax — — — Total reclassification for the period Net of Tax $ (1,180 ) $ 821 $ 918 _______________ (a) These AOCI components are included in the computation of net periodic pension cost, see Note 13, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details. Puget Sound Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented Amount reclassified from accumulated other comprehensive income (loss) 2018 2017 2016 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,529 $ 1,529 $ 1,529 Amortization of net gain (loss) (a) (16,430 ) (13,972 ) (15,955 ) Total before tax (14,901 ) (12,443 ) (14,426 ) Tax (expense) or benefit 3,129 4,355 5,049 Net of tax (11,772 ) (8,088 ) (9,377 ) Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: Electric derivatives Purchased electricity — — — Tax (expense) or benefit — — — Net of Tax — — — Net unrealized gain (loss) on treasury interest rate swaps: Interest rate contracts Interest expense (487 ) (488 ) (488 ) Tax (expense) or benefit 102 171 171 Net of Tax (385 ) (317 ) (317 ) Total reclassification for the period Net of Tax $ (12,157 ) $ (8,405 ) $ (9,694 ) _______________ (a) These AOCI components are included in the computation of net periodic pension cost, see Note 13, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.

SCHEDULE I CONDENSED FINANCIAL

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY	12 Months Ended
	Dec. 31, 2018
Condensed Financial Information Disclosure [Abstract]
Schedule I: Condensed Financial Information of Puget Energy	SCHEDULE I: CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY Puget Energy Condensed Statements of Income and Comprehensive Income (Loss) (Dollars in Thousands) Year Ended December 31, 2018 2017 2016 Non-utility expense and other $ (1,345 ) $ (1,466 ) $ (5,252 ) Other income (deductions): Equity in earnings of subsidiary 320,122 323,568 385,838 Non-hedged interest rate swap expense — 28 (1,062 ) Interest income 4,273 1,039 2 Interest expense (108,816 ) (106,072 ) (104,600 ) Income taxes 21,388 (41,903 ) 37,973 Net income (loss) 235,622 175,194 312,899 Comprehensive income (loss) $ 182,702 $ 184,624 $ 306,453 See accompanying notes to the condensed financial statements. Puget Energy Condensed Balance Sheets (Dollars in Thousands) December 31, 2018 2017 Assets: Investment in subsidiaries $ 3,820,347 $ 3,721,553 Other property and investments: Goodwill 1,656,513 1,656,513 Current assets: Cash 2,067 751 Receivables from affiliates 1 138,714 78,570 Total current assets 140,781 79,321 Long-term assets: Deferred income taxes 221,660 208,889 Other 2,040 3,196 Total long-term assets 223,700 212,085 Total assets $ 5,841,341 $ 5,669,472 Capitalization and liabilities: Common equity $ 3,860,728 $ 3,750,030 Long-term debt 1,954,205 1,892,672 Total capitalization 5,814,933 5,642,702 Current liabilities: Account Payable 260 1,042 Interest 26,148 25,728 Total current liabilities 26,408 26,770 Commitments and contingencies (Note 16) Total capitalization and liabilities $ 5,841,341 $ 5,669,472 _______________ 1 Eliminated in consolidation. See accompanying notes to the condensed financial statements. Puget Energy Condensed Statements of Cash Flows (Dollars in Thousands) Year Ended December 31, 2018 2017 2016 Operating activities: Net cash provided by (used in) operating activities 79,176 $ 139,005 $ 145,719 Investing activities: Investment in subsidiaries — (24,222 ) — (Increase) decrease in loan to subsidiary (59,864 ) (78,155 ) — Other — (437 ) (6,078 ) Net cash provided by (used in) investing activities (59,864 ) (102,814 ) (6,078 ) Financing activities: Dividends paid (77,204 ) (123,307 ) (148,965 ) Issuance of bond 209,300 — — Issuance/redemption of term-loan and other long-term debt (150,000 ) 90,120 12,480 Issue costs and others (92 ) (2,650 ) (3,398 ) Net cash provided by (used in) by financing activities (17,996 ) (35,837 ) (139,883 ) Increase (decrease) in cash 1,316 354 (242 ) Cash at beginning of year 751 397 639 Cash at end of year $ 2,067 $ 751 $ 397 See accompanying notes to the condensed financial statements. NOTES TO CONDENSED FINANCIAL STATEMENTS (1) Basis of Presentation Puget Energy is an energy services holding company that conducts substantially all of its business operations through its regulated subsidiary, PSE. Puget Energy also has a wholly-owned non-regulated subsidiary, named Puget LNG, LLC (Puget LNG). Puget LNG was formed in November 2016, and has the sole purpose of owning, developing and financing the non-regulated activity of a liquefied natural gas (LNG) facility at the Port of Tacoma, Washington. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These financial statements, in which Puget Energy’s subsidiaries have been included using the equity method, should be read in conjunction with the consolidated financial statements and notes thereto of Puget Energy included in Item 8, "Financial Statements and Supplementary Data" of this Form 10-K. Puget Energy owns 100% of the common stock of its subsidiaries. Equity earnings of subsidiary included earnings from PSE of $317.2 million , $320.1 million and $380.6 million for the years ended December 31, 2018 , 2017 and 2016 , respectively, and business combination accounting adjustments under ASC 805 recorded at Puget Energy for PSE of $4.7 million , $3.9 million and $5.2 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. Investment in subsidiaries includes Puget Energy business combination accounting adjustments under ASC 805 that are recorded at Puget Energy. (2) Debt For information concerning Puget Energy’s long-term debt obligations, see Note 7, "Long-Term Debt" to the consolidated financial statements included in Item 8 of this report. (3) Commitments and Contingencies For information concerning Puget Energy’s material contingencies and guarantees, see Note 16, "Commitments and Contingencies" to the consolidated financial statements included in Item 8 of this report.

SCHEDULE II VALUATION AND QUALI

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES	12 Months Ended
	Dec. 31, 2018
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]
Schedule II: Valuation and Qualifying Accounts and Reserves	SCHEDULE II: VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Puget Energy and Puget Sound Energy (Dollars in Thousands) Balance at Beginning of Period Additions Charged to Costs and Expenses Deductions Balance at End of Period Year Ended December 31, 2018 Accounts deducted from assets on balance sheet: Allowance for doubtful accounts receivable $ 8,901 $ 24,846 $ 25,339 $ 8,408 Year Ended December 31, 2017 Accounts deducted from assets on balance sheet: Allowance for doubtful accounts receivable $ 9,798 $ 26,266 $ 27,163 $ 8,901 Year Ended December 31, 2016 Accounts deducted from assets on balance sheet: Allowance for doubtful accounts receivable $ 9,756 $ 24,389 $ 24,347 $ 9,798

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Puget Energy is an energy services holding company that owns Puget Sound Energy (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, Puget LNG, LLC (Puget LNG), which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma liquefied natural gas (LNG) facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that are incurred by PSE and allocated to Puget LNG are related party transactions by nature. In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805) purchase accounting adjustments. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.
Utility Plant	Utility Plant Puget Energy and PSE capitalize, at original cost, additions to utility plant, including renewals and betterments. Costs include indirect costs such as engineering, supervision, certain taxes, pension and other employee benefits and an allowance for funds used during construction (AFUDC). Replacements of minor items of property are included in maintenance expense. When the utility plant is retired and removed from service, the original cost of the property is charged to accumulated depreciation and costs associated with removal of the property, less salvage, are charged to the cost of removal regulatory liability. Planned Major Maintenance Planned major maintenance is an activity that typically occurs when PSE overhauls or substantially upgrades various systems and equipment on a scheduled basis. Costs related to planned major maintenance are deferred and amortized to the next scheduled major maintenance. This accounting method also follows the Washington Utilities and Transportation Commission (Washington Commission) regulatory treatment related to these generating facilities. Other Property and Investments For PSE, the costs of other property and investments (i.e., non-utility) are stated at historical cost. Expenditures for refurbishment and improvements that significantly add to productive capacity or extend useful life of an asset are capitalized. Replacements of minor items are expensed on a current basis. Gains and losses on assets sold or retired, which were previously recorded in utility plant, are apportioned between regulatory assets/liabilities and earnings. However, gains and losses on assets sold or retired, not previously recorded in utility plant, are reflected in earnings.
Depreciation and Amortization	Depreciation and Amortization The Company provides for depreciation and amortization on a straight-line basis. Amortization is recorded for intangibles such as regulatory assets and liabilities, computer software and franchises. The annual depreciation provision stated as a percent of a depreciable electric utility plant was 3.3% , 2.8% , and 2.8% in 2018 , 2017 and 2016 , respectively; depreciable natural gas utility plant was 2.8% , 3.4% , and 3.4% in 2018 , 2017 and 2016 , respectively; and depreciable common utility plant was 7.1% , 8.3% and 9.7% in 2018 , 2017 and 2016 , respectively. The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability.
Goodwill	Goodwill In 2009, Puget Holdings completed its merger with Puget Energy. Puget Energy re-measured the carrying amount of all its assets and liabilities to fair value, which resulted in recognition of approximately $1.7 billion in goodwill. The goodwill recorded by Puget Energy represents the potential long-term return to the Company’s investors. ASC 350, “Intangibles - Goodwill and Other” (ASC 350), requires that goodwill be tested for impairment at the reporting unit level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. These events or circumstances could include a significant change in the Company’s business or regulatory outlook, legal factors, a sale or disposition of a significant portion of a reporting unit or significant changes in the financial markets which could influence the Company’s access to capital and interest rates. Application of the goodwill impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, assignment of goodwill to reporting units and the determination of the fair value of the reporting units. Management has determined Puget Energy has only one reporting unit. In testing goodwill and other indefinite-lived intangible assets for impairment, the Company has the option of first performing a qualitative assessment to determine whether it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform a quantitative impairment test. If, after assessing the totality of events or circumstances during a qualitative assessment, management determines it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then the entity shall perform a quantitative test to determine impairment. This requires a comparison of the fair value of our reporting unit to its carrying value. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not impaired. If the carrying amount of a reporting unit exceeds its fair value, an impairment loss shall be recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to that reporting unit. In 2018 , the Company elected to perform the qualitative assessment to determine if it was more-likely-than-not that the fair value of Puget Energy’s reporting unit was below carrying value. This qualitative assessment included the review of several qualitative factors, including the value of Puget Energy’s reporting unit from the previous quantitative tests and the excess of fair value over carrying value from these tests, macroeconomic conditions, industry and market considerations, the projected financial performance of Puget Energy’s reporting unit, as well as other factors. Based on our assessment, the Company concluded that it was more-likely-than-not that the fair value of Puget Energy’s reporting unit exceeded its carrying value and, therefore, did not result in an impairment as of October 1, 2018 . There were no known events or circumstances from the date of the assessment through December 31, 2018 that would impact management’s conclusion. The Company elected to perform a quantitative impairment assessment in 2017 as of the October 1, 2017, measurement date. The fair value of Puget Energy’s reporting unit was estimated using a combination of the discounted cash flow and market approach. The discounted cash flow approach requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term rate of growth for Puget Energy business, estimation of the useful life over which cash flows will occur, the selection of utility holding companies determined to be comparable to Puget Energy and determination of an appropriate weighted-average cost of capital or discount rate. The market approach estimates the fair value of the business based on market prices of stocks of comparable companies engaged in the same or similar lines of business. In addition, indications of market value are estimated by deriving multiples of equity or invested capital to various measures of revenue, earnings or cash flow. Changes in these estimates and/or assumptions could materially affect the determination of fair value and goodwill impairment of the reporting unit. Based on the test performed, management determined that there was no indication of impairment of Puget Energy’s goodwill as of October 1, 2017. There were no known events or circumstances from the date of the assessment through December 31, 2017, that would impact management’s conclusion.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents consist of demand bank deposits and short-term highly liquid investments with original maturities of three months or less at the time of purchase. The carrying amounts of cash and cash equivalents are reported at cost and approximate fair value, due to the short-term maturity.
Materials and Supplies	Materials and Supplies Materials and supplies are used primarily in the operation and maintenance of electric and natural gas distribution and transmission systems as well as spare parts for combustion turbines used for the generation of electricity. The Company records these items at weighted-average cost.
Fuel and Gas Inventory	Fuel and Natural Gas Inventory Fuel and natural gas inventory is used in the generation of electricity and for future sales to the Company’s natural gas customers. Fuel inventory consists of coal, diesel and natural gas used for generation. Natural gas inventory consists of natural gas and LNG held in storage for future sales. The Company records these items at the lower of cost or net realizable value method.
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities PSE accounts for its regulated operations in accordance with ASC 980, “Regulated Operations” (ASC 980). ASC 980 requires PSE to defer certain costs or losses that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. It similarly requires deferral of revenues or gains that are expected to be returned to customers in the future. Accounting under ASC 980 is appropriate as long as rates are established by or subject to approval by independent third-party regulators; rates are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that rates set at levels that will recover costs can be charged to and collected from customers. In most cases, PSE classifies regulatory assets and liabilities as long-term when amortization periods extend longer than one year. For further details regarding regulatory assets and liabilities, see Note 4, "Regulation and Rates" to the consolidated financial statements included in Item 8 of this report.
Allowance for Funds Used During Construction	Allowance for Funds Used During Construction AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. The amount of AFUDC recorded in each accounting period varies depending primarily upon the level of construction work in progress and the AFUDC rate used. AFUDC is capitalized as a part of the cost of utility plant; the AFUDC debt portion is credited to interest expense, while the AFUDC equity portion is credited to other income. Cash inflow related to AFUDC does not occur until these charges are reflected in rates. The current AFUDC rate authorized by the Washington Commission for natural gas and electric utility plant additions through December 18, 2017 was 7.77% . Effective December 19, 2017 with the Washington Commission order, the new AFUDC rate authorized is 7.60% . The Washington Commission authorized the Company to calculate AFUDC using its allowed rate of return. To the extent amounts calculated using this rate exceed the AFUDC calculated rate using the Federal Energy Regulatory Commission (FERC) formula, PSE capitalizes the excess as a deferred asset, crediting other income. The deferred asset is being amortized over the average useful life of PSE’s non-project electric utility plant which is approximately 30 years .
Revenue Recognition	Revenue Recognition Operating utility revenue is recognized when the basis of services is rendered, which includes estimated unbilled revenue. Revenue from retail sales is billed based on tariff rates approved by the Washington Commission. PSE's estimate of unbilled revenue is based on a calculation using meter readings from its automated meter reading (AMR) system. The estimate calculates unbilled usage at the end of each month as the difference between the customer meter readings on the last day of the month and the last customer meter readings billed. The unbilled usage is then priced at published rates for each tariff rate schedule to estimate the unbilled revenues by customer. PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $239.3 million , $257.1 million and $235.3 million for 2018 , 2017 and 2016 , respectively. The Company reports the collection of such taxes on a gross basis in operation revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income. PSE's electric and natural gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, natural gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. The mechanism mitigates volatility in revenue and gross margin erosion due to weather and energy efficiency. Any differences in revenue are deferred to a regulatory asset for under recovery or regulatory liability for over recovery under alternative revenue recognition standard. Revenue is recognized under this program when deemed collectible within 24 months based on alternative revenue recognition guidance. Decoupled rate increases are effective May 1 of each year subject to a 3.0% cap of total revenue for decoupled rate schedules. Any excess revenue above 3.0% will be included in the following year's decoupled rate. The Company will be able to recognize revenue below the 3.0% cap of total revenue for decoupled rate schedules. For revenue deferrals exceeding the annual 3.0% rate cap of total revenue for decoupled rate schedules, the Company will assess the excess amount to determine its ability to be collected within 24 months. On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 general rate case (GRC) to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. The rate test which limits the amount of revenues PSE can collect in its annual filings increased from 3.0% to 5.0% for natural gas customers but will remain at 3.0% for electric customers. The Company will not record any decoupling revenue that is expected to take longer than 24 months to collect following the end of the annual period in which the revenues would have otherwise been recognized. Once determined to be collectible within 24 months, any previously non-recognized amounts will be recognized. Revenues associated with energy costs under the power cost adjustment (PCA) mechanism and purchased gas adjustment (PGA) mechanism are excluded from the decoupling mechanism.
Allowance for Doubtful Accounts	Allowance for Doubtful Accounts Allowance for doubtful accounts are provided for electric and natural gas customer accounts based upon a historical experience rate of write-offs of energy accounts receivable along with information on future economic outlook. The allowance account is adjusted monthly for this experience rate. The allowance account is maintained until either receipt of payment or the likelihood of collection is considered remote at which time the allowance account and corresponding receivable balance are written off. The Company’s balance for allowance for doubtful accounts at December 31, 2018 and 2017 was $8.4 million and $8.9 million , respectively.
Self Insurance	Self-Insurance PSE is self-insured for storm damage and certain environmental contamination associated with current operations occurring on PSE-owned property. In addition, PSE is required to meet a deductible for a portion of the risk associated with comprehensive liability, workers’ compensation claims and catastrophic property losses other than those which are storm related. Under the December 5, 2017 Washington Commission order regarding PSE’s GRC, the cumulative annual cost threshold for deferral of storms under the mechanism increased from $8.0 million to $10.0 million effective January 1, 2018. Additionally, costs may only be deferred if the outage meets the Institute of Electrical and Electronics Engineers (IEEE) outage criteria for system average interruption duration index.
Federal Income Taxes	Federal Income Taxes For presentation in Puget Energy's and PSE’s separate financial statements, income taxes are allocated to the subsidiaries on the basis of separate company computations of tax, modified by allocating certain consolidated group limitations which are attributed to the separate company. Taxes payable or receivable are settled with Puget Holdings, which is the ultimate tax payer.
Natural Gas Off System Sales and Capacity Release	Natural Gas Off-System Sales and Capacity Release PSE contracts for firm natural gas supplies and holds firm transportation and storage capacity sufficient to meet the expected peak winter demand for natural gas by its firm customers. Due to the variability in weather, winter peaking consumption of natural gas by most of its customers and other factors, PSE holds contractual rights to natural gas supplies and transportation and storage capacity in excess of its average annual requirements to serve firm customers on its distribution system. For much of the year, there is excess capacity available for third-party natural gas sales, exchanges and capacity releases. PSE sells excess natural gas supplies, enters into natural gas supply exchanges with third parties outside of its distribution area and releases to third parties excess interstate natural gas pipeline capacity and natural gas storage rights on a short-term basis to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. The proceeds from such activities, net of transactional costs, are accounted for as reductions in the cost of purchased natural gas and passed on to customers through the PGA mechanism, with no direct impact on net income.
Non-Core Gas Sales	As part of the Company’s electric operations, PSE purchases natural gas for its gas-fired generation facilities. The projected volume of natural gas for power is relative to the price of natural gas. Based on the market prices for natural gas, PSE may use the natural gas it has already purchased to generate power or PSE may sell the already purchased natural gas. The net proceeds from selling natural gas, previously purchased for power generation, are accounted for in electric operating revenue and are included in the PCA mechanism.
Production Tax Credit	Production Tax Credit Production Tax Credits (PTCs) represent federal income tax incentives available to taxpayers that generate energy from qualifying renewable sources during the first ten years of operation. From a regulatory perspective, the tax savings from these credits were intended to be refunded by PSE to its customers when monetized, used on the income tax return, through its revenue requirement as initially approved by the Washington Commission. As the Company has not generated taxable income and these credits have not been monetized, they have not been refunded to customers. Amounts to be refunded have been recorded as a liability with an offsetting reduction to revenue as it was intended to be refunded through the revenue requirement. A deferred tax asset and reduction to deferred tax expense were also recorded for PTCs not yet monetized. These entries resulted in no net income impact. In connection with the GRC settlement in 2017, the Washington Commission authorized the Company to utilize the tax savings associated with the monetization of the PTCs to fund the following: (i) Colstrip Community Transition Fund, (ii) unrecovered Colstrip plant and (iii) incurred decommissioning and remediation costs for Colstrip. As PTCs will no longer be refunded to customers through the revenue requirement, a non-cash increase to revenue and deferred tax expense will be recorded as the PTCs are monetized. These entries will result in no net income impact. At December 31, 2017 and 2018 , $2.1 million and $84.0 million of PTCs are estimated to be monetized through tax filings.
Accounting for Derivatives	Accounting for Derivatives ASC 815 requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value unless the contracts qualify for an exception. PSE enters into derivative contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts and swaps. Some of PSE’s physical electric supply contracts qualify for the normal purchase normal sale (NPNS) exception to derivative accounting rules. PSE may enter into financial fixed price contracts to economically hedge the variability of certain index-based contracts. Those contracts that do not meet the NPNS exception are marked-to-market to current earnings in the statements of income, subject to deferral under ASC 980, for natural gas related derivatives due to the PGA mechanism. For additional information, see Note 10 , "Accounting for Derivative Instruments and Hedging Activities" to the consolidated financial statements included in Item 8 of this report.
Fair Value Measurements of Derivatives	Fair Value Measurements of Derivatives ASC 820, “Fair Value Measurements and Disclosures” (ASC 820), defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). As permitted under ASC 820, the Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements as it believes that the approach is used by market participants for these types of assets and liabilities. Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company values derivative instruments based on daily quoted prices from an independent external pricing service. When external quoted market prices are not available for derivative contracts, the Company uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves. All derivative instruments are sensitive to market price fluctuations that can occur on a daily basis. For additional information, see Note 11 , "Fair Value Measurements" to the consolidated financial statements included in Item 8 of this report.
Debt Related Costs	Debt Related Costs Debt premiums, discounts, expenses and amounts received or incurred to settle hedges are amortized over the life of the related debt for the Company. The premiums and costs associated with reacquired debt are deferred and amortized over the life of the related new issuance, in accordance with ratemaking treatment for PSE and presented net of long-term liabilities on the balance sheet.

New Accounting Pronouncements C

New Accounting Pronouncements Cash, Cash Equivalents and Restricted Cash (Tables)	9 Months Ended
	Sep. 30, 2018
Restrictions on Cash and Cash Equivalents [Table Text Block]	The following tables provide a reconciliation of cash, cash equivalents and restricted cash reported within the statements of cash flows: Puget Energy Twelve Months Ended December 31, (Dollars in Thousands) 2018 2017 Cash and cash equivalents $ 37,521 $ 26,616 Restricted cash 18,041 10,145 Total cash, cash equivalents and restricted cash shown in the statement of cash flows $ 55,562 $ 36,761 Puget Sound Energy Twelve Months Ended December 31, (Dollars in Thousands) 2018 2017 Cash and cash equivalents $ 35,452 $ 25,864 Restricted cash 18,041 10,145 Total cash, cash equivalents and restricted cash shown in the statement of cash flows $ 53,493 $ 36,009

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Disaggregation of Revenue [Table Text Block]	The following table presents disaggregated revenue from contracts with customers, and other revenue by major source: Puget Energy and Puget Sound Energy (Dollars in Thousands) Twelve Months Ended December 31, Revenue from contracts with customers: 2018 Electric retail $ 2,138,008 Natural gas retail 849,898 Other 234,187 Total revenue from contracts with customers 3,222,093 Alternative revenue programs (22,852 ) Other non-customer revenue 147,255 Total operating revenue $ 3,346,496

Regulation and Rates (Tables)

Regulation and Rates (Tables)	12 Months Ended
	Dec. 31, 2018
Regulation and Rates [Line Items]
Schedule of Net Regulatory Assets and Liabilities	The net regulatory assets and liabilities at December 31, 2018 and 2017 , included the following: Puget Sound Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2018 2017 Storm damage costs electric 4 to 6 years 118,331 128,508 Chelan PUD contract initiation 12.8 years 90,964 98,052 Environmental remediation (a) 76,345 81,550 Lower Snake River 18.4 years 67,021 70,975 Decoupling deferrals and interest Less than 2 years 65,779 98,769 Baker Dam licensing operating and maintenance costs N/A 55,607 54,817 Deferred Washington Commission AFUDC 10 years 52,029 50,301 Property tax tracker Less than 2 years 45,621 36,517 Unamortized loss on reacquired debt 1 to 28 years 42,378 39,674 Colstrip 1 & 2 Regulatory Asset N/A 37,674 127,627 Energy conservation costs (a) 30,701 35,538 Generation plant major maintenance, excluding Colstrip 4 to 10 years 15,027 17,216 PGA deferral of unrealized losses on derivative instruments N/A 14,739 26,030 White River relicensing and other costs 3 years 12,966 19,502 Mint Farm ownership and operating costs 6.3 years 12,319 14,319 PGA receivable 1 year 9,922 — Snoqualmie licensing operating and maintenance costs N/A 7,407 7,341 Colstrip major maintenance 0.5 years 6,841 8,723 PCA mechanism N/A 4,735 4,576 Colstrip common property 6.4 years 3,903 4,618 Ferndale 0.8 years 3,316 7,295 Electron unrecovered loss Less than 1 year — 3,786 Various other regulatory assets (a) 14,583 17,382 Total PSE regulatory assets 788,208 953,116 Deferred income taxes (d) N/A (976,582 ) (1,012,260 ) Cost of removal (b) (424,727 ) (389,579 ) Treasury grants 20 years (168,884 ) (205,775 ) Production tax credits (c) (93,616 ) (93,616 ) Accumulated provision for rate refunds N/A (34,579 ) — Decoupling ROR excess earnings — (18,400 ) Decoupling deferrals and interest (13,758 ) (7,896 ) Total decoupling liability Less than 2 years (13,758 ) (26,296 ) Summit purchase option buy-out 1.8 years (2,888 ) (4,463 ) PGA payable 1 year — (16,051 ) Various other regulatory liabilities (a) (7,428 ) (10,544 ) Total PSE regulatory liabilities (1,722,462 ) (1,758,584 ) PSE net regulatory assets (liabilities) $ (934,254 ) $ (805,468 ) _______________ (a) Amortization periods vary depending on timing of underlying transactions. (b) The balance is dependent upon the cost of removal of underlying assets and the life of utility plant. (c) Amortization will begin once PTCs are utilized by PSE on its tax return. (d) For additional information, see Note 14,"Income Taxes" to the consolidated financial statements included in Item 8 of this report. Puget Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2018 2017 Total PSE regulatory assets (a) $ 788,208 $ 953,116 Puget Energy acquisition adjustments: Regulatory assets related to power contracts 1 to 20 years 16,693 19,454 Various other regulatory assets Varies — (8 ) Total Puget Energy regulatory assets 804,901 972,562 Total PSE regulatory liabilities (a) (1,722,462 ) (1,758,584 ) Puget Energy acquisition adjustments: Deferred income taxes 608 634 Regulatory liabilities related to power contracts 1 to 35 years (162,711 ) (174,918 ) Various other regulatory liabilities Varies (1,323 ) (1,314 ) Total Puget Energy regulatory liabilities (1,885,888 ) (1,934,182 ) Puget Energy net regulatory asset (liabilities) $ (1,080,987 ) $ (961,620 ) _______________ (a) Puget Energy’s regulatory assets and liabilities include purchase accounting adjustments under ASC 805.

Utility Plant (Tables)

Utility Plant (Tables)	12 Months Ended
	Dec. 31, 2018
Utility Plant [Abstract]
Schedule of Utility Plant	Puget Energy Puget Sound Energy Utility Plant Estimated Useful Life At December 31, At December 31, (Dollars in Thousands) (Years) 2018 2017 2018 2017 Distribution plant 20-65 $ 6,122,739 $ 5,670,351 $ 7,722,024 $ 7,289,998 Production plant 12-90 3,099,805 3,068,135 3,974,250 3,954,057 Transmission plant 43-75 1,442,854 1,361,495 1,550,950 1,471,337 General plant 5-75 682,976 586,226 718,105 628,179 Intangible plant (including capitalized software) NA 662,328 447,568 652,942 438,185 Plant acquisition adjustment NA 242,826 242,826 282,792 282,792 Underground storage 25-60 35,404 31,815 48,874 45,288 Liquefied natural gas storage 25-60 12,628 12,628 14,498 14,498 Plant held for future use NA 39,384 53,428 39,536 53,580 Recoverable Cushion Gas NA 8,655 8,655 8,655 8,655 Plant not classified NA 239,857 275,014 239,857 275,014 Capital leases, net of accumulated amortization 1 NA 1,315 1,129 1,315 1,129 Less: accumulated provision for depreciation (2,832,321 ) (2,428,524 ) (5,495,348 ) (5,131,966 ) Subtotal $ 9,758,450 $ 9,330,746 $ 9,758,450 $ 9,330,746 Construction work in progress NA 550,466 495,937 550,466 495,937 Net utility plant $ 10,308,916 $ 9,826,683 $ 10,308,916 $ 9,826,683 _______________ 1 At December 31, 2018 and 2017 , accumulated amortization of capital leases at Puget Energy and PSE was $1.3 million and $0.7 million , respectively.
Schedule of Jointly Owned Utility Plants	These amounts are also included in the Utility Plant table above. The Company's share of fuel costs and operating expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income. Puget Energy Jointly Owned Generating Plants (Dollars in Thousands) Energy Source (Fuel) Company’s Ownership Share Plant in Service at Cost Construction Work in Progress Accumulated Depreciation Colstrip Units 1 & 2 Coal 50.0% $ 239,341 $ — $ (62,420 ) Colstrip Units 3 & 4 Coal 25.0% 318,736 — (98,641 ) Colstrip Units 1 – 4 Common Facilities Coal various 83 — (38 ) Frederickson 1 Natural Gas 49.85% 61,790 — (8,500 ) Jackson Prairie Natural Gas Storage 33.34% 33,831 404 (7,355 ) Tacoma LNG LNG various — 296,324 — _______________ 1 As of December 31, 2018 , PE's ownership share in Colstrip 1 & 2 plant-in-service includes $ 130.7 million in regulatory assets related to the 2017 GRC update to depreciation rates for the expected shutdown date of July 1, 2022. Puget Sound Energy Jointly Owned Generating Plants Energy Source (Fuel) Company’s Ownership Share Plant in Service at Cost Construction Work in Progress Accumulated Depreciation Colstrip Units 1 & 2 1 Coal 50.0% $ 368,242 $ — $ (191,323 ) Colstrip Units 3 & 4 Coal 25.0% 578,008 — (357,914 ) Colstrip Units 1 – 4 Common Facilities Coal various 252 — (206 ) Frederickson 1 Natural Gas 49.85% 67,858 — (14,567 ) Jackson Prairie Natural Gas Storage 33.34% 47,975 404 (21,499 ) Tacoma LNG LNG various — 130,756 — _______________ 1 As of December 31, 2018 , PSE's ownership share in Colstrip 1 & 2 plant-in-service includes $ 130.7 million in regulatory assets related to the 2017 GRC update to depreciation rates for the expected shutdown date of July 1, 2022.
Schedule of Asset Retirement Obligations	The following table describes the changes to the Company’s ARO for the year ended December 31, 2018 : Puget Energy and At December 31, (Dollars in Thousands) 2018 2017 Asset retirement obligation at beginning of the period $ 191,176 $ 200,345 New asset retirement obligation recognized in the period 501 2,881 Relief of liability (4,750 ) (3,841 ) Revisions in estimated cash flows (10,512 ) (13,748 ) Accretion expense 5,788 5,539 Asset retirement obligation at end of period 1 $ 182,203 $ 191,176

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Instrument [Line Items]
Schedule of Long-Term Debt Instruments	Long-Term Debt The following table presents outstanding long-term debt principal amounts and due dates as of 2018 and 2017 : (Dollars in Thousands) At December 31, Series Type Due 2018 2017 Puget Sound Energy: 6.740% Senior Secured Note 1 2018 $ — $ 200,000 5.500% Promissory Note 2020 2,412 2,412 7.150% First Mortgage Bond 2025 15,000 15,000 7.200% First Mortgage Bond 2025 2,000 2,000 7.020% Senior Secured Note 2027 300,000 300,000 7.000% Senior Secured Note 2029 100,000 100,000 3.900% Pollution Control Bond 2031 138,460 138,460 4.000% Pollution Control Bond 2031 23,400 23,400 5.483% Senior Secured Note 2035 250,000 250,000 6.724% Senior Secured Note 2036 250,000 250,000 6.274% Senior Secured Note 2037 300,000 300,000 5.757% Senior Secured Note 2039 350,000 350,000 5.795% Senior Secured Note 2040 325,000 325,000 5.764% Senior Secured Note 2040 250,000 250,000 4.434% Senior Secured Note 2041 250,000 250,000 5.638% Senior Secured Note 2041 300,000 300,000 4.300% Senior Secured Note 2045 425,000 425,000 4.223% Senior Secured Note 2048 600,000 — 4.700% Senior Secured Note 2051 45,000 45,000 6.974% Junior Subordinated Note 2067 — 250,000 * Debt discount, issuance cost and other * (31,412 ) (26,361 ) Total PSE long-term debt 3,894,860 3,749,911 Puget Energy: * Fair value adjustment of PSE long-term debt * (182,372 ) (190,895 ) * Revolving Credit Agreement 2022 11,900 102,600 * Term Loan Agreement 2021 150,000 — 6.500% Senior Secured Note 2020 450,000 450,000 6.000% Senior Secured Note 2021 500,000 500,000 5.625% Senior Secured Note 2022 450,000 450,000 3.650% Senior Secured Note 2025 400,000 400,000 * Debt discount, issuance cost and other * (1,897 ) (3,687 ) Total Puget Energy long-term debt $ 5,672,491 $ 5,457,929 _______________ * Not Applicable. 1 6.74% Senior Secured Note in the amount of $200.0 million was classified on the Balance Sheet as a current maturity of long-term debt as of June 15, 2017.
Schedule of Maturities of Long-Term Debt	The principal amounts of long-term debt maturities for the next five years and thereafter are as follows: (Dollars in Thousands) 2019 2020 2021 2022 2023 Thereafter Total Maturities of: PSE $ — $ 2,412 $ — $ — $ — $ 3,923,860 $ 3,926,272 Puget Energy — 450,000 650,000 461,900 — 400,000 1,961,900 Total long-term debt $ — $ 452,412 $ 650,000 $ 461,900 $ — $ 4,323,860 $ 5,888,172

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2018
Leases [Abstract]
Schedule of Operating Lease Expense	Operating lease expenses net of sublease receipts were: (Dollars in Thousands) At December 31, Operating Lease Expense Years 2018 $ 34,093 2017 35,198 2016 31,786
Schedule of Future Minimum Lease Payments for Non-cancellable Leases	: (Dollars in Thousands) Future Minimum Lease Payments At December 31, Years Operating Capital 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

Accounting for Derivative Ins_2

Accounting for Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative [Line Items]
Schedule of Credit Risk Related Contingent Features [Table Text Block]	The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position and the amount of additional collateral the Company could be required to post: Puget Energy and Puget Sound Energy At December 31, (Dollars in Thousands) 2018 2017 Contingent Feature Fair Value 1 Liability Posted Collateral Contingent Collateral Fair Value 1 Liability Posted Collateral Contingent Collateral Credit rating 2 $ 574 $ — $ 574 $ 3,187 $ — $ 3,187 Requested credit for adequate assurance 18,495 — — 37,374 — — Forward value of contract 3 — — — 353 2,639 — Total $ 19,069 $ — $ 574 $ 40,914 $ 2,639 $ 3,187 _______________ 1 Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable. 2 Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral. 3 Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.
Offsetting Assets and Liabilities [Table Text Block]	The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities: Puget Energy and Puget Sound Energy At December 31, 2018 (Dollars in Thousands) Gross Amounts Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 49,019 $ — $ 49,019 $ (25,388 ) $ — $ 23,631 Liabilities: Energy derivative contracts 57,756 — 57,756 (25,388 ) — 32,368 Puget Energy and Puget Sound Energy At December 31, 2017 (Dollars in Thousands) Gross Amounts Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 24,405 $ — $ 24,405 $ (17,940 ) $ — $ 6,465 Liabilities: Energy derivative contracts 86,094 — 86,094 (17,940 ) (353 ) 67,801 _______________ 1 All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of set-off.
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 Year Ended December 31, (Dollars in Thousands) Volumes (millions) Assets 1 Liabilities² 2018 2017 2018 2017 2018 2017 Electric portfolio derivatives * * 33,287 13,391 27,284 49,050 Natural gas derivatives (MMBtus) 3 336.6 332.1 15,732 11,014 30,472 37,044 Total derivative contracts $ 49,019 $ 24,405 $ 57,756 $ 86,094 Current $ 46,507 $ 22,247 $ 46,661 $ 64,859 Long-term 2,512 2,158 11,095 21,235 Total derivative contracts $ 49,019 $ 24,405 $ 57,756 $ 86,094 _______________ 1 Balance sheet classification: Current and Long-term Unrealized gain on derivative instruments. 2 Balance sheet classification: Current and Long-term Unrealized loss on derivative instruments. 3 All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 194.8 million One Million British Thermal Units (MMBtus) and purchased electricity of 6.6 million megawatt hours (MWhs) at December 31, 2018 and 166.8 million MMBtus and 2.9 million MWhs at December 31, 2017 .
Parent Company [Member]
Derivative [Line Items]
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance [Table Text Block]	The following tables present the effect and locations of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income: Puget Energy and Year Ended December 31, (Dollars in Thousands) Location 2018 2017 2016 Interest rate contracts 1 : Non-hedged interest rate swap (expense) income $ — $ 28 $ (1,062 ) Interest expense — — — Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 23,186 (32,492 ) 62,318 Realized Electric generation fuel 26,222 (23,195 ) (39,656 ) Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 18,476 1,702 21,477 Realized Purchased electricity 12,240 (17,873 ) (21,998 ) Total gain (loss) recognized in income on derivatives $ 80,124 $ (71,830 ) $ 21,079
Subsidiaries [Member]
Derivative [Line Items]
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance [Table Text Block]	_______________ 1 Interest rate swap contracts were held at Puget Energy, and matured January 2017.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Liabilities, Quantitative Information	Puget Energy At December 31, 2018 At December 31, 2017 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ — $ — $ 250,000 $ 238,935 Long-term debt (fixed-rate), net of discount 1 2 5,510,591 6,443,742 5,105,329 6,520,515 Long-term debt (variable-rate) 2 161,900 161,900 102,600 102,600 Total $ 5,672,491 $ 6,605,642 $ 5,457,929 $ 6,862,050 Puget Sound Energy At December 31, 2018 At December 31, 2017 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ — $ — $ 250,000 $ 238,935 Long-term debt (fixed-rate), net of discount 2 2 3,894,860 4,574,611 3,499,911 4,550,130 Total $ 3,894,860 $ 4,574,611 $ 3,749,911 $ 4,789,065
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]	Puget Energy and Puget Sound Energy Year Ended December 31, Level 3 Roll-Forward Net Asset(Liability) 2018 2017 2016 (Dollars in Thousands) Electric NaturalGas Total Electric NaturalGas Total Electric NaturalGas Total Balance at beginning of period $ 1,098 $ 1,923 $ 3,021 $ 972 $ 625 $ 1,597 $ (7,345 ) $ (2,383 ) $ (9,728 ) Changes during period Realized and unrealized energy derivatives: Included in earnings 1 34,604 — 34,604 2,781 — 2,781 4,007 — 4,007 Included in regulatory assets / liabilities — 6,075 6,075 — 6,346 6,346 — 4,312 4,312 Settlements 2 (33,067 ) (7,197 ) (40,264 ) (6,549 ) (6,372 ) (12,921 ) (1,129 ) (2,679 ) (3,808 ) Transferred into Level 3 (1,987 ) — (1,987 ) 523 (553 ) (30 ) (3,021 ) — (3,021 ) Transferred out Level 3 714 872 1,586 3,371 1,877 5,248 8,460 1,375 9,835 Balance at end of period $ 1,362 $ 1,673 $ 3,035 $ 1,098 $ 1,923 $ 3,021 $ 972 $ 625 $ 1,597 _______________ 1 Income Statement classification: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $1.1 million , $1.5 million and $2.0 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. 2 The Company had no purchases, sales or issuances during the reported periods.
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Table Text Block]	Below are the forward price ranges for the Company's commodity contracts, as of December 31, 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. Below are significant unobservable inputs used in estimating the impaired long term power purchase contracts' fair value in 2018 and 2017 : Puget Energy Valuation Date Contract Unobservable Input Low High Average March 31, 2018 Wells Hydro Power prices (per MWh) $ 9.69 $ 25.30 $ 17.50 Power contract costs per quarter (in thousands) $ 4,126 $ 4,126 $ 4,126 September 30, 2017 Wells Hydro Power prices (per MWh) $ 14.06 $ 26.86 $ 22.24 Power contract costs per quarter (in thousands) $ 4,126 $ 4,126 $ 4,126 March 31, 2017 Wells Hydro Power prices (per MWh) $ 8.76 $ 26.70 $ 20.86 Power contract costs per quarter (in thousands) $ 3,965 $ 4,223 $ 4,051 Rocky Reach Power prices (per MWh) $ 8.53 $ 48.21 $ 27.69 Power contract costs per quarter (in thousands) $ 5,827 $ 6,780 $ 6,150 Priest Rapids RP Power prices (per MWh) $ 13.70 $ 29.38 $ 23.14 Power contract costs per year (in thousands) $ 620 $ 4,022 $ 2,306
Schedule of Impaired Intangible Assets [Table Text Block]	n 2018 and 2017 , due to decreases in forward power prices and decreases in forecasted revenue and cost estimates, the following impairments were recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability as follows: Puget Energy (Dollars in Thousands) Valuation Date Contract Name Carrying Value Fair Value Write Down March 31, 2018 Wells Hydro $ 4,302 $ 2,395 $ 1,907 Total 2018 Impairments $ 1,907 September 30, 2017 Wells Hydro $ 10,621 $ 9,609 $ 1,012 March 31, 2017 Wells Hydro 14,879 13,067 1,812 Rocky Reach 235,331 159,818 75,513 Priest Rapids RP 5,665 2,657 3,008 Total 2017 Impairments $ 81,345
Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following tables present the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis and the reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy and Fair Value Fair Value At December 31, 2018 At December 31, 2017 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 28,765 $ 4,522 $ 33,287 $ 9,866 $ 3,525 $ 13,391 Natural gas derivative instruments 12,247 3,485 15,732 6,973 4,041 11,014 Total derivative assets $ 41,012 $ 8,007 $ 49,019 $ 16,839 $ 7,566 $ 24,405 Liabilities: Electric derivative instruments 24,124 3,160 27,284 46,623 2,427 49,050 Natural gas derivative instruments 28,660 1,812 30,472 34,926 2,118 37,044 Total derivative liabilities $ 52,784 $ 4,972 $ 57,756 $ 81,549 $ 4,545 $ 86,094

Retirement Benefits (Tables)

Retirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2018
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Schedule of Changes in Projected Benefit Obligations	The following tables summarize the Company’s change in benefit obligation, change in plan assets and amounts recognized in the Statements of Financial Position for the years ended December 31, 2018 and 2017 : Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2018 2017 2018 2017 2018 2017 Change in benefit obligation: Benefit obligation at beginning of period $ 700,481 $ 652,607 $ 55,754 $ 51,734 $ 11,454 $ 11,194 Amendments — — 1,446 — — — Service cost 22,757 20,081 847 913 69 72 Interest cost 27,303 28,373 2,120 2,285 444 500 Actuarial loss (gain) (29,067 ) 40,945 1,122 2,722 (379 ) 725 Benefits paid (42,662 ) (40,594 ) (5,581 ) (1,900 ) (1,037 ) (1,137 ) Medicare part D subsidy received — — — — 85 100 Administrative expense (1,169 ) (931 ) — — — — Benefit obligation at end of period $ 677,643 $ 700,481 $ 55,708 $ 55,754 $ 10,636 $ 11,454
Schedule of Changes in Fair Value of Plan Assets	Puget Energy and Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2018 2017 2018 2017 2018 2017 Change in plan assets: Fair value of plan assets at beginning of period $ 704,360 $ 620,260 $ — $ — $ 7,138 $ 7,200 Actual return on plan assets (38,379 ) 107,836 — — (395 ) 784 Employer contribution 18,000 18,000 5,581 1,900 254 291 Benefits paid (42,662 ) (40,594 ) (5,581 ) (1,900 ) (1,037 ) (1,137 ) Administrative expense (1,077 ) (1,142 ) — — — — Fair value of plan assets at end of period $ 640,242 $ 704,360 $ — $ — $ 5,960 $ 7,138 Funded status at end of period $ (37,401 ) $ 3,879 $ (55,708 ) $ (55,754 ) $ (4,676 ) $ (4,316 )
Schedule of Amounts Recognized in Balance Sheet and Accumulated Other Comprehensive Income	Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2018 2017 2018 2017 2018 2017 Amounts recognized in Statement of Financial Position consist of: Noncurrent assets $ — $ 3,879 $ — $ — $ — $ — Current liabilities — — (6,249 ) (5,486 ) (332 ) (317 ) Noncurrent liabilities (37,401 ) — (49,459 ) (50,268 ) (4,344 ) (3,999 ) Net assets (liabilities) $ (37,401 ) $ 3,879 $ (55,708 ) $ (55,754 ) $ (4,676 ) $ (4,316 )
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets [Table Text Block]	Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2018 2017 2018 2017 2018 2017 Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets: Projected benefit obligation $ 677,643 $ 700,481 $ 55,708 $ 55,754 $ 10,636 $ 11,454 Accumulated benefit obligation 668,469 688,908 51,031 52,681 10,557 11,367 Fair value of plan assets 640,242 704,360 — — 5,960 7,138
Schedule of Net Benefit Costs	The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, 2018 , 2017 and 2016 : Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2018 2017 2016 2018 2017 2016 2018 2017 2016 Components of net periodic benefit cost: Service cost $ 22,757 $ 20,081 $ 18,913 $ 847 $ 913 $ 1,085 $ 69 $ 72 $ 93 Interest cost 27,303 28,373 28,689 2,120 2,285 2,325 444 500 533 Expected return on plan assets (50,202 ) (47,784 ) (46,619 ) — — — (472 ) (461 ) (446 ) Amortization of prior service cost (credit) (1,980 ) (1,980 ) (1,980 ) 1,580 42 42 — — — Amortization of net loss (gain) 2,187 — — 42 1,077 911 (335 ) (402 ) (386 ) Net periodic benefit cost $ 65 $ (1,310 ) $ (997 ) $ 4,589 $ 4,317 $ 4,363 $ (294 ) $ (291 ) $ (206 )
Schedule of Amounts Recognized in Other Comprehensive Income (Loss)	The following tables summarize Puget Energy's and PSE's benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, 2018 and 2017 : Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2018 2017 2018 2017 2018 2017 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 59,422 $ (18,896 ) $ 1,122 $ 2,722 $ 488 $ 403 Amortization of net (loss) gain (2,187 ) — (1,580 ) (1,076 ) 335 401 Settlements, mergers, sales, and closures — — (619 ) — — — Prior service cost (credit) — — 1,446 — — — Amortization of prior service (cost) credit 1,980 1,980 (42 ) (42 ) — — Total change in other comprehensive income for year $ 59,215 $ (16,916 ) $ 327 $ 1,604 $ 823 $ 804
Schedule of Assumptions Used	In accounting for pension and other benefit obligations and costs under the plans, the following weighted-average actuarial assumptions were used by the Company: Qualified Pension Benefits SERP Pension Benefits Other Benefits Benefit Obligation Assumptions 2018 2017 2016 2018 2017 2016 2018 2017 2016 Discount rate 4.40 % 4.00 % 4.50 % 4.40 % 4.00 % 4.50 % 4.40 % 4.00 % 4.50 % Rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Medical trend rate — — — — — — 7.60 6.80 8.80 Benefit Cost Assumptions Discount rate 4.40 % 4.50 % 4.65 % 4.40 % 4.50 % 4.65 % 4.40 % 4.50 % 4.65 % Return on plan assets 7.50 7.45 7.75 — — — 7.00 6.75 6.75 Rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Medical trend rate — — — — — — 7.60 9.50 5.30
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates	The assumed medical inflation rate used to determine benefit obligations is 7.60% in 2019 grading down to 3.90% in 2020 . A 1.0% change in the assumed medical inflation rate would have the following effects: 2018 2017 (Dollars in Thousands) 1% Increase 1% Decrease 1% Increase 1% Decrease Effect on post-retirement benefit obligation $ 19 $ (18 ) $ 23 $ (22 ) Effect on service and interest cost components 1 (1 ) 1 (1 )
Schedule of Expected Benefit Payments	The expected total benefits to be paid during the next five years and the aggregate total to be paid for the five years thereafter are as follows: (Dollars in Thousands) 2019 2020 2021 2022 2023 2024-2027 Qualified Pension total benefits $ 43,700 $ 45,100 $ 45,900 $ 47,100 $ 48,500 $ 252,400 SERP Pension total benefits 6,249 4,993 1,887 5,378 3,678 39,400 Other Benefits total with Medicare Part D subsidy 1,112 1,094 1,064 1,038 1,008 4,410 Other Benefits total without Medicare Part D subsidy 892 863 899 872 841 3,704
Schedule of Allocation of Plan Assets	The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, 2018 and 2017 : Recurring Fair Value Measures Recurring Fair Value Measures As of December 31, 2018 As of December 31, 2017 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual Funds $ 103,661 $ — $ 103,661 $ 117,796 $ — $ 117,796 Common Stock 177,949 — 177,949 209,504 — 209,504 Government Securities — — — 18,316 23,782 42,098 Corporate Bonds — — — — 34,588 34,588 Cash and cash equivalents — 702 702 2,684 9,304 11,988 Subtotal $ 281,610 $ 702 282,312 $ 348,300 $ 67,674 415,974 Investments measured at NAV 1 356,586 237,427 Net (payable) receivable 1,345 50,959 Total assets $ 640,243 $ 704,360 _______________ 1 In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that were measured at NAV per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV primarily consist of common/collective trust funds and two partnerships held as of December 31, 2018 . Mesirow Institutional Multi-Strategy Fund Partnership, L.P. utilizes a combination of long and short strategies through investments in investment funds. The major strategy allocations of the investment funds include (1) Investments in debt obligations of public and private entities; typically, in financial duress, and (2) Investments in equity positions on a global basis utilizing fundamental analysis. Grosvenor Institutional Partners Fund, L.P invests substantially all of the fund assets available in the Grosvenor Master Fund, a Cayman Islands exempted company which is sponsored, managed and has the same investment objective as the Partnership fund. In addition to the Master Fund, investments are made primarily in offshore investment funds, investment partnerships, and pooled investment vehicles; collectively referred to as Portfolio Funds, which generally implement "nontraditional" or "alternative" investment strategies. To obtain the desired return needed to fund the pension benefit plans, the Retirement Plan Committee has established investment allocation percentages by asset classes as follows: Allocation Asset Class Minimum Target Maximum Domestic large cap equity 25 % 31 % 40 % Domestic small cap equity — 9 15 Non-U.S. equity 10 25 30 Fixed income 15 25 30 Real estate — — 10 Absolute return 5 10 15 Cash — — 5 The following table sets forth by level, within the fair value hierarchy, the Other Benefits plan assets which consist of insurance benefits for retired employees, at fair value: Recurring Fair Value Measures Recurring Fair Value Measures As of December 31, 2018 As of December 31, 2017 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual fund 1 $ 5,910 $ — $ 5,910 $ 7,089 $ — $ 7,089 Investments measured at NAV 2 50 49 Total assets $ 5,960 $ 7,138 _______________ 1 This is a publicly traded balanced mutual fund. The fund seeks regular income, conservation of principal, and an opportunity for long-term growth of principal and income. The fair value is determined by taking the number of shares owned by the plan, and multiplying by the market price as of December 31, 2018 . 2 In accordance with ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent)", certain investments that were measured at NAV per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the line items presented in the statement of net assets available for benefits. Investments measured at NAV consist of a common/collective trust fund as of December 31, 2018 .
Parent Company [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Schedule of Amounts Recognized in Balance Sheet and Accumulated Other Comprehensive Income	The following tables summarize Puget Energy's and PSE's pension benefit amounts recognized in AOCI for the years ended December 31, 2018 and 2017 : Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2018 2017 2018 2017 2018 2017 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 94,929 $ 37,693 $ 9,612 $ 10,689 $ (2,564 ) $ (3,386 ) Prior service cost (credit) (5,863 ) (7,843 ) 1,607 204 — — Total $ 89,066 $ 29,850 $ 11,219 $ 10,893 $ (2,564 ) $ (3,386 )
Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Schedule of Amounts Recognized in Balance Sheet and Accumulated Other Comprehensive Income	Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2018 2017 2018 2017 2018 2017 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 229,819 $ 185,277 $ 11,450 $ 13,134 $ (3,857 ) $ (4,901 ) Prior service cost (credit) (4,659 ) (6,232 ) 1,609 208 — — Total $ 225,160 $ 179,045 $ 13,059 $ 13,342 $ (3,857 ) $ (4,901 )
Schedule of Net Benefit Costs	Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2018 2017 2016 2018 2017 2016 2018 2017 2016 Components of net periodic benefit cost: Service cost $ 22,757 $ 20,081 $ 18,913 $ 847 $ 913 $ 1,085 $ 69 $ 72 $ 93 Interest cost 27,303 28,373 28,689 2,120 2,285 2,325 444 500 533 Expected return on plan assets (50,240 ) (47,862 ) (46,814 ) — — — (472 ) (461 ) (446 ) Amortization of prior service cost (credit) (1,573 ) (1,573 ) (1,573 ) 44 44 44 — — — Amortization of net loss (gain) 14,917 13,048 15,257 2,069 1,565 1,330 (556 ) (641 ) (632 ) Net periodic benefit cost $ 13,164 $ 12,067 $ 14,472 $ 5,080 $ 4,807 $ 4,784 $ (515 ) $ (530 ) $ (452 )
Schedule of Amounts Recognized in Other Comprehensive Income (Loss)	Puget Sound Energy Qualified Pension Benefit SERP Pension Benefits Other Benefits (Dollars in Thousands) 2018 2017 2018 2017 2018 2017 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 59,460 $ (18,817 ) $ 1,122 $ 2,722 $ 488 $ 452 Amortization of net (loss) gain (14,917 ) (13,048 ) (2,069 ) (1,565 ) 556 641 Settlements, mergers, sales, and closures — — (737 ) — — — Prior service cost (credit) — — 1,446 — — — Amortization of prior service (cost) credit 1,573 1,573 (44 ) (44 ) — — Total change in other comprehensive income for year $ 46,116 $ (30,292 ) $ (282 ) $ 1,113 $ 1,044 $ 1,093

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosures [Line Items]
Schedule of Components of Income Tax Expense (Benefit)	The details of income tax (benefit) expense are as follows: Puget Energy Year Ended December 31, (Dollars in Thousands) 2018 2017 2016 Charged to operating expenses: Current: Federal $ 10,382 $ 1,127 $ — State 263 17 20 Deferred: Federal 19,451 254,420 140,315 State (4 ) (421 ) (131 ) Total income tax expense $ 30,092 $ 255,143 $ 140,204
Schedule of Effective Income Tax Rate Reconciliation	The following reconciliation compares pre-tax book income at the federal statutory rate of 21.0% in 2018 and 35.0% in 2017 and 2016 to the actual income tax expense in the Statements of Income: Puget Energy Year Ended December 31, (Dollars in Thousands) 2018 2017 2016 Income taxes at the statutory rate $ 55,800 $ 148,847 $ 158,586 Increase (decrease): Production tax credit 1 — — (12,925 ) Utility plant differences 2 (25,871 ) — 3,966 Executive compensation 4,439 — — Treasury grant amortization (4,861 ) (9,537 ) (9,788 ) Tax reform — 117,185 — Other–net 585 (1,352 ) 365 Total income tax expense $ 30,092 $ 255,143 $ 140,204 Effective tax rate 11.3 % 60.0 % 30.9 %
Schedule of Deferred Tax Assets and Liabilities	The Company’s net deferred tax liability at December 31, 2018 and 2017 is composed of amounts related to the following types of temporary differences: Puget Energy At December 31, (Dollars in Thousands) 2018 2017 Utility plant and equipment $ 1,998,721 $ 2,034,328 Other deferred tax liabilities 113,051 172,048 Subtotal deferred tax liabilities 2,111,772 2,206,376 Net operating loss carryforward (224,885 ) (212,168 ) Net regulatory liability for income taxes (975,974 ) (1,011,626 ) Production tax credit carryforward (121,616 ) (187,617 ) Net other deferred tax assets — (48,097 ) Subtotal deferred tax assets (1,322,475 ) (1,459,508 ) Total net deferred tax liabilities $ 789,297 $ 746,868
Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Schedule of Components of Income Tax Expense (Benefit)	Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2018 2017 2016 Charged to operating expenses: Current: Federal $ 19,283 $ 1,127 $ — State 438 17 20 Deferred: Federal 30,979 210,842 175,327 State — — — Total income tax expense $ 50,700 $ 211,986 $ 175,347
Schedule of Effective Income Tax Rate Reconciliation	Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2018 2017 2016 Income taxes at the statutory rate $ 77,251 $ 185,430 $ 194,572 Increase (decrease): Production tax credit 1 — — (12,925 ) Utility plant differences 2 (25,871 ) — 3,966 Executive Compensation 4,439 — — Treasury grant amortization (4,861 ) (9,537 ) (9,788 ) Tax reform — 36,328 — Other–net (258 ) (235 ) (478 ) Total income tax expense $ 50,700 $ 211,986 $ 175,347 Effective tax rate 13.8 % 40.0 % 31.5 %
Schedule of Deferred Tax Assets and Liabilities	Puget Sound Energy At December 31, (Dollars in Thousands) 2018 2017 Utility plant and equipment $ 1,998,721 $ 2,034,328 Other, net deferred tax liabilities 25,880 86,933 Subtotal deferred tax liabilities 2,024,601 2,121,261 Net regulatory liability for income taxes (976,582 ) (1,012,260 ) Production tax credit carryforward (121,616 ) (187,617 ) Net other deferred tax assets — (51,911 ) Subtotal deferred tax assets (1,098,198 ) (1,251,788 ) Total net deferred tax liabilities $ 926,403 $ 869,473

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
Other Commitments [Line Items]
Schedule of Long-term Contracts for Purchase of Electric Power	The Company's expenses under these PUD contracts were as follows for the years ended December 31: (Dollars in Thousands) 2018 2017 2016 PUD contract costs $ 80,165 $ 73,827 $ 77,667 As of December 31, 2018 , the Company purchased portions of the power output of the PUDs' projects as set forth in the following table: Company's Current Share of (Dollars in Thousands) Contract Expiration Percent of Output Megawatt Capacity Estimated 2019 Costs 2019 Debt Service Costs Interest included in 2019 Debt Service Costs Debt Outstanding Chelan County PUD: Rock Island Project 2031 25.0 % 156 $ 29,794 $ 10,058 $ 5,053 $ 80,058 Rocky Reach Project 2031 25.0 325 30,378 5,240 2,297 36,289 Douglas County PUD: Wells Project 1 2028 25.3 212 32,662 — — — Grant County PUD: Priest Rapids Development 2052 0.6 6 2,099 1,166 1,166 13,040 Wanapum Development 2052 0.6 7 2,099 1,166 1,166 13,040 Total 706 $ 97,032 $ 17,630 $ 9,682 $ 142,427 _______________ 1 In March 2017, PSE entered a new PPA with Douglas County PUD for Wells Project output that begins upon expiration of the existing contract on August 31, 2018 and continues through September 30, 2028. The Company's expenses under these PUD contracts were as follows for the years ended December 31: (Dollars in Thousands) 2018 2017 2016 PUD contract costs $ 80,165 $ 73,827 $ 77,667
Schedule of Long-term Purchase Commitments	The quantified obligations are based on the FERC and NEB (National Energy Board) currently authorized rates, which are subject to change. Natural Gas Supply and Demand Charge Obligations (Dollars in Thousands) 2019 2020 2021 2022 2023 Thereafter Total Natural gas supply $ 311,601 $ 162,384 $ 157,156 $ 144,008 $ 91,851 $ — $ 867,000 Firm transportation service 165,719 160,053 140,239 139,343 120,486 209,215 935,055 Firm storage service 8,899 7,908 3,108 1,619 504 353 22,391 Short-term natural gas supply contracts 37,589 5,734 931 — — — 44,254 Total $ 523,808 $ 336,079 $ 301,434 $ 284,970 $ 212,841 $ 209,568 $ 1,868,700 The following table summarizes the Company’s estimated obligations for service contracts through the terms of its existing contracts. Service Contract Obligations (Dollars in Thousands) 2019 2020 2021 2022 2023 Thereafter Total Energy production service contracts $ 27,243 $ 27,915 $ 28,650 $ 29,345 $ 30,056 $ 124,646 $ 267,855 Automated meter reading system 45,080 44,193 44,741 45,416 46,106 142,724 368,260 Total $ 72,323 $ 72,108 $ 73,391 $ 74,761 $ 76,162 $ 267,370 $ 636,115 These contracts have varying terms and may include escalation and termination provisions. (Dollars in Thousands) 2019 2020 2021 2022 2023 Thereafter Total Columbia River projects $ 92,905 $ 86,691 $ 76,378 $ 85,807 $ 87,452 $ 631,283 $ 1,060,516 Other utilities 888 — — — — — 888 Non-utility contracts 216,539 255,193 264,262 264,740 269,886 1,221,204 2,491,824 Short-term electric supply contracts 117,040 4,029 — — — — 121,069 Total $ 427,372 $ 345,913 $ 340,640 $ 350,547 $ 357,338 $ 1,852,487 $ 3,674,297

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2018
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	The following tables present the changes in the Company’s (loss) AOCI by component for the years ended December 31, 2018 , 2017 and 2016 , respectively: Puget Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on energy derivative instruments Changes in AOCI, net of tax (Dollars in Thousands) Total Balance at December 31, 2015 $ (27,266 ) $ — $ (27,266 ) Other comprehensive income (loss) before reclassifications (5,528 ) — (5,528 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax (918 ) — (918 ) Net current-period other comprehensive income (loss) (6,446 ) — (6,446 ) Balance at December 31, 2016 $ (33,712 ) $ — $ (33,712 ) Other comprehensive income (loss) before reclassifications 10,251 — 10,251 Amounts reclassified from accumulated other comprehensive income (loss), net of tax (821 ) — (821 ) Net current-period other comprehensive income (loss) 9,430 — 9,430 Balance at December 31, 2017 $ (24,282 ) $ — $ (24,282 ) Other comprehensive income (loss) before reclassifications (48,870 ) — (48,870 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 1,180 — 1,180 Reclassification of stranded taxes to retained earnings due to tax reform (5,230 ) — (5,230 ) Net current-period other comprehensive income (loss) (52,920 ) — (52,920 ) Balance at December 31, 2018 $ (77,202 ) $ — $ (77,202 ) Puget Sound Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on energy derivative instruments Net unrealized gain (loss) on treasury interest rate swaps Changes in AOCI, net of tax (Dollars in Thousands) Total Balance at December 31, 2015 $ (143,877 ) $ — $ (5,673 ) $ (149,550 ) Other comprehensive income (loss) before reclassifications (5,655 ) — — (5,655 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 9,377 — 317 9,694 Net current-period other comprehensive income (loss) 3,722 — 317 4,039 Balance at December 31, 2016 $ (140,155 ) $ — $ (5,356 ) $ (145,511 ) Other comprehensive income (loss) before reclassifications 10,200 — — 10,200 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 8,088 — 317 8,405 Net current-period other comprehensive income (loss) 18,288 — 317 18,605 Balance at December 31, 2017 $ (121,867 ) $ — $ (5,039 ) $ (126,906 ) Other comprehensive income (loss) before reclassifications (48,802 ) — — (48,802 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 11,772 — 385 12,157 Reclassification of stranded taxes to retained earnings due to tax reform (26,233 ) — (1,100 ) (27,333 ) Net current-period other comprehensive income (loss) (63,263 ) — (715 ) (63,978 ) Balance at December 31, 2018 $ (185,130 ) $ — $ (5,754 ) $ (190,884 )
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2018 , 2017 and 2016 , respectively, are as follows: Puget Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented Amount reclassified from accumulated other comprehensive income (loss) 2018 2017 2016 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,937 $ 1,938 $ 1,938 Amortization of net gain (loss) (a) (3,431 ) (675 ) (525 ) Total before tax (1,494 ) 1,263 1,413 Tax (expense) or benefit 314 (442 ) (495 ) Net of Tax (1,180 ) 821 918 Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: Electric derivatives Purchased electricity — — — Tax (expense) or benefit — — — Net of Tax — — — Total reclassification for the period Net of Tax $ (1,180 ) $ 821 $ 918 _______________ (a) These AOCI components are included in the computation of net periodic pension cost, see Note 13, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details. Puget Sound Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented Amount reclassified from accumulated other comprehensive income (loss) 2018 2017 2016 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,529 $ 1,529 $ 1,529 Amortization of net gain (loss) (a) (16,430 ) (13,972 ) (15,955 ) Total before tax (14,901 ) (12,443 ) (14,426 ) Tax (expense) or benefit 3,129 4,355 5,049 Net of tax (11,772 ) (8,088 ) (9,377 ) Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: Electric derivatives Purchased electricity — — — Tax (expense) or benefit — — — Net of Tax — — — Net unrealized gain (loss) on treasury interest rate swaps: Interest rate contracts Interest expense (487 ) (488 ) (488 ) Tax (expense) or benefit 102 171 171 Net of Tax (385 ) (317 ) (317 ) Total reclassification for the period Net of Tax $ (12,157 ) $ (8,405 ) $ (9,694 ) _______________ (a) These AOCI components are included in the computation of net periodic pension cost, see Note 13, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details) $ in Thousands	Nov. 07, 2018	Dec. 19, 2017	Dec. 18, 2017	Dec. 31, 2013	Dec. 31, 2018USD ($)mi²unit	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Jan. 01, 2018USD ($)	Jan. 01, 2017USD ($)	Feb. 06, 2009USD ($)
Accounting Policies
Monetized production tax credits					$ 84,000	$ 2,100
Goodwill					$ 1,656,513	1,656,513				$ 1,700,000
Number of reportable segments | unit					1
Cash and Cash Equivalents
Cash and Cash Equivalents, at Carrying Value					$ 37,521	26,616
Revenue Recognition
Excise taxes collected					239,300	257,100	$ 235,300
Allowance for Doubtful Accounts
Allowance for doubtful accounts					$ 8,408	$ 8,901
Electric Transmission
Accounting Policies
Annual depreciation provision					3.30%	2.80%	2.80%
Gas Transmission Equipment
Accounting Policies
Annual depreciation provision					2.80%	3.40%	3.40%
Common Plant
Accounting Policies
Annual depreciation provision					7.10%	8.30%	9.70%
Subsidiaries [Member]
Accounting Policies
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities	7.49%	7.60%		7.77%
Area of service territory (sqmi) | mi²					6,000
Cash and Cash Equivalents
Cash and Cash Equivalents, at Carrying Value					$ 35,452	$ 25,864
Allowance for Doubtful Accounts
Allowance for doubtful accounts					$ 8,408	$ 8,901
Self Insurance [Abstract]
Public Utilities, Rate Case, Deferred Storm Costs Threshold								$ 10,000	$ 8,000
Puget LNG [Member]
Statements of Cash Flows
Jointly Owned Non-Utility Plant Share					57.00%
Construction in Progress, Gross					$ 165,600
Construction in Progress and O&M Expenses					$ 130,800
Tacoma LNG [Member]
Statements of Cash Flows
Jointly Owned Non-Utility Plant Share					43.00%
Construction in Progress, Gross					$ 2,000
Decoupling Mechanism [Member] | Electricity, US Regulated [Member] | Subsidiaries [Member] | Maximum
Revenue Recognition
Public Utilities, Approved Rate Increase (Decrease), Percentage		3.00%
Decoupling Mechanism [Member] | Natural Gas, US Regulated [Member] | Subsidiaries [Member] | Maximum
Revenue Recognition
Public Utilities, Approved Rate Increase (Decrease), Percentage		5.00%	3.00%

Summary of Significant Accoun_4

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

New Accounting Pronouncements R

New Accounting Pronouncements Revenue Recognition (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cash and Cash Equivalents, at Carrying Value	$ 37,521	$ 26,616
Restricted Cash and Cash Equivalents, Current	18,041	10,145
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	5,200
Other Comprehensive Income (Loss) Reclassification of Stranded Taxes to RE for Pension Plans	5,230
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	55,562	36,761	$ 41,296	$ 50,443
Subsidiaries [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cash and Cash Equivalents, at Carrying Value	35,452	25,864
Restricted Cash and Cash Equivalents, Current	18,041	10,145
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	27,332
Other Comprehensive Income (Loss) Reclassification of Stranded Taxes to RE for Pension Plans	26,200
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	53,493	$ 36,009	$ 40,899	$ 49,805
Other Comprehensive Income (Loss) Reclassification of Stranded Taxes to RE for Interest Rate Swaps	$ 1,100

Revenue (Details)

Revenue (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenue from Contract with Customer, Including Assessed Tax									$ 3,222,093
Regulated Operating Revenue, Other									39,829	$ 41,854	$ 35,299
Revenues									3,346,496	3,460,276	3,164,301
Natural Gas, US Regulated [Member]
Revenue from Contract with Customer, Including Assessed Tax									849,898
Other Revenue From Contracts with Customers [Member]
Revenue from Contract with Customer, Including Assessed Tax									234,187
Decoupling over-collection [Domain]
Regulated Operating Revenue, Other									(22,852)
Other Non-606 Revenue [Member]
Regulated Operating Revenue, Other									147,255
Electricity, US Regulated [Member]
Revenue from Contract with Customer, Including Assessed Tax									2,138,008
Subsidiaries [Member]
Regulated Operating Revenue, Other									39,829	41,854	35,616
Revenues	$ 985,172	$ 651,464	$ 671,852	$ 1,038,008	$ 1,002,900	$ 660,377	$ 719,767	$ 1,077,232	$ 3,346,496	$ 3,460,276	$ 3,164,618

Regulation and Rates Net regula

Regulation and Rates Net regulatory assets and liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Deferred income tax charge
Regulatory Assets [Line Items]
Regulatory Liabilities	$ 608	$ 634
Regulatory liabilities related to power contracts
Regulatory Assets [Line Items]
Regulatory Liabilities	162,711	174,918
Various other regulatory liabilities
Regulatory Assets [Line Items]
Regulatory Liabilities	1,323	1,314
Liabilities, Total
Regulatory Assets [Line Items]
Regulatory Liabilities	1,885,888	1,934,182
Net Regulatory Assets
Regulatory Assets [Line Items]
Net Regulatory Assets	(1,080,987)
Various other regulatory assets
Regulatory Assets [Line Items]
Regulatory Assets	0	(8)
Requlatory Assets Related to Power Contracts
Regulatory Assets [Line Items]
Regulatory Assets	16,693	19,454
Assets, Total
Regulatory Assets [Line Items]
Regulatory Assets	804,901	972,562
Net Regulatory Assets
Regulatory Assets [Line Items]
Net Regulatory Assets		(961,620)
Subsidiaries [Member] | Deferred income tax charge
Regulatory Assets [Line Items]
Regulatory Liabilities	976,582	1,012,260
Subsidiaries [Member] | Cost of removal
Regulatory Assets [Line Items]
Regulatory Liabilities	$ 424,727	389,579
Subsidiaries [Member] | Treasury grants
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period	20 years
Regulatory Liabilities	$ 168,884	205,775
Subsidiaries [Member] | Production tax credits [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	93,616	93,616
Subsidiaries [Member] | Accumulated Provision for Rate Refund [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	34,579	0
Subsidiaries [Member] | Decoupling rate of return sharing [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	0	18,400
Subsidiaries [Member] | Deferral and interest decoupling revenue [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	$ 13,758	7,896
Subsidiaries [Member] | Deferred decoupling revenue, net [Member]
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period	2 years
Regulatory Liabilities	$ 13,758	26,296
Subsidiaries [Member] | PGA payable
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period	1 year
Regulatory Liabilities	$ 0	16,051
Subsidiaries [Member] | Summit purchase option buy-out
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period	1 year 10 months
Regulatory Liabilities	$ 2,888	4,463
Subsidiaries [Member] | Various other regulatory liabilities
Regulatory Assets [Line Items]
Regulatory Liabilities	7,428	10,544
Subsidiaries [Member] | Liabilities, Total
Regulatory Assets [Line Items]
Regulatory Liabilities	1,722,462	1,758,584
Subsidiaries [Member] | Net Regulatory Assets
Regulatory Assets [Line Items]
Net Regulatory Assets	(934,254)
Subsidiaries [Member] | Storm Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	118,331	128,508
Subsidiaries [Member] | Colstrip Regulatory Asset [Domain]
Regulatory Assets [Line Items]
Regulatory Assets	37,674	127,627
Subsidiaries [Member] | Deferred decoupling revenue, net [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 65,779	98,769
Net Regulatory Assets, Remaining Amortization Period	2 years
Subsidiaries [Member] | Chelan PUD contract initiation
Regulatory Assets [Line Items]
Regulatory Assets	$ 90,964	98,052
Net Regulatory Assets, Remaining Amortization Period	12 years 10 months
Subsidiaries [Member] | Environmental remediation
Regulatory Assets [Line Items]
Regulatory Assets	$ 76,345	81,550
Subsidiaries [Member] | Lower Snake River
Regulatory Assets [Line Items]
Regulatory Assets	$ 67,021	70,975
Net Regulatory Assets, Remaining Amortization Period	18 years 5 months
Subsidiaries [Member] | Baker Dam Licensing Operating Maintenance Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 55,607	54,817
Subsidiaries [Member] | Deferred Washington Commission AFUDC
Regulatory Assets [Line Items]
Regulatory Assets	$ 52,029	50,301
Net Regulatory Assets, Remaining Amortization Period	10 years
Subsidiaries [Member] | Unamortized loss on reacquired debt
Regulatory Assets [Line Items]
Regulatory Assets	$ 42,378	39,674
Subsidiaries [Member] | Property tax tracker
Regulatory Assets [Line Items]
Regulatory Assets	$ 45,621	36,517
Net Regulatory Assets, Remaining Amortization Period	2 years
Subsidiaries [Member] | Energy Conservation Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 30,701	35,538
Subsidiaries [Member] | PGA deferral of unrealized losses on derivative instruments
Regulatory Assets [Line Items]
Regulatory Assets	14,739	26,030
Subsidiaries [Member] | White River relicensing and other costs
Regulatory Assets [Line Items]
Regulatory Assets	$ 12,966	19,502
Net Regulatory Assets, Remaining Amortization Period	3 years
Subsidiaries [Member] | Generation plant major maintenance [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 15,027	17,216
Subsidiaries [Member] | Mint Farm ownership and operating costs
Regulatory Assets [Line Items]
Regulatory Assets	$ 12,319	14,319
Net Regulatory Assets, Remaining Amortization Period	6 years 4 months
Subsidiaries [Member] | Colstrip major maintenance [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 6,841	8,723
Net Regulatory Assets, Remaining Amortization Period	6 months
Subsidiaries [Member] | Snoqualmie Licensing Operating Maintenance Costs
Regulatory Assets [Line Items]
Regulatory Assets	$ 7,407	7,341
Subsidiaries [Member] | Ferndale
Regulatory Assets [Line Items]
Regulatory Assets	$ 3,316	7,295
Net Regulatory Assets, Remaining Amortization Period	10 months
Subsidiaries [Member] | Colstrip common property
Regulatory Assets [Line Items]
Regulatory Assets	$ 3,903	4,618
Net Regulatory Assets, Remaining Amortization Period	6 years 5 months
Subsidiaries [Member] | PCA Mechanism [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 4,735	4,576
Subsidiaries [Member] | Electron Unrecovered Loss
Regulatory Assets [Line Items]
Regulatory Assets	$ 0	3,786
Net Regulatory Assets, Remaining Amortization Period	1 year
Subsidiaries [Member] | PGA receivable [Domain]
Regulatory Assets [Line Items]
Regulatory Assets	$ 9,922	0
Net Regulatory Assets, Remaining Amortization Period	1 year
Subsidiaries [Member] | Various other regulatory assets
Regulatory Assets [Line Items]
Regulatory Assets	$ 14,583	17,382
Subsidiaries [Member] | Assets, Total
Regulatory Assets [Line Items]
Regulatory Assets	788,208	953,116
Subsidiaries [Member] | Net Regulatory Assets
Regulatory Assets [Line Items]
Net Regulatory Assets		(805,468)
Colstrip Regulatory Asset [Domain]
Regulatory Assets [Line Items]
Regulatory Assets	$ 130,700	$ 127,600

Regulation and Rates Rate Adjus

Regulation and Rates Rate Adjustments (Details) - USD ($)	Mar. 01, 2019	Nov. 07, 2018	May 01, 2018	Mar. 01, 2018	Dec. 19, 2017	Dec. 18, 2017	Dec. 31, 2013	Apr. 30, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Regulation and Rates [Line Items]
Income tax (benefit) expense									$ 30,092,000	$ 255,143,000	$ 140,204,000
Decoupling Mechanism [Member]
Regulation and Rates [Line Items]
Deferred Revenue, Revenue Recognized									20,800,000
Subsidiaries [Member]
Regulation and Rates [Line Items]
Income tax (benefit) expense			$ 34,600,000						50,700,000	$ 211,986,000	$ 175,347,000
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities		7.49%			7.60%		7.77%
Subsidiaries [Member] | Expedited Rate Filing (ERF) [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 18,900,000
Public Utilities, Requested Rate Increase (Decrease), Percentage		0.90%
Subsidiaries [Member] | Expedited Rate Filing (ERF) [Member] | Natural Gas, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount				$ 25,900,000
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 21,700,000		$ 6,100,000
Public Utilities, Requested Rate Increase (Decrease), Percentage		2.70%
Subsidiaries [Member] | Decoupling Mechanism [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Contract with Customer, Liability, Revenue Recognized									$ 800,000
Subsidiaries [Member] | General Rate Case [Member]
Regulation and Rates [Line Items]
Regulated Utility, After-tax Allowed Rate of Return on Net Regulatory Assets and Liabilities					6.55%
Subsidiaries [Member] | General Rate Case [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage					0.90%
Public Utilities, Approved Rate Increase (Decrease), Amount					$ 20,200,000
Subsidiaries [Member] | General Rate Case [Member] | Natural Gas, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage					(3.80%)
Public Utilities, Approved Rate Increase (Decrease), Amount					$ (35,500,000)
Maximum | Subsidiaries [Member] | Decoupling Mechanism [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage					3.00%
Maximum | Subsidiaries [Member] | Decoupling Mechanism [Member] | Natural Gas, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage					5.00%	3.00%
Scenario, Forecast [Member] | Subsidiaries [Member] | Expedited Rate Filing (ERF) [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 0
Scenario, Forecast [Member] | Subsidiaries [Member] | Expedited Rate Filing (ERF) [Member] | Natural Gas, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 21,500,000
Scenario, Forecast [Member] | Subsidiaries [Member] | Tax Cuts and Jobs Act [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage								(3.40%)
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount								$ (72,900,000)
Scenario, Forecast [Member] | Subsidiaries [Member] | Tax Cuts and Jobs Act [Member] | Natural Gas, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage								(2.70%)
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount								$ (23,600,000)

Regulation and Rates (Details)

Regulation and Rates (Details)	Nov. 07, 2018	Dec. 19, 2017USD ($)	Dec. 18, 2017	Jan. 13, 2017	Dec. 31, 2013	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Jan. 01, 2018USD ($)	Jan. 01, 2017USD ($)
Regulation and Rates [Line Items]
Accrual for Environmental Loss Contingencies						$ 32,200,000
Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Environmental Remediation Expense						8,800,000
Environmental Expense and Liabilities						14,100,000	$ 17,600,000
Natural Gas, US Regulated [Member]
Regulation and Rates [Line Items]
Environmental Remediation Expense						42,700,000
Environmental Expense and Liabilities						62,200,000	63,900,000
Subsidiaries [Member]
Regulation and Rates [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities	7.49%	7.60%			7.77%
Regulatory Liabilities Reclassified from Accumulated Depreciation						424,700,000	389,600,000
Public Utilities, Rate Case, Deferred Storm Costs Threshold								$ 10,000,000	$ 8,000,000
Public Utilities, Rate Case, Deferred Storm Qualifying Costs								$ 500,000
Storm Damage Costs Incurred During Period						25,400,000	30,400,000
Storm Damage Costs Deferred During Period						$ 15,100,000	$ 21,600,000
General Rate Case [Member] | Subsidiaries [Member]
Regulation and Rates [Line Items]
Regulated Utility, After-tax Allowed Rate of Return on Net Regulatory Assets and Liabilities		6.55%
Public Utilities, Approved Equity Capital Structure, Percentage		48.50%
Public Utilities, Approved Return on Equity, Percentage		9.50%
Number of new mechanisms				2
General Rate Case [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 20,200,000
Public Utilities, Approved Rate Increase (Decrease), Percentage		0.90%
General Rate Case [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount		$ (35,500,000)
Public Utilities, Approved Rate Increase (Decrease), Percentage		(3.80%)
Maximum | Decoupling Mechanism [Member] | Subsidiaries [Member] | Electricity, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage		3.00%
Maximum | Decoupling Mechanism [Member] | Subsidiaries [Member] | Natural Gas, US Regulated [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage		5.00%	3.00%
Regulatory liabilities related to power contracts
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Min						1 year
Net Regulatory Assets, Remaining Amortization Period, Max						35 years
Treasury grants | Subsidiaries [Member]
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period						20 years
Generation plant major maintenance [Member] | Subsidiaries [Member]
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Min						4 years
Net Regulatory Assets, Remaining Amortization Period, Max						10 years
Chelan PUD contract initiation | Subsidiaries [Member]
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period						12 years 10 months
Ferndale | Subsidiaries [Member]
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period						10 months
Deferred decoupling revenue, net [Member] | Subsidiaries [Member]
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period						2 years
Requlatory Assets Related to Power Contracts
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Min						1 year
Net Regulatory Assets, Remaining Amortization Period, Max						20 years
Lower Snake River | Subsidiaries [Member]
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period						18 years 5 months
Storm Costs [Member] | Subsidiaries [Member]
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Min						4 years
Net Regulatory Assets, Remaining Amortization Period, Max						6 years
Unamortized loss on reacquired debt | Subsidiaries [Member]
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Min						1 year
Net Regulatory Assets, Remaining Amortization Period, Max						28 years

Dividend Payment Restrictions (

Dividend Payment Restrictions (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Parent [Line Items]
Retained Earnings, Unappropriated	$ 783
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio, Threshold For Dividend Payment	2
EBITDA Interest Expense Ratio	3.7
EBITDA to Interest Expense Denominator	1
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End	1
Subsidiaries [Member]
Parent [Line Items]
Dividends, Common Equity Ratio, Threshold For Dividend Payment	44.00%
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio, Threshold For Dividend Payment	3
Dividends, Common Equity Ratio at Period End	47.60%
EBITDA Interest Expense Ratio	5.6
EBITDA to Interest Expense Denominator	1
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End	1

Utility Plant (Details)

Utility Plant (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Public Utility, Property, Plant and Equipment
Accumulated amortization of capital leases	$ 1,300	$ 700
Utility Plant
Distribution plant	6,122,739	5,670,351
Production plant	3,099,805	3,068,135
Transmission plant	1,442,854	1,361,495
General plant	682,976	586,226
Intangible plant (including capitalized software)	662,328	447,568
Plant acquisition adjustment	242,826	242,826
Underground storage	35,404	31,815
Liquefied natural gas storage	12,628	12,628
Plant held for future use	39,384	53,428
Recoverable cushion gas	8,655	8,655
Public Utilities, Property, Plant and Equipment, Other Property, Plant and Equipment	239,857	275,014
Capital leases, net of accumulated amortization	1,315	1,129
Less: Accumulated depreciation and amortization	(2,832,321)	(2,428,524)
Subtotal	9,758,450	9,330,746
Construction work in progress	550,466	495,937
Net utility plant	$ 10,308,916	9,826,683
Minimum
Public Utility, Property, Plant and Equipment
Distribution plant, Estimated Useful Life	20 years
Production plant, Estimated Useful Life	12 years
Transmission plant, Estimated Useful Life	43 years
General plant, Estimated Useful Life	5 years
Underground storage, Estimated Useful Life	25 years
Liquefied natural gas storage, Estimated Useful Life	25 years
Public Utilities, Property, Plant and Equipment, Plant Not Classified, Estimated Useful Life	1 year
Capital leases, net of accumulated amortization, Estimated Useful Life	4 years
Maximum
Public Utility, Property, Plant and Equipment
Distribution plant, Estimated Useful Life	65 years
Production plant, Estimated Useful Life	90 years
Transmission plant, Estimated Useful Life	75 years
General plant, Estimated Useful Life	75 years
Underground storage, Estimated Useful Life	60 years
Liquefied natural gas storage, Estimated Useful Life	60 years
Public Utilities, Property, Plant and Equipment, Plant Not Classified, Estimated Useful Life	125 years
Capital leases, net of accumulated amortization, Estimated Useful Life	6 years
Subsidiaries [Member]
Utility Plant
Distribution plant	$ 7,722,024	7,289,998
Production plant	3,974,250	3,954,057
Transmission plant	1,550,950	1,471,337
General plant	718,105	628,179
Intangible plant (including capitalized software)	652,942	438,185
Plant acquisition adjustment	282,792	282,792
Underground storage	48,874	45,288
Liquefied natural gas storage	14,498	14,498
Plant held for future use	39,536	53,580
Recoverable cushion gas	8,655	8,655
Public Utilities, Property, Plant and Equipment, Other Property, Plant and Equipment	239,857	275,014
Capital leases, net of accumulated amortization	1,315	1,129
Less: Accumulated depreciation and amortization	(5,495,348)	(5,131,966)
Subtotal	9,758,450	9,330,746
Construction work in progress	550,466	495,937
Net utility plant	$ 10,308,916	$ 9,826,683

Utility Plant - Jointly Owned U

Utility Plant - Jointly Owned Utility Plant (Details) $ in Thousands	Dec. 31, 2018USD ($)
Colstrip Units 1 & 2
Jointly Owned Utility Plant Interests
Plant in Service at Cost	$ 239,341
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Accumulated Depreciation	(62,420)
Colstrip Units 3 & 4
Jointly Owned Utility Plant Interests
Plant in Service at Cost	318,736
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Accumulated Depreciation	(98,641)
Colstrip Units 1 – 4 Common Facilities
Jointly Owned Utility Plant Interests
Plant in Service at Cost	83
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Accumulated Depreciation	(38)
Frederickson 1
Jointly Owned Utility Plant Interests
Plant in Service at Cost	61,790
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Accumulated Depreciation	(8,500)
Jackson Prairie [Member]
Jointly Owned Utility Plant Interests
Plant in Service at Cost	33,831
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	404
Accumulated Depreciation	(7,355)
Tacoma LNG [Member]
Jointly Owned Utility Plant Interests
Plant in Service at Cost	0
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	296,324
Accumulated Depreciation	$ 0
Subsidiaries [Member] | Colstrip Units 1 & 2
Jointly Owned Utility Plant Interests
Company’s Ownership Share	50.00%
Plant in Service at Cost	$ 368,242
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Accumulated Depreciation	$ (191,323)
Subsidiaries [Member] | Colstrip Units 3 & 4
Jointly Owned Utility Plant Interests
Company’s Ownership Share	25.00%
Plant in Service at Cost	$ 578,008
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Accumulated Depreciation	(357,914)
Subsidiaries [Member] | Colstrip Units 1 – 4 Common Facilities
Jointly Owned Utility Plant Interests
Plant in Service at Cost	252
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Accumulated Depreciation	$ (206)
Subsidiaries [Member] | Frederickson 1
Jointly Owned Utility Plant Interests
Company’s Ownership Share	49.85%
Plant in Service at Cost	$ 67,858
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Accumulated Depreciation	$ (14,567)
Subsidiaries [Member] | Jackson Prairie [Member]
Jointly Owned Utility Plant Interests
Company’s Ownership Share	33.34%
Plant in Service at Cost	$ 47,975
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	404
Accumulated Depreciation	(21,499)
Subsidiaries [Member] | Tacoma LNG [Member]
Jointly Owned Utility Plant Interests
Plant in Service at Cost	0
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	130,756
Accumulated Depreciation	0
Other Plant in Service [Member] | Colstrip Units 1 & 2
Jointly Owned Utility Plant Interests
Plant in Service at Cost	$ 130,700

Utility Plant - Asset Retiremen

Utility Plant - Asset Retirement Obligation (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Sep. 06, 2016
number of agreements			2
Subsidiaries [Member]
Decommissioning Liability, Noncurrent	$ 4,800	$ 3,800
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of period	191,176	200,345
Costs Incurred, Asset Retirement Obligation Incurred	501	2,881
Asset Retirement Obligation, Liabilities Incurred	(4,750)	(3,841)
Asset Retirement Obligation, Revision of Estimate	(10,512)	(13,748)
Asset Retirement Obligation, Accretion Expense	5,788	5,539
Asset retirement obligation at end of period	182,203	191,176
Colstrip Units 1 and 2 [Member] | Subsidiaries [Member]
Decommissioning Liability, Noncurrent	5,500	11,000
Colstrip Units 3 and 4 [Member] | Subsidiaries [Member]
Decommissioning Liability, Noncurrent	12,700	1,800
Tacoma LNG [Member]
Decommissioning Liability, Noncurrent		2,700
Tacoma LNG [Member] | Puget LNG [Member]
Decommissioning Liability, Noncurrent	$ 1,700	$ 2,200

Long-Term Debt (Schedule of Lon

Long-Term Debt (Schedule of Long-Term Debt Instruments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Oct. 01, 2018	Jun. 04, 2018	Mar. 28, 2018	Mar. 05, 2018	Jun. 15, 2017
Debt Instrument [Line Items]
Current borrowing capacity of line of credit	$ 200,000
Proceeds from long-term debt and bonds issued	804,050	$ 90,120	$ 12,481
Total PSE long-term debt	5,888,172
Long Term Debt, Reconciliation, Fair Value Adjustment	(182,372)	(190,895)
Long-term Debt, term loan	150,000	0		$ 150,000
Long-term Line of Credit, Noncurrent	11,900	102,600
Unamortized discount on senior notes	(1,897)	(3,687)
Net PSE long-term debt	$ 5,672,491	5,457,929
Senior Secured Note | 6.500% Senior Secured Note Due 2020
Debt Instrument [Line Items]
Stated interest rate percent	6.50%
Total PSE long-term debt	$ 450,000	450,000
Senior Secured Note | 6.000% Senior Secured Note Due 2021
Debt Instrument [Line Items]
Stated interest rate percent	6.00%
Total PSE long-term debt	$ 500,000	500,000
Senior Secured Note | 5.625% Senior Secured Note Due 2022
Debt Instrument [Line Items]
Stated interest rate percent	5.625%
Total PSE long-term debt	$ 450,000	450,000
Senior Secured Note | 3.650% Senior Secured Note Due 2025 [Member]
Debt Instrument [Line Items]
Stated interest rate percent	3.65%
Total PSE long-term debt	$ 400,000	400,000
Subsidiaries [Member]
Debt Instrument [Line Items]
Proceeds from long-term debt and bonds issued	594,750	0	$ 0
Total PSE long-term debt	3,926,272
Unamortized discount on senior notes	(31,412)	(26,361)
Net PSE long-term debt	$ 3,894,860	3,749,911
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 5.500% Secured Promissory Note Due 2017
Debt Instrument [Line Items]
Stated interest rate percent	5.50%
Total PSE long-term debt	$ 2,412	2,412
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 7.150% Series Due 2025
Debt Instrument [Line Items]
Stated interest rate percent	7.15%
Total PSE long-term debt	$ 15,000	15,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 7.200% Series Due 2025
Debt Instrument [Line Items]
Stated interest rate percent	7.20%
Total PSE long-term debt	$ 2,000	2,000
Subsidiaries [Member] | Pollution Control Bonds | 3.900% Series Due 2031
Debt Instrument [Line Items]
Stated interest rate percent	3.90%
Total PSE long-term debt	$ 138,460	138,460
Subsidiaries [Member] | Pollution Control Bonds | 4.000% Series Due 2031
Debt Instrument [Line Items]
Stated interest rate percent	4.00%
Total PSE long-term debt	$ 23,400	23,400
Subsidiaries [Member] | Junior Subordinated Debt | 6.974% Series Due 2067
Debt Instrument [Line Items]
Stated interest rate percent						6.974%
Total PSE long-term debt	$ 0						$ 250,000
Subsidiaries [Member] | Senior Secured Note | 6.740% Series Due 2018
Debt Instrument [Line Items]
Stated interest rate percent	6.74%							6.74%
Total PSE long-term debt	$ 0	200,000			$ 200,000			$ 200,000
Subsidiaries [Member] | Senior Secured Note | 7.020% Series Due 2027
Debt Instrument [Line Items]
Stated interest rate percent	7.02%
Total PSE long-term debt	$ 300,000	300,000
Subsidiaries [Member] | Senior Secured Note | 7.000% Series Due 2029
Debt Instrument [Line Items]
Stated interest rate percent	7.00%
Total PSE long-term debt	$ 100,000	100,000
Subsidiaries [Member] | Senior Secured Note | 5.483% Series Due 2035
Debt Instrument [Line Items]
Stated interest rate percent	5.483%
Total PSE long-term debt	$ 250,000	250,000
Subsidiaries [Member] | Senior Secured Note | 6.724% Series Due 2036
Debt Instrument [Line Items]
Stated interest rate percent	6.724%
Total PSE long-term debt	$ 250,000	250,000
Subsidiaries [Member] | Senior Secured Note | 6.274% Series Due 2037
Debt Instrument [Line Items]
Stated interest rate percent							6.274%
Total PSE long-term debt	$ 300,000	300,000
Subsidiaries [Member] | Senior Secured Note | 5.757% Series Due 2039
Debt Instrument [Line Items]
Stated interest rate percent	5.757%
Total PSE long-term debt	$ 350,000	350,000
Subsidiaries [Member] | Senior Secured Note | 5.795% Series Due 2040
Debt Instrument [Line Items]
Stated interest rate percent	5.795%
Total PSE long-term debt	$ 325,000	325,000
Subsidiaries [Member] | Senior Secured Note | 5.764% Series Due 2040
Debt Instrument [Line Items]
Stated interest rate percent	5.764%
Total PSE long-term debt	$ 250,000	250,000
Subsidiaries [Member] | Senior Secured Note | 4.434% Series Due 2041
Debt Instrument [Line Items]
Stated interest rate percent	4.434%
Total PSE long-term debt	$ 250,000	250,000
Subsidiaries [Member] | Senior Secured Note | 5.638% Series Due 2041
Debt Instrument [Line Items]
Stated interest rate percent	5.638%
Total PSE long-term debt	$ 300,000	300,000
Subsidiaries [Member] | Senior Secured Note | 4.300% Series Due 2045
Debt Instrument [Line Items]
Stated interest rate percent	4.30%
Total PSE long-term debt	$ 425,000	425,000
Subsidiaries [Member] | Senior Secured Note | 4.223% Series Due 2048 [Members] [Domain]
Debt Instrument [Line Items]
Stated interest rate percent	4.223%
Total PSE long-term debt	$ 600,000	0			$ 600,000
Subsidiaries [Member] | Senior Secured Note | 4.700% Series Due 2051
Debt Instrument [Line Items]
Stated interest rate percent	4.70%
Total PSE long-term debt	$ 45,000	$ 45,000

Long-Term Debt (Narrative) (Det

Long-Term Debt (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Oct. 01, 2018	Jun. 04, 2018	Mar. 28, 2018	Mar. 05, 2018	Dec. 31, 2017	Jun. 15, 2017
Debt Instrument [Line Items]
Long-term debt	$ 5,888,172
Long-term Debt, term loan	150,000	$ 150,000				$ 0
Long-term Line of Credit, Noncurrent	11,900					102,600
Current borrowing capacity of line of credit	200,000
Senior Secured Note | 3.650% Senior Secured Note Due 2025 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 400,000					400,000
Stated interest rate percent	3.65%
Term Loan Expansion [Member]
Debt Instrument [Line Items]
Long-term Line of Credit, Noncurrent	$ 100,000
Subsidiaries [Member]
Debt Instrument [Line Items]
Long-term debt	3,926,272
Subsidiaries [Member] | Senior Secured Note | 6.740% Series Due 2018
Debt Instrument [Line Items]
Long-term debt	$ 0		$ 200,000			200,000	$ 200,000
Stated interest rate percent	6.74%						6.74%
Commercial Paper			348,000
Subsidiaries [Member] | Senior Secured Note | 4.223% Series Due 2048 [Members] [Domain]
Debt Instrument [Line Items]
Long-term debt	$ 600,000		$ 600,000			0
Stated interest rate percent	4.223%
Subsidiaries [Member] | Senior Secured Note | 4.300% Series Due 2045
Debt Instrument [Line Items]
Long-term debt	$ 425,000					$ 425,000
Stated interest rate percent	4.30%
Subsidiaries [Member] | Junior Subordinated Debt | consent fees [Domain]
Debt Instrument [Line Items]
Long-term debt					$ 2,600
Subsidiaries [Member] | Junior Subordinated Debt | remaining principal paid [Domain] [Domain] [Domain]
Debt Instrument [Line Items]
Long-term debt				$ 56,600
Subsidiaries [Member] | Junior Subordinated Debt | 6.974% Series Due 2067
Debt Instrument [Line Items]
Long-term debt	$ 0				250,000
Stated interest rate percent				6.974%
Subsidiaries [Member] | Junior Subordinated Debt | debt premium [Domain]
Debt Instrument [Line Items]
Long-term debt					1
Subsidiaries [Member] | Junior Subordinated Debt | debt face value [Domain] [Domain]
Debt Instrument [Line Items]
Long-term debt					1
Subsidiaries [Member] | Junior Subordinated Debt | debt discount [Domain]
Debt Instrument [Line Items]
Long-term debt					1
Subsidiaries [Member] | Junior Subordinated Debt | principal paid [Domain]
Debt Instrument [Line Items]
Long-term debt					193,400
Subsidiaries [Member] | Junior Subordinated Debt | principal paid [Domain]
Debt Instrument [Line Items]
Long-term debt					$ 194,900

Long-Term Debt (Schedule of Mat

Long-Term Debt (Schedule of Maturities of Long-Term Debt) (Details) $ in Thousands	Dec. 31, 2018USD ($)
Maturities of Long-term Debt [Abstract]
2,016	$ 0
2,017	452,412
2,018	650,000
2,019	461,900
2,020	0
Thereafter	4,323,860
Total long-term debt	5,888,172
Subsidiaries [Member]
Maturities of Long-term Debt [Abstract]
2,016	0
2,017	2,412
2,018	0
2,019	0
2,020	0
Thereafter	3,923,860
Total long-term debt	3,926,272
Parent Company [Member]
Maturities of Long-term Debt [Abstract]
2,016	0
2,017	450,000
2,018	650,000
2,019	461,900
2,020	0
Thereafter	400,000
Total long-term debt	$ 1,961,900

Liquidity Facilities and Othe_2

Liquidity Facilities and Other Financing Arrangements (Details) - USD ($)	Feb. 10, 2012	Dec. 31, 2018	Dec. 31, 2017	Oct. 10, 2017	Dec. 31, 2015
Short-term Debt [Line Items]
Short-term debt		$ 379,297,000	$ 329,463,000
Line of Credit Facility, Maximum Borrowing Capacity		1,300,000,000
Current borrowing capacity of line of credit		200,000,000
Long-term Line of Credit, Noncurrent		11,900,000	102,600,000
Senior secured credit facility
Short-term Debt [Line Items]
Short-term debt		0			$ 0
Subsidiaries [Member]
Short-term Debt [Line Items]
Short-term debt		$ 379,297,000	$ 329,463,000		$ 329,500,000
Weighted-average interest rate on short-term debt (percent)		3.40%	3.50%
Line of Credit Facility, Current Same-Day Borrowing Capacity		$ 75,000,000
Line of Credit Facility, Maximum Borrowing Capacity		$ 1,400,000,000
Maximum capitalization percentage		65.00%
Derivative, Basis Spread on Variable Rate		1.25%
Line of Credit, Unused Capacity, Commitment Fee Percentage		0.175%
Subsidiaries [Member] | Working Capital Needs
Short-term Debt [Line Items]
Current borrowing capacity of line of credit				$ 800,000,000
Subsidiaries [Member] | Energy Hedging Activities [Member]
Short-term Debt [Line Items]
Outstanding amount for line of credit		$ 1,000,000
Subsidiaries [Member] | Letter of Credit | Working Capital Needs
Short-term Debt [Line Items]
Outstanding amount for line of credit		379,300,000
Current borrowing capacity of line of credit		3,000,000
Subsidiaries [Member] | Senior secured credit facility | Promissory Note with Puget Energy
Short-term Debt [Line Items]
Current borrowing capacity of line of credit		$ 30,000,000
Basis spread on variable rate (percent)		0.25%
Debt instrument variable rate basis		one-month LIBOR
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Current borrowing capacity of line of credit				800,000,000
Line of Credit Facility, Fair Value of Amount Outstanding				$ 11,900,000
Basis spread on variable rate (percent)		1.75%
Line of Credit Facility, Commitment Fee Percentage	0.275%

Leases (Schedule of Operating L

Leases (Schedule of Operating Lease Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Subsidiaries [Member]
Operating Leases, Rent Expense, Net [Abstract]
Operating lease expense net of sublease receipts	$ 34,093	$ 35,198	$ 31,786

Leases (Schedule of Future Mini

Leases (Schedule of Future Minimum Lease Payments for Non-cancellable Leases) (Details) - Subsidiaries [Member] $ in Thousands	Dec. 31, 2018USD ($)
Operating
2,014	$ 20,635
2,015	20,704
2,016	20,630
2,017	20,202
2,018	19,223
Thereafter	132,889
Total minimum lease payments	234,283
Capital
2,014	495
2,015	446
2,016	311
2,017	82
2,018	0
Thereafter	0
Total minimum lease payments	$ 1,334

Accounting for Derivative Ins_3

Accounting for Derivative Instruments and Hedging Activities (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Electric Portfolio
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	$ 0	$ 2,639
Credit Rating | Natural Gas Portfolio
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	$ 1,000
External Credit Rating, Investment Grade [Member] | Electric Portfolio
Derivative [Line Items]
Percentage of derivatives with credit risk exposure	95.80%
External Credit Rating, Non Investment Grade [Member] | Electric Portfolio
Derivative [Line Items]
Percentage of derivatives with credit risk exposure	4.20%
Credit Rating
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	$ 6,400
Credit Rating | Electric Portfolio
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	$ 0	$ 0

Accounting for Derivative Ins_4

Accounting for Derivative Instruments and Hedging Activities (Schedule of Derivative Assets and Liabilities) (Details) $ in Thousands, MWh in Millions, MMBTU in Millions	Dec. 31, 2018USD ($)MWhMMBTU	Dec. 31, 2017USD ($)MWhMMBTU
Derivative [Line Items]
Assets, Current	$ 46,507	$ 22,247
Assets, Long-term	2,512	2,158
Liabilities, Current	46,661	64,859
Liabilities, Long-term	11,095	21,235
Subsidiaries [Member]
Derivative [Line Items]
Assets, Current	46,507	22,247
Assets, Long-term	2,512	2,158
Liabilities, Current	46,661	64,859
Liabilities, Long-term	11,095	21,235
Energy derivative contracts
Derivative [Line Items]
Gross Amounts Recognized in the Statement of Financial Position 1	49,019	24,405
Total derivative assets	49,019	24,405
Total derivative liabilities	57,756	86,094
Not Designated as Hedging Instrument
Derivative [Line Items]
Total derivative assets	49,019	24,405
Total derivative liabilities	57,756	86,094
Not Designated as Hedging Instrument | Parent Company [Member]
Derivative [Line Items]
Assets, Current	46,507	22,247
Assets, Long-term	2,512	2,158
Liabilities, Current	46,661	64,859
Liabilities, Long-term	$ 11,095	$ 21,235
Not Designated as Hedging Instrument | Electric Generation Fuel
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	194.8	166.8
Not Designated as Hedging Instrument | Purchased Electricity
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MWh	6.6	2.9
Not Designated as Hedging Instrument | Electric Portfolio
Derivative [Line Items]
Total derivative assets	$ 33,287	$ 13,391
Total derivative liabilities	27,284	49,050
Not Designated as Hedging Instrument | Natural Gas Portfolio
Derivative [Line Items]
Total derivative assets	15,732	11,014
Total derivative liabilities	$ 30,472	$ 37,044
Not Designated as Hedging Instrument | Gas Derivatives
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	336.6	332.1

Accounting for Derivative Ins_5

Accounting for Derivative Instruments and Hedging Activities (Schedule of Amounts Recognized in Statement of Income) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	$ (41,662)	$ 30,790	$ (83,795)
Subsidiaries [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(41,662)	30,790	(83,795)
Not Designated as Hedging Instrument
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(80,124)	71,830	(21,079)
Not Designated as Hedging Instrument | Other Income (Deductions) | Interest Expense
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	0	(28)	1,062
Not Designated as Hedging Instrument | Interest Rate Contract | Interest Expense
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	0	0	0
Not Designated as Hedging Instrument | Energy Related Derivative [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(23,186)	32,492	(62,318)
Not Designated as Hedging Instrument | Energy derivative contracts | Electric Generation Fuel
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(26,222)	23,195	39,656
Not Designated as Hedging Instrument | Energy derivative contracts | Purchased Electricity
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(12,240)	17,873	21,998
Not Designated as Hedging Instrument | Electric [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	$ (18,476)	$ (1,702)	$ (21,477)

Accounting for Derivative Ins_6

Accounting for Derivative Instruments and Hedging Activities (Schedule of Amounts Recognized in Other Comprehensive Income) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Parent Company [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax	$ 0	$ 0	$ 0

Accounting for Derivative Ins_7

Accounting for Derivative Instruments and Hedging Activities (Schedule of Effects of Non-hedging Derivative Instruments on Income) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives	$ 41,662	$ (30,790)	$ 83,795
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives	80,124	(71,830)	21,079
Not Designated as Hedging Instrument | Energy Related Derivative [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives	23,186	(32,492)	62,318
Not Designated as Hedging Instrument | Interest Rate Contract | Interest Expense
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives	0	0	0
Not Designated as Hedging Instrument | Commodity contracts: | Electric Generation Fuel
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives	26,222	(23,195)	(39,656)
Not Designated as Hedging Instrument | Commodity contracts: | Purchased Electricity
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives	12,240	(17,873)	(21,998)
Not Designated as Hedging Instrument | Electric [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives	18,476	1,702	21,477
Subsidiaries [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives	$ 41,662	$ (30,790)	$ 83,795

Accounting for Derivative Ins_8

Accounting for Derivative Instruments and Hedging Activities (Schedule of Contractual Contingent Liability Positions) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Electric Portfolio
Derivative [Line Items]
Fair Value Liability	$ 19,069	$ 40,914
Collateral Already Posted, Aggregate Fair Value	0	2,639
Contingent Collateral	574	3,187
Credit Rating | Natural Gas Portfolio
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	1,000
Forward Value of Contract [Member] | Electric Portfolio
Derivative [Line Items]
Fair Value Liability	0	353
Collateral Already Posted, Aggregate Fair Value	0	2,639
Contingent Collateral	0	0
Requested Credit for Adequate Assurance | Electric Portfolio
Derivative [Line Items]
Fair Value Liability	18,495	37,374
Collateral Already Posted, Aggregate Fair Value	0	0
Contingent Collateral	0	0
Credit Rating
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	6,400
Credit Rating | Electric Portfolio
Derivative [Line Items]
Fair Value Liability	574	3,187
Collateral Already Posted, Aggregate Fair Value	0	0
Contingent Collateral	$ 574	$ 3,187

Accounting for Derivative Ins_9

Accounting for Derivative Instruments and Hedging Activities (Offsetting) (Details) - Energy derivative contracts - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Assets:
Gross Amounts Recognized in the Statement of Financial Position 1	$ 49,019	$ 24,405
Gross Amounts Offset in the Statement of Financial Position	0	0
Net of Amounts Presented in the Statement of Financial Position	49,019	24,405
Commodity Contracts	25,388	17,940
Cash Collateral Received/Posted	0	0
Net Amount	23,631	6,465
Liabilities:
Gross Amounts Recognized in the Statement of Financial Position 1	57,756	86,094
Gross Amounts Offset in the Statement of Financial Position	0	0
Net of Amounts Presented in the Statement of Financial Position	57,756	86,094
Commodity Contracts	25,388	17,940
Cash Collateral Received/Posted	0	353
Net Amount	$ 32,368	$ 67,801

Fair Value Measurements - Asset

Fair Value Measurements - Assets and Liabilities Measured on Recurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Measurements, Recurring | Parent Company [Member] | Level 3 | Electric Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	$ 4,522
Derivative Liabilities	3,160
Fair Value, Measurements, Recurring | Parent Company [Member] | Level 3 | Natural Gas Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	3,485
Derivative Liabilities	1,812
Fair Value, Measurements, Recurring | Subsidiaries [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	49,019	$ 24,405
Derivative Liabilities	57,756	86,094
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Electric Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	33,287	13,391
Derivative Liabilities	27,284	49,050
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Natural Gas Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	15,732	11,014
Derivative Liabilities	30,472	37,044
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	41,012	16,839
Derivative Liabilities	52,784	81,549
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Level 2 | Electric Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	28,765	9,866
Derivative Liabilities	24,124	46,623
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Level 2 | Natural Gas Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	12,247	6,973
Derivative Liabilities	28,660	34,926
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	8,007	7,566
Derivative Liabilities	4,972	4,545
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Level 3 | Electric Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		3,525
Derivative Liabilities		2,427
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Level 3 | Natural Gas Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		4,041
Derivative Liabilities		2,118
Carrying Amount | Parent Company [Member] | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Notes receivable and other	$ 49,500	$ 48,500

Fair Value Measurements - Debt

Fair Value Measurements - Debt at Carrying and Fair Value (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Subsidiaries [Member] | Carrying Amount | Income Approach Valuation Technique
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	$ 3,894,860	$ 3,749,911
Subsidiaries [Member] | Carrying Amount | Income Approach Valuation Technique | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unamortized Debt Issuance Expense	24,600	24,600
Junior subordinated notes	0	250,000
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	3,894,860	3,499,911
Subsidiaries [Member] | Total | Income Approach Valuation Technique
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	4,574,611	4,789,065
Subsidiaries [Member] | Total | Income Approach Valuation Technique | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Junior subordinated notes	0	238,935
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	4,574,611	4,550,130
Parent Company [Member] | Carrying Amount | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Notes Receivable, Fair Value Disclosure	49,500	48,500
Parent Company [Member] | Carrying Amount | Income Approach Valuation Technique
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	5,672,491	5,457,929
Parent Company [Member] | Carrying Amount | Income Approach Valuation Technique | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unamortized Debt Issuance Expense	26,100	27,900
Junior subordinated notes	0	250,000
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	5,510,591	5,105,329
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure	161,900	102,600
Parent Company [Member] | Total | Income Approach Valuation Technique
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	6,605,642	6,862,050
Parent Company [Member] | Total | Income Approach Valuation Technique | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Junior subordinated notes	0	238,935
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	6,443,742	6,520,515
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure	$ 161,900	$ 102,600

Fair Value Measurements - Unobs

Fair Value Measurements - Unobservable Input Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Level 3 Roll-Forward Net Asset(Liability)
Balance at beginning of period	$ 3,021	$ 1,597	$ (9,728)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Included in earnings	34,604	2,781	4,007
Included in regulatory assets / liabilities	6,075	6,346	4,312
Settlements	(40,264)	(12,921)	(3,808)
Transferred into Level 3	(1,987)	(30)	(3,021)
Transferred out Level 3	1,586	5,248	9,835
Balance at end of period	3,035	3,021	1,597
Electric Portfolio
Level 3 Roll-Forward Net Asset(Liability)
Balance at beginning of period	1,098	972	(7,345)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Included in earnings	34,604	2,781	4,007
Included in regulatory assets / liabilities	0	0	0
Settlements	(33,067)	(6,549)	(1,129)
Transferred into Level 3	(1,987)	523	(3,021)
Transferred out Level 3	714	3,371	8,460
Balance at end of period	1,362	1,098	972
Unrealized gain (loss) on derivative instruments, net	1,100	1,500	2,000
Natural Gas Portfolio
Level 3 Roll-Forward Net Asset(Liability)
Balance at beginning of period	1,923	625	(2,383)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Included in earnings	0	0	0
Included in regulatory assets / liabilities	6,075	6,346	4,312
Settlements	(7,197)	(6,372)	(2,679)
Transferred into Level 3	0	(553)	0
Transferred out Level 3	872	1,877	1,375
Balance at end of period	$ 1,673	$ 1,923	$ 625

Fair Value Measurements - Valua

Fair Value Measurements - Valuation Techniques (Details)	3 Months Ended			9 Months Ended	12 Months Ended
	Mar. 31, 2018USD ($)$ / MWh	Sep. 30, 2017USD ($)	Mar. 31, 2017USD ($)$ / MWh	Sep. 30, 2017USD ($)$ / MWh	Dec. 31, 2018USD ($)$ / MWh$ / MMBTU	Dec. 31, 2017USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of Intangible Assets (Excluding Goodwill)					$ 1,907,000	$ 81,345,000
Fair Value measurement, sensitivity analysis, hypothetical increase or decrease of market prices, result on fair value, percent					10.00%
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value					$ 2,600,000
Energy derivative contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net of Amounts Presented in the Statement of Financial Position					49,019,000	24,405,000
Net of Amounts Presented in the Statement of Financial Position					$ 57,756,000	$ 86,094,000
Natural Gas Portfolio | Income Approach Valuation Technique | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU					1.84
Natural Gas Portfolio | Income Approach Valuation Technique | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU					5.80
Natural Gas Portfolio | Income Approach Valuation Technique | Weighted Average
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU					3.18
Natural Gas Portfolio | Parent Company [Member] | Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net of Amounts Presented in the Statement of Financial Position					$ 3,485,000
Net of Amounts Presented in the Statement of Financial Position					$ 1,812,000
Electric Portfolio | Income Approach Valuation Technique | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Power prices (per MWh) | $ / MWh					11.35
Electric Portfolio | Income Approach Valuation Technique | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Power prices (per MWh) | $ / MWh					66.45
Electric Portfolio | Income Approach Valuation Technique | Weighted Average
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Power prices (per MWh) | $ / MWh					29.63
Electric Portfolio | Parent Company [Member] | Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net of Amounts Presented in the Statement of Financial Position					$ 4,522,000
Net of Amounts Presented in the Statement of Financial Position					$ 3,160,000
Wells Project1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite-Lived Intangible Assets, Net	$ 4,302,000	$ 10,621,000	$ 14,879,000	$ 10,621,000
Impairment of Intangible Assets (Excluding Goodwill)	$ 1,907,000	1,012,000	$ 1,812,000
Wells Project1 | Income Approach Valuation Technique | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Power prices (per MWh) | $ / MWh	9.69		8.76	14.06
Fair Value Inputs, Power Contract Costs	$ 4,126		$ 3,965	$ 4,126
Wells Project1 | Income Approach Valuation Technique | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Power prices (per MWh) | $ / MWh	25.30		26.70	26.86
Fair Value Inputs, Power Contract Costs	$ 4,126		$ 4,223	$ 4,126
Wells Project1 | Income Approach Valuation Technique | Weighted Average
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Power prices (per MWh) | $ / MWh	17.50		20.86	22.24
Fair Value Inputs, Power Contract Costs	$ 4,126		$ 4,051	$ 4,126
Rocky Reach Project
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite-Lived Intangible Assets, Net			235,331,000
Impairment of Intangible Assets (Excluding Goodwill)			75,513,000
Rocky Reach Project | Income Approach Valuation Technique | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Power prices (per MWh) | $ / MWh	8.53
Fair Value Inputs, Power Contract Costs	$ 5,827
Rocky Reach Project | Income Approach Valuation Technique | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Power prices (per MWh) | $ / MWh	48.21
Fair Value Inputs, Power Contract Costs	$ 6,780
Rocky Reach Project | Income Approach Valuation Technique | Weighted Average
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Power prices (per MWh) | $ / MWh	27.69
Fair Value Inputs, Power Contract Costs	$ 6,150
Priest Rapids Development
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite-Lived Intangible Assets, Net			5,665,000
Impairment of Intangible Assets (Excluding Goodwill)			3,008,000
Priest Rapids Development | Income Approach Valuation Technique | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Power prices (per MWh) | $ / MWh	13.70
Fair Value Inputs, Power Contract Costs	$ 620
Priest Rapids Development | Income Approach Valuation Technique | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Power prices (per MWh) | $ / MWh	29.38
Fair Value Inputs, Power Contract Costs	$ 4,022
Priest Rapids Development | Income Approach Valuation Technique | Weighted Average
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Power prices (per MWh) | $ / MWh	23.14
Fair Value Inputs, Power Contract Costs	$ 2,306
Carrying Amount | Wells Project1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure	$ 2,395,000	$ 9,609,000	13,067,000	$ 9,609,000
Carrying Amount | Rocky Reach Project
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure			159,818,000
Carrying Amount | Priest Rapids Development
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure			$ 2,657,000

Employee Investment Plans (Deta

Employee Investment Plans (Details) - Subsidiaries [Member] $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Defined Contribution Plan
Employer matching contribution, percent	1.00%	4.50%
Maximum annual contribution per employee, percent		6.00%
Employer discretionary contribution amount		$ 20.7	$ 19.2	$ 17.2
Defined Contribution Plan, Vesting Years		3
First 3 Percent
Defined Contribution Plan
Employer matching contribution, percent		100.00%
Maximum annual contribution per employee, percent		3.00%
Second 3 Percent
Defined Contribution Plan
Employer matching contribution, percent		50.00%
Maximum annual contribution per employee, percent		3.00%
Cash Balance Formula
Defined Contribution Plan
Employer matching contribution, percent		100.00%
Maximum annual contribution per employee, percent		6.00%
Employer additional contribution of base pay, percentage		1.00%
Final Average Earnings Formula
Defined Contribution Plan
Employer matching contribution, percent		55.00%
Maximum annual contribution per employee, percent		6.00%
employer contribution [Member]
Defined Contribution Plan
Employer matching contribution, percent		4.00%

Retirement Benefits - Change in

Retirement Benefits - Change in Net Benefit Obligation and Fair Value (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	$ 0	$ 0
Change in benefit obligation:
Benefit obligation at beginning of period	11,454		$ 11,194
Service cost	69	72
Interest cost	444	500
Actuarial loss (gain)	(379)	725
Benefits paid	(1,037)	(1,137)
Medicare part D subsidy received	85	100
Defined Benefit Plan, Expected Administration Expenses	0	0
Benefit obligation at end of period	10,636	11,454
Change in plan assets:
Fair value of plan assets at beginning of period	7,138		7,200
Actual return on plan assets	(395)	784
Employer contribution	254	291
Benefits paid	(1,037)	(1,137)
Defined Benefit Plan, Plan Assets, Administration Expense	0	0
Fair value of plan assets at end of period	5,960	7,138
Funded status at end of period	(4,676)	(4,316)
Subsidiaries [Member] | Other Benefits
Change in benefit obligation:
Service cost	69	72	93
Interest cost	444	500	533
Nonqualified Plan | Qualified Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	(1,446)	0
Change in benefit obligation:
Benefit obligation at beginning of period	55,754		51,734
Service cost	847	913
Interest cost	2,120	2,285
Actuarial loss (gain)	1,122	2,722
Benefits paid	(5,581)	(1,900)
Medicare part D subsidy received	0	0
Defined Benefit Plan, Expected Administration Expenses	0	0
Benefit obligation at end of period	55,708	55,754
Change in plan assets:
Fair value of plan assets at beginning of period	0		0
Actual return on plan assets	0	0
Employer contribution	5,581	1,900
Benefits paid	(5,581)	(1,900)
Defined Benefit Plan, Plan Assets, Administration Expense	0	0
Fair value of plan assets at end of period	0	0
Funded status at end of period	(55,708)	(55,754)
Nonqualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Change in benefit obligation:
Service cost	847	913	1,085
Interest cost	2,120	2,285	2,325
Qualified Plan | Qualified Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	0	0
Change in benefit obligation:
Benefit obligation at beginning of period	700,481		652,607
Service cost	22,757	20,081
Interest cost	27,303	28,373
Actuarial loss (gain)	(29,067)	40,945
Benefits paid	(42,662)	(40,594)
Medicare part D subsidy received	0	0
Defined Benefit Plan, Expected Administration Expenses	(1,169)	(931)
Benefit obligation at end of period	677,643	700,481
Change in plan assets:
Fair value of plan assets at beginning of period	704,360		620,260
Actual return on plan assets	(38,379)	107,836
Employer contribution	18,000	18,000
Benefits paid	(42,662)	(40,594)
Defined Benefit Plan, Plan Assets, Administration Expense	(1,077)	(1,142)
Fair value of plan assets at end of period	640,242	704,360
Funded status at end of period	(37,401)	3,879
Qualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Change in benefit obligation:
Service cost	22,757	20,081	18,913
Interest cost	$ 27,303	$ 28,373	$ 28,689

Retirement Benefits - Amounts R

Retirement Benefits - Amounts Recognized (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2015
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation	$ 10,636	$ 11,454	$ 11,194
Defined Benefit Plan, Accumulated Benefit Obligation	10,557	11,367
Defined Benefit Plan, Plan Assets, Amount	5,960	7,138	7,200
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets	0	0
Current liabilities	(332)	(317)
Noncurrent liabilities	(4,344)	(3,999)
Net assets (liabilities)	(4,676)	(4,316)
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	488	403
Amortization of net (loss) gain	335	401
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), before Tax	0	0
Amortization of prior service (cost) credit	0	0
Total change in other comprehensive income for year	823	804
Parent Company [Member] | Other Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)	(2,564)	(3,386)
Prior service cost (credit)	0	0
Total	(2,564)	(3,386)
Subsidiaries [Member] | Other Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)	(3,857)	(4,901)
Prior service cost (credit)	0	0
Total	(3,857)	(4,901)
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	488	452
Amortization of net (loss) gain	556	641
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), before Tax	0	0
Amortization of prior service (cost) credit	0	0
Total change in other comprehensive income for year	1,044	1,093
Nonqualified Plan | Qualified Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation	55,708	55,754	51,734
Defined Benefit Plan, Accumulated Benefit Obligation	51,031	52,681
Defined Benefit Plan, Plan Assets, Amount	0	0	0
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets	0	0
Current liabilities	(6,249)	(5,486)
Noncurrent liabilities	(49,459)	(50,268)
Net assets (liabilities)	(55,708)	(55,754)
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	1,122	2,722
Amortization of net (loss) gain	(1,580)	(1,076)
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	(619)	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), before Tax	1,446	0
Amortization of prior service (cost) credit	(42)	(42)
Total change in other comprehensive income for year	327	1,604
Nonqualified Plan | Parent Company [Member] | Qualified Pension Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)	9,612	10,689
Prior service cost (credit)	1,607	204
Total	11,219	10,893
Nonqualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)	11,450	13,134
Prior service cost (credit)	1,609	208
Total	13,059	13,342
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	1,122	2,722
Amortization of net (loss) gain	(2,069)	(1,565)
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	(737)	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), before Tax	1,446	0
Amortization of prior service (cost) credit	(44)	(44)
Total change in other comprehensive income for year	(282)	1,113
Qualified Plan | Qualified Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation	677,643	700,481	652,607
Defined Benefit Plan, Accumulated Benefit Obligation	668,469	688,908
Defined Benefit Plan, Plan Assets, Amount	640,242	704,360	$ 620,260
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets	0	3,879
Current liabilities	0	0
Noncurrent liabilities	(37,401)	0
Net assets (liabilities)	(37,401)	3,879
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	59,422	(18,896)
Amortization of net (loss) gain	(2,187)	0
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), before Tax	0	0
Amortization of prior service (cost) credit	1,980	1,980
Total change in other comprehensive income for year	59,215	(16,916)
Qualified Plan | Parent Company [Member] | Qualified Pension Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)	94,929	37,693
Prior service cost (credit)	(5,863)	(7,843)
Total	89,066	29,850
Qualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)	229,819	185,277
Prior service cost (credit)	(4,659)	(6,232)
Total	225,160	179,045
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	59,460	(18,817)
Amortization of net (loss) gain	(14,917)	(13,048)
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), before Tax	0	0
Amortization of prior service (cost) credit	1,573	1,573
Total change in other comprehensive income for year	46,116	$ (30,292)
Scenario, Plan [Member] | Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Plans, Net Gain (Loss), Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	(500)
Scenario, Plan [Member] | Subsidiaries [Member] | Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Plans, Net Gain (Loss), Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	(400)
Scenario, Plan [Member] | Nonqualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Plans, Net Gain (Loss), Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	(1,700)
Pension and Other Postretirement Benefit Plans, Prior Service Cost, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	(300)
Scenario, Plan [Member] | Qualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Plans, Net Gain (Loss), Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	$ (12,700)

Retirement Benefits - Net Perio

Retirement Benefits - Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Other Benefits
Components of net periodic benefit cost:
Service cost	$ 69	$ 72
Interest cost	444	500
Parent Company [Member] | Other Benefits
Components of net periodic benefit cost:
Service cost	69	72	$ 93
Interest cost	444	500	533
Expected return on plan assets	(472)	(461)	(446)
Amortization of prior service cost (credit)	0	0	0
Amortization of net loss (gain)	(335)	(402)	(386)
Net periodic benefit cost	(294)	(291)	(206)
Subsidiaries [Member] | Other Benefits
Components of net periodic benefit cost:
Service cost	69	72	93
Interest cost	444	500	533
Expected return on plan assets	(472)	(461)	(446)
Amortization of prior service cost (credit)	0	0	0
Amortization of net loss (gain)	(556)	(641)	(632)
Net periodic benefit cost	(515)	(530)	(452)
Nonqualified Plan | Qualified Pension Benefits
Components of net periodic benefit cost:
Service cost	847	913
Interest cost	2,120	2,285
Nonqualified Plan | Parent Company [Member] | Qualified Pension Benefits
Components of net periodic benefit cost:
Service cost	847	913	1,085
Interest cost	2,120	2,285	2,325
Expected return on plan assets	0	0	0
Amortization of prior service cost (credit)	1,580	42	42
Amortization of net loss (gain)	42	1,077	911
Net periodic benefit cost	4,589	4,317	4,363
Nonqualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Components of net periodic benefit cost:
Service cost	847	913	1,085
Interest cost	2,120	2,285	2,325
Expected return on plan assets	0	0	0
Amortization of prior service cost (credit)	44	44	44
Amortization of net loss (gain)	2,069	1,565	1,330
Net periodic benefit cost	5,080	4,807	4,784
Qualified Plan | Qualified Pension Benefits
Components of net periodic benefit cost:
Service cost	22,757	20,081
Interest cost	27,303	28,373
Qualified Plan | Parent Company [Member] | Qualified Pension Benefits
Components of net periodic benefit cost:
Service cost	22,757	20,081	18,913
Interest cost	27,303	28,373	28,689
Expected return on plan assets	(50,202)	(47,784)	(46,619)
Amortization of prior service cost (credit)	(1,980)	(1,980)	(1,980)
Amortization of net loss (gain)	2,187	0	0
Net periodic benefit cost	65	(1,310)	(997)
Qualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Components of net periodic benefit cost:
Service cost	22,757	20,081	18,913
Interest cost	27,303	28,373	28,689
Expected return on plan assets	(50,240)	(47,862)	(46,814)
Amortization of prior service cost (credit)	(1,573)	(1,573)	(1,573)
Amortization of net loss (gain)	14,917	13,048	15,257
Net periodic benefit cost	$ 13,164	$ 12,067	$ 14,472

Retirement Benefits - Assumptio

Retirement Benefits - Assumptions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates
1% Increase, Effect on post-retirement benefit obligation		$ 19	$ 23
1% Decrease, Effect on post-retirement benefit obligation		(18)	(22)
1% Increase, Effect on service and interest cost components		1	1
1% Decrease, Effect on service and interest cost components		$ (1)	$ (1)
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Current and Prior Fiscal Year		1.00%
Other Benefits
Benefit Obligation Assumptions
Discount rate		4.40%	4.00%		4.50%
Rate of compensation increase		4.50%	4.50%		4.50%
Medical trend rate		7.60%	6.80%		8.80%
Benefit Cost Assumptions
Discount rate		4.40%	4.50%	4.65%
Return on plan assets		7.00%	6.75%	6.75%
Rate of compensation increase		4.50%	4.50%	4.50%
Medical trend rate		7.60%	9.50%	5.30%
Nonqualified Plan | Qualified Pension Benefits
Benefit Obligation Assumptions
Discount rate		4.40%	4.00%		4.50%
Rate of compensation increase		4.50%	4.50%		4.50%
Medical trend rate		0.00%	0.00%		0.00%
Benefit Cost Assumptions
Discount rate		4.40%	4.50%	4.65%
Return on plan assets		0.00%	0.00%	0.00%
Rate of compensation increase		4.50%	4.50%	4.50%
Medical trend rate		0.00%	0.00%	0.00%
Qualified Plan | Qualified Pension Benefits
Benefit Obligation Assumptions
Discount rate		4.40%	4.00%		4.50%
Rate of compensation increase		4.50%	4.50%		4.50%
Medical trend rate		0.00%	0.00%		0.00%
Benefit Cost Assumptions
Discount rate		4.40%	4.50%	4.65%
Return on plan assets		7.50%	7.45%	7.75%
Rate of compensation increase		4.50%	4.50%	4.50%
Medical trend rate		0.00%	0.00%	0.00%
Scenario, Plan [Member]
Assumed Health Care Cost Trend Rates
Medical inflation rate assumed for next fiscal year		7.60%
Scenario, Forecast [Member]
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates
defined benefit plan health care cost trend rate assumed for next two years	3.90%

Retirement Benefits - Future Be

Retirement Benefits - Future Benefit Payments (Details) $ in Thousands	Dec. 31, 2018USD ($)
Other Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,016	$ 1,112
2,017	1,094
2,018	1,064
2,019	1,038
2,020	1,008
2021-2025	4,410
2016, without Medicare Part D subsidy	892
2017, without Medicare Part D subsidy	863
2018, without Medicare Part D subsidy	899
2019, without Medicare Part D subsidy	872
2020, without Medicare Part D subsidy	841
2021-2025, without Medicare Part D subsidy	3,704
Qualified Plan | Qualified Pension Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,016	43,700
2,017	45,100
2,018	45,900
2,019	47,100
2,020	48,500
2021-2025	252,400
Nonqualified Plan | Qualified Pension Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,016	6,249
2,017	4,993
2,018	1,887
2,019	5,378
2,020	3,678
2021-2025	$ 39,400

Retirement Benefits - Plan Asse

Retirement Benefits - Plan Asset Allocation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Domestic Small Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	9.00%
Foreign Equity Funds [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	25.00%
Domestic Large Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	31.00%
Fixed income
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	25.00%
Real estate
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	0.00%
Absolute return
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	10.00%
Cash and cash equivalents
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation	0.00%
Fair Value, Measurements, Recurring | Pension Plan [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 640,243	$ 704,360
Fair Value, Measurements, Recurring | Equities: | Pension Plan [Member] | Level 1
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	281,610	348,300
Fair Value, Measurements, Recurring | Equities: | Pension Plan [Member] | Level 2
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	702	67,674
Fair Value, Measurements, Recurring | Equities: | Pension Plan [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	282,312	415,974
Fair Value, Measurements, Recurring | Fair Value Measurement [Domain] | Pension Plan [Member] | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	356,586	237,427
Fair Value, Measurements, Recurring | Mutual Funds | Pension Plan [Member] | Level 1
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	103,661	117,796
Fair Value, Measurements, Recurring | Mutual Funds | Pension Plan [Member] | Level 2
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Fair Value, Measurements, Recurring | Mutual Funds | Pension Plan [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	103,661	117,796
Fair Value, Measurements, Recurring | Common Stock | Pension Plan [Member] | Level 1
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	177,949	209,504
Fair Value, Measurements, Recurring | Common Stock | Pension Plan [Member] | Level 2
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Fair Value, Measurements, Recurring | Common Stock | Pension Plan [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	177,949	209,504
Fair Value, Measurements, Recurring | US Treasury and Government [Member] | Pension Plan [Member] | Level 1
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	18,316
Fair Value, Measurements, Recurring | US Treasury and Government [Member] | Pension Plan [Member] | Level 2
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	23,782
Fair Value, Measurements, Recurring | US Treasury and Government [Member] | Pension Plan [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	42,098
Fair Value, Measurements, Recurring | Corporate Bond Securities [Member] | Pension Plan [Member] | Level 1
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Fair Value, Measurements, Recurring | Corporate Bond Securities [Member] | Pension Plan [Member] | Level 2
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	34,588
Fair Value, Measurements, Recurring | Corporate Bond Securities [Member] | Pension Plan [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	34,588
Fair Value, Measurements, Recurring | Cash and cash equivalents | Pension Plan [Member] | Level 1
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	2,684
Fair Value, Measurements, Recurring | Cash and cash equivalents | Pension Plan [Member] | Level 2
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	702	9,304
Fair Value, Measurements, Recurring | Cash and cash equivalents | Pension Plan [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 702	$ 11,988
Minimum | Domestic Small Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	0
Minimum | Foreign Equity Funds [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	0.1
Minimum | Domestic Large Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	0.25
Minimum | Fixed income
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	0.15
Minimum | Real estate
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	0
Minimum | Absolute return
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	0.05
Minimum | Cash and cash equivalents
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	0
Maximum | Domestic Small Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	0.15
Maximum | Foreign Equity Funds [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	0.3
Maximum | Domestic Large Cap Equity Investments [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	0.4
Maximum | Fixed income
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	0.3
Maximum | Real estate
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	0.1
Maximum | Absolute return
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	0.15
Maximum | Cash and cash equivalents
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum (Deprecated 2017-01-31)	0.05

Retirement Benefits - Fair Valu

Retirement Benefits - Fair Value Level 3 Rollforward (Details) - Fair Value, Measurements, Recurring - Net Receivables [Member] - Qualified Pension Benefits - Fair Value Measured at Net Asset Value Per Share [Member] $ in Thousands	Dec. 31, 2018USD ($)
Change in plan assets:
Fair value of plan assets at beginning of period	$ 50,959
Fair value of plan assets at end of period	$ 1,345

Retirement Benefits - Textuals

Retirement Benefits - Textuals (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018
Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent	1.00%	4.50%
Scenario, Plan [Member] | Other Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Net Gain (Loss)		$ (0.5)
Scenario, Plan [Member] | Subsidiaries [Member] | Other Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Net Gain (Loss)		(0.4)
Estimated Future Employer Contributions in Current Fiscal Year		0.3
Scenario, Plan [Member] | Qualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Net Gain (Loss)		(12.7)
Pension and Other Postretirement Benefit Plans, Net Prior Service Cost or Credit, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year		1.6
Estimated Future Employer Contributions in Current Fiscal Year		18
Scenario, Plan [Member] | Nonqualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Net Gain (Loss)		(1.7)
Estimated Future Employer Contributions in Current Fiscal Year		$ 6.2
Cash Balance Formula | Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent		100.00%
employer contribution [Member] | Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent		4.00%

Retirement Benefits Accumulated

Retirement Benefits Accumulated Benefit Obligation (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2015
Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation	$ 10,636	$ 11,454	$ 11,194
Defined Benefit Plan, Accumulated Benefit Obligation	10,557	11,367
Defined Benefit Plan, Plan Assets, Amount	5,960	7,138	$ 7,200
Fair Value, Measurements, Recurring | Level 1 | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount
Fair Value, Measurements, Recurring | Level 1 | Mutual Funds | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	103,661	117,796
Fair Value, Measurements, Recurring | Level 1 | Mutual Funds | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	5,910	7,089
Fair Value, Measurements, Recurring | Level 1 | Cash and cash equivalents | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	2,684
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	640,243	704,360
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	5,960	7,138
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Mutual Funds | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	103,661	117,796
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Mutual Funds | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	5,910	7,089
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Cash and cash equivalents | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	702	11,988
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value Measurement [Domain] | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	50	49
Fair Value, Measurements, Recurring | Level 2 | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount
Fair Value, Measurements, Recurring | Level 2 | Mutual Funds | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Fair Value, Measurements, Recurring | Level 2 | Mutual Funds | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Fair Value, Measurements, Recurring | Level 2 | Cash and cash equivalents | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 702	$ 9,304

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	May 01, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosures [Line Items]
Current Federal Tax Expense (Benefit)		$ 10,382	$ 1,127	$ 0
Current State and Local Tax Expense (Benefit)		263	17	20
Federal		19,451	254,420	140,315
State		(4)	(421)	(131)
Total income tax expense		30,092	255,143	140,204
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Revenue Change		51,200
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, effect on income tax expense		17,900
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Effect on Income Taxes due to revaluation		80,900
Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Current Federal Tax Expense (Benefit)		19,283	1,127	0
Current State and Local Tax Expense (Benefit)		438	17	20
Federal		30,979	210,842	175,327
State		0	0	0
Total income tax expense	$ 34,600	$ 50,700	211,986	$ 175,347
Income Tax Non-Reg Treatment [Member] | Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, unregulated portion			3,000
Income Tax Reg Treatment [Member] | Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, PTC revaluation			$ 33,300

Income Taxes - Income Tax Recon

Income Taxes - Income Tax Reconciliation (Details) - USD ($) $ in Thousands	May 01, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosures [Line Items]
Current Federal Tax Expense (Benefit)		$ 10,382	$ 1,127	$ 0
Current State and Local Tax Expense (Benefit)		263	17	20
Federal		19,451	254,420	140,315
State		(4)	(421)	(131)
Income Tax Reconciliation [Abstract]
Income taxes at the statutory rate		55,800	148,847	158,586
Production tax credit1		0	0	(12,925)
Utility plant differences2		(25,871)	0	3,966
Income Tax Reconciliation, Executive Compensation		4,439	0	0
Income Tax Reconciliation, Treasury Grant		(4,861)	(9,537)	(9,788)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		0	117,185	0
Other–net		585	(1,352)	365
Total income tax expense		$ 30,092	$ 255,143	$ 140,204
Effective tax rate		11.30%	60.00%	30.90%
Deferred Tax Assets, Regulatory Assets and Liabilities, Accelerated Tax Depreciation		$ 919,800
Deferred Tax Assets, Regulatory Assets and Liabilities, Undetermined refund		92,500
Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Current Federal Tax Expense (Benefit)		19,283	$ 1,127	$ 0
Current State and Local Tax Expense (Benefit)		438	17	20
Federal		30,979	210,842	175,327
State		0	0	0
Income Tax Reconciliation [Abstract]
Income taxes at the statutory rate		77,251	185,430	194,572
Production tax credit1		0	0	(12,925)
Utility plant differences2		(25,871)	0	3,966
Income Tax Reconciliation, Executive Compensation		4,439	0	0
Income Tax Reconciliation, Treasury Grant		(4,861)	(9,537)	(9,788)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		0	36,328	0
Other–net		(258)	(235)	(478)
Total income tax expense	$ 34,600	$ 50,700	$ 211,986	$ 175,347
Effective tax rate		13.80%	40.00%	31.50%
Deferred Tax Assets, Regulatory Assets and Liabilities		$ (1,012,300)		$ (71,500)

Income Taxes - Deferred Income

Income Taxes - Deferred Income Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Deferred Tax Liabilities, Gross
Utility plant and equipment	$ 1,998,721	$ 2,034,328
Other deferred tax liabilities	113,051	172,048
Subtotal deferred tax liabilities	2,111,772	2,206,376
Deferred Tax Assets, Net Regulatory Liability for Income Taxes	(975,974)	(1,011,626)
Deferred Tax Assets, Gross
Net operating loss carryforward	(224,885)	(212,168)
Production tax credit carryforward	(121,616)	(187,617)
Deferred Tax Assets, Other	0	(48,097)
Subtotal deferred tax assets	(1,322,475)	(1,459,508)
Total net deferred tax liabilities	789,297	746,868
Subsidiaries [Member]
Deferred Tax Liabilities, Gross
Utility plant and equipment	1,998,721	2,034,328
Other deferred tax liabilities	25,880	86,933
Subtotal deferred tax liabilities	2,024,601	2,121,261
Deferred Tax Assets, Net Regulatory Liability for Income Taxes	(976,582)	(1,012,260)
Deferred Tax Assets, Gross
Production tax credit carryforward	(121,616)	(187,617)
Deferred Tax Assets, Other	0	(51,911)
Subtotal deferred tax assets	(1,098,198)	(1,251,788)
Total net deferred tax liabilities	$ 926,403	$ 869,473

Income Taxes - Balance Sheet Lo

Income Taxes - Balance Sheet Location (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosures [Line Items]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	$ 0	$ 117,185	$ 0
Non-current deferred taxes	789,297	746,868
Total net deferred tax liabilities	789,297	746,868
Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	0	36,328	0
Deferred Tax Assets, Regulatory Assets and Liabilities	(1,012,300)		$ (71,500)
Non-current deferred taxes	926,403	869,473
Total net deferred tax liabilities	926,403	$ 869,473
ARAM [Member]
Income Tax Disclosures [Line Items]
Deferred Other Tax Expense (Benefit)	$ 29,800

Litigation (Details)

Litigation (Details) $ in Millions	Mar. 28, 2017USD ($)	Dec. 31, 2018USD ($)unit	Dec. 31, 2017USD ($)
Loss Contingencies [Line Items]
Litigation Settlement, Amount Awarded to Other Party	$ 1.5
Colstrip Unit One and Two
Loss Contingencies [Line Items]
Equity Method Investment, Ownership Percentage		50.00%
Colstrip Unit Three and Four
Loss Contingencies [Line Items]
Equity Method Investment, Ownership Percentage		25.00%
Colstrip Unit One and Two
Loss Contingencies [Line Items]
Number of Units | unit		2
Colstrip Regulatory Asset [Domain]
Loss Contingencies [Line Items]
Regulatory Assets		$ 130.7	$ 127.6

Commitments and Contingencies_2

Commitments and Contingencies (Details) $ in Thousands, MWh in Millions	12 Months Ended
	Dec. 31, 2018USD ($)MWhContracts$ / kWhMW	Dec. 31, 2017USD ($)MWh	Dec. 31, 2016USD ($)MWh
Long-term Purchase Commitment [Line Items]
Long-term Line of Credit, Noncurrent	$ 11,900	$ 102,600
Average cost of Company's energy output (US$ per kWh) | $ / kWh	0.023
Number of Public Utility Districts with long term purchase agreements | Contracts	3
Contract expenses	$ 80,165	$ 73,827	$ 77,667
Percent of Output	13.70%
Megawatt Capacity | MW	706
Estimated 2019 Costs	$ 97,032
2019 Debt Service Costs	17,630
Interest included in 2019 Debt Service Costs	9,682
Debt Outstanding	142,427
Payment Obligations for Power Purchases
2,014	427,372
2,015	345,913
2,016	340,640
2,017	350,547
2,018	357,338
Thereafter	1,852,487
Total	$ 3,674,297
Total energy obtained during period under purchased power contracts (MWh) | MWh	14.1	14.5	13
Cost incurred during period to provide energy under purchased power contracts	$ 508,200	$ 456,400	$ 402,500
Daily take obligation under long-term service contract (percent)	100.00%
Daily delivery obligation under long-term service contract (percent)	100.00%
Natural Gas [Member]
Payment Obligations for Power Purchases
2,014	$ 311,601
2,015	162,384
2,016	157,156
2,017	144,008
2,018	91,851
Thereafter	0
Total	867,000
Columbia River projects
Payment Obligations for Power Purchases
2,014	92,905
2,015	86,691
2,016	76,378
2,017	85,807
2,018	87,452
Thereafter	631,283
Total	1,060,516
Other utilities
Payment Obligations for Power Purchases
2,014	888
2,015	0
2,016	0
2,017	0
2,018	0
Thereafter	0
Total	888
Non-utility contracts
Payment Obligations for Power Purchases
2,014	216,539
2,015	255,193
2,016	264,262
2,017	264,740
2,018	269,886
Thereafter	1,221,204
Total	2,491,824
Firm transportation service
Payment Obligations for Power Purchases
2,014	165,719
2,015	160,053
2,016	140,239
2,017	139,343
2,018	120,486
Thereafter	209,215
Total	935,055
Firm Storage and Peaking Service [Member]
Payment Obligations for Power Purchases
2,014	8,899
2,015	7,908
2,016	3,108
2,017	1,619
2,018	504
Thereafter	353
Total	22,391
Long-term Purchase Commitment, Demand Charges	119,900
Firm natural gas supply
Payment Obligations for Power Purchases
2,014	523,808
2,015	336,079
2,016	301,434
2,017	284,970
2,018	212,841
Thereafter	209,568
Total	1,868,700
Combustion turbines
Payment Obligations for Power Purchases
Long-term Purchase Commitment, Demand Charges	44,500
Energy production service contracts
Payment Obligations for Power Purchases
2,014	27,243
2,015	27,915
2,016	28,650
2,017	29,345
2,018	30,056
Thereafter	124,646
Total	267,855
Automated meter reading system
Payment Obligations for Power Purchases
2,014	45,080
2,015	44,193
2,016	44,741
2,017	45,416
2,018	46,106
Thereafter	142,724
Total	368,260
Service contract obligations
Payment Obligations for Power Purchases
2,014	72,323
2,015	72,108
2,016	73,391
2,017	74,761
2,018	76,162
Thereafter	267,370
Total	$ 636,115
Minimum | Combustion turbines
Payment Obligations for Power Purchases
Remaining terms under contract	1 year
Maximum | Combustion turbines
Payment Obligations for Power Purchases
Remaining terms under contract	26
Rock Island Project
Long-term Purchase Commitment [Line Items]
Percent of Output	25.00%
Megawatt Capacity | MW	156
Estimated 2019 Costs	$ 29,794
2019 Debt Service Costs	10,058
Interest included in 2019 Debt Service Costs	5,053
Debt Outstanding	$ 80,058
Rocky Reach Project
Long-term Purchase Commitment [Line Items]
Percent of Output	25.00%
Megawatt Capacity | MW	325
Estimated 2019 Costs	$ 30,378
2019 Debt Service Costs	5,240
Interest included in 2019 Debt Service Costs	2,297
Debt Outstanding	$ 36,289
Wells Project1
Long-term Purchase Commitment [Line Items]
Percent of Output	25.30%
Megawatt Capacity | MW	212
Estimated 2019 Costs	$ 32,662
2019 Debt Service Costs	0
Interest included in 2019 Debt Service Costs	0
Debt Outstanding	$ 0
Priest Rapids Development
Long-term Purchase Commitment [Line Items]
Percent of Output	0.60%
Megawatt Capacity | MW	6
Estimated 2019 Costs	$ 2,099
2019 Debt Service Costs	1,166
Interest included in 2019 Debt Service Costs	1,166
Debt Outstanding	$ 13,040
Wanapum Development
Long-term Purchase Commitment [Line Items]
Percent of Output	0.60%
Megawatt Capacity | MW	7
Estimated 2019 Costs	$ 2,099
2019 Debt Service Costs	1,166
Interest included in 2019 Debt Service Costs	1,166
Debt Outstanding	13,040
Natural Gas, US Regulated [Member] | Short-Term Energy Supply Contracts [Member]
Payment Obligations for Power Purchases
2,014	37,589
2,015	5,734
2,016	931
2,017	0
2,018	0
Thereafter	0
Total	44,254
Subsidiaries [Member] | Electricity, US Regulated [Member]
Payment Obligations for Power Purchases
2,014	117,000
2,015	4,000
2,016	0
2,017	0
2,018	0
Thereafter	0
Total	$ 121,100

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction	$ 3.9	$ 23.3
Related Party Transaction, Due from (to) Related Party	$ 1

Segment Information (Details)

Segment Information (Details)	12 Months Ended
	Dec. 31, 2018mi²segment
Segment Reporting Information [Line Items]
Number of operating segments | segment	1
Subsidiaries [Member]
Segment Reporting Information [Line Items]
Area of service territory (sqmi) | mi²	6,000

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Loss) Changes in AOCI, net of tax (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	$ (24,282)
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	(5,200)
Accumulated other comprehensive income (loss), net of tax	(77,202)	$ (24,282)
Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(126,906)
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	(27,332)
Accumulated other comprehensive income (loss), net of tax	(190,884)	(126,906)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(24,282)	(33,712)	$ (27,266)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(48,870)	10,251	(5,528)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	1,180	(821)	(918)
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	(5,230)
Other Comprehensive Income (Loss), Net of Tax	(52,920)	9,430	(6,446)
Accumulated other comprehensive income (loss), net of tax	(77,202)	(24,282)	(33,712)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(121,867)	(140,155)	(143,877)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(48,802)	10,200	(5,655)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	11,772	8,088	9,377
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	(26,233)
Other Comprehensive Income (Loss), Net of Tax	(63,263)	18,288	3,722
Accumulated other comprehensive income (loss), net of tax	(185,130)	(121,867)	(140,155)
Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(24,282)	(33,712)	(27,266)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(48,870)	10,251	(5,528)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	1,180	(821)	(918)
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	(5,230)
Other Comprehensive Income (Loss), Net of Tax	(52,920)	9,430	(6,446)
Accumulated other comprehensive income (loss), net of tax	(77,202)	(24,282)	(33,712)
Comprehensive Income [Member] | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(126,906)	(145,511)	(149,550)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(48,802)	10,200	(5,655)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	12,157	8,405	9,694
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	(27,333)
Other Comprehensive Income (Loss), Net of Tax	(63,978)	18,605	4,039
Accumulated other comprehensive income (loss), net of tax	(190,884)	(126,906)	(145,511)
Energy Related Derivative [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	0	0	0
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0	0	0
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	0
Other Comprehensive Income (Loss), Net of Tax	0	0	0
Accumulated other comprehensive income (loss), net of tax	0	0	0
Energy Related Derivative [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member] | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	0	0	0
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0	0	0
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	0
Other Comprehensive Income (Loss), Net of Tax	0	0	0
Accumulated other comprehensive income (loss), net of tax	0	0	0
Interest Rate Swap [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member] | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(5,039)	(5,356)	(5,673)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	385	317	317
Other Comprehensive (Income) Loss, Reclassification of Stranded Taxes to Retained Earnings	1,100
Other Comprehensive Income (Loss), Net of Tax	(715)	317	317
Accumulated other comprehensive income (loss), net of tax	$ (5,754)	$ (5,039)	$ (5,356)

Accumulated Other Comprehensi_4

Accumulated Other Comprehensive Income (Loss) Reclassifications Out of Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification of net unrealized loss on energy derivative instruments during the period, tax	$ 0	$ 0	$ 0
Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification of net unrealized loss on energy derivative instruments during the period, tax	0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	(385)	(317)	(317)
Reclassification out of Accumulated Other Comprehensive Income | Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Comprehensive income (loss)	(1,180)	821	918
Reclassification out of Accumulated Other Comprehensive Income | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Comprehensive income (loss)	(12,157)	(8,405)	(9,694)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Amortization of prior service cost	1,937	1,938	1,938
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax	(3,431)	(675)	(525)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax	(1,494)	1,263	1,413
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax	314	(442)	(495)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, after Tax	(1,180)	821	918
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Noncontrolling Interest [Member] | Energy Related Derivative [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax	0	0	0
Reclassification of net unrealized loss on energy derivative instruments during the period, tax	0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	0	0	0
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Noncontrolling Interest [Member] | Interest Rate Swap [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax	(487)	(488)	(488)
Reclassification of net unrealized loss on energy derivative instruments during the period, tax	102	171	171
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	(385)	(317)	(317)
Accumulated Defined Benefit Plans Adjustment Attributable to Noncontrolling Interest [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Amortization of prior service cost	1,529	1,529	1,529
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax	(16,430)	(13,972)	(15,955)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax	(14,901)	(12,443)	(14,426)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax	3,129	4,355	5,049
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, after Tax	(11,772)	(8,088)	(9,377)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Energy Related Derivative [Member] | Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax	0	0	0
Reclassification of net unrealized loss on energy derivative instruments during the period, tax	0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	$ 0	$ 0	$ 0

SUPPLEMENTAL QUARTERLY FINANCIA

SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Information [Line Items]
Operating revenues									$ 3,346,496	$ 3,460,276	$ 3,164,301
Operating income									554,058	739,106	765,474
Net income (loss)									235,622	175,194	312,899
Parent Company [Member]
Quarterly Financial Information [Line Items]
Operating revenues	$ 985,172	$ 651,464	$ 671,852	$ 1,038,008	$ 1,002,900	$ 660,377	$ 719,767	$ 1,077,232
Operating income	199,885	37,297	84,091	232,785	238,305	99,044	130,030	271,727
Net income (loss)	107,053	(21,970)	3,642	146,897	(467)	12,836	35,275	127,550	235,622	175,194	312,899
Subsidiaries [Member]
Quarterly Financial Information [Line Items]
Operating revenues	985,172	651,464	671,852	1,038,008	1,002,900	660,377	719,767	1,077,232	3,346,496	3,460,276	3,164,618
Operating income	193,432	46,147	81,701	235,856	248,995	96,369	126,800	268,431	557,136	740,595	770,552
Net income (loss)	$ 123,456	$ 3,891	$ 26,778	$ 163,037	$ 97,208	$ 29,100	$ 50,654	$ 143,092	$ 317,162	$ 320,054	$ 380,581

SCHEDULE I CONDENSED FINANCIA_2

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Statements of Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Condensed Financial Statements, Captions [Line Items]
Non-utility expense and other									$ (54,519)	$ (53,864)	$ (42,620)
Non-hedged interest rate swap expense									0	28	(1,062)
Interest expense									(343,795)	(354,802)	(355,139)
Income taxes									(30,092)	(255,143)	(140,204)
Net income (loss)									235,622	175,194	312,899
Comprehensive income (loss)									182,702	184,624	306,453
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Non-utility expense and other									(1,345)	(1,466)	(5,252)
Equity In Net Income (Loss) Of Subsidiaries									320,122	323,568	385,838
Non-hedged interest rate swap expense									0	28	(1,062)
Interest income									4,273	1,039	2
Interest expense									(108,816)	(106,072)	(104,600)
Income taxes									21,388	(41,903)	37,973
Net income (loss)	$ 107,053	$ (21,970)	$ 3,642	$ 146,897	$ (467)	$ 12,836	$ 35,275	$ 127,550	235,622	175,194	312,899
Comprehensive income (loss)									$ 182,702	$ 184,624	$ 306,453

SCHEDULE I CONDENSED FINANCIA_3

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Feb. 06, 2009
Other property and investments:
Goodwill	$ 1,656,513	$ 1,656,513			$ 1,700,000
Current assets:
Cash and Cash Equivalents, at Carrying Value	37,521	26,616
Total current assets	857,376	813,418
Long-term assets:
Other	77,523	74,389
Total assets	14,098,861	13,690,789
Capitalization and liabilities:
Common equity	3,860,758	3,750,030	$ 3,688,713	$ 3,531,225
Long-term debt	1,961,900	1,902,600
Total capitalization	9,533,249	9,007,959
Current liabilities:
Accounts payable	480,069	359,586
Interest	70,099	73,564
Deferred income taxes	789,297	746,868
Unrealized loss on derivative instruments	46,661	64,859
Total current liabilities	1,226,882	1,297,659
Long-term liabilities:
Unrealized loss on derivative instruments	11,095	21,235
Total capitalization and liabilities	14,098,861	13,690,789
Parent Company [Member]
Assets:
Investments in subsidiaries	3,820,347	3,721,553
Other property and investments:
Goodwill	1,656,513	1,656,513
Current assets:
Cash and Cash Equivalents, at Carrying Value	2,067	751
Receivables from affiliates	138,714	78,570
Total current assets	140,781	79,321
Long-term assets:
Deferred income taxes	221,660	208,889
Other	2,040	3,196
Total long-term assets	223,700	212,085
Total assets	5,841,341	5,669,472
Capitalization and liabilities:
Common equity	3,860,728	3,750,030
Long-term debt	1,954,205	1,892,672
Total capitalization	5,814,933	5,642,702
Current liabilities:
Accounts payable	260	1,042
Interest	26,148	25,728
Total current liabilities	26,408	26,770
Long-term liabilities:
Total long-term liabilities	0	0
Total capitalization and liabilities	$ 5,841,341	$ 5,669,472

SCHEDULE I CONDENSED FINANCIA_4

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Statements of Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Net cash provided by (used in) operating activities	$ 904,181	$ 972,131	$ 729,290
Investing activities:
Other	2,097	(195)	(1,921)
Net cash provided by (used in) investing activities	(1,070,573)	(1,040,330)	(708,365)
Financing activities:
Dividends paid	(77,204)	(123,307)	(148,965)
Proceeds from long-term debt and bonds issued	804,050	90,120	12,481
Issuance/redemption of term-loan and other long-term debt	(600,000)	0	0
Net cash provided by (used in) financing activities	185,193	63,664	(30,072)
Net increase (decrease) in cash, cash equivalents, and restricted cash	18,801	(4,535)	(9,147)
Cash, cash equivalents, and restricted cash at end of period	37,521	26,616
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	55,562	36,761	41,296	$ 50,443
Parent Company [Member]
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Net cash provided by (used in) operating activities	79,176	139,005	145,719
Investing activities:
Adjustments to Additional Paid in Capital, Other	0	(24,222)	0
(Increase) decrease in loan to subsidiary	(59,864)	(78,155)	0
Other	0	(437)	(6,078)
Net cash provided by (used in) investing activities	(59,864)	(102,814)	(6,078)
Financing activities:
Dividends paid	(77,204)	(123,307)	(148,965)
Proceeds from long-term debt and bonds issued	209,300	0	0
Issuance/redemption of term-loan and other long-term debt	(150,000)	90,120	12,480
Issue costs and others	(92)	(2,650)	(3,398)
Net cash provided by (used in) financing activities	(17,996)	(35,837)	(139,883)
Net increase (decrease) in cash, cash equivalents, and restricted cash	1,316	354	(242)
Cash, cash equivalents, and restricted cash at end of period	2,067	751
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 2,067	$ 751	$ 397	$ 639

SCHEDULE I CONDENSED FINANCIA_5

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY Notes (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Net income									$ 235,622	$ 175,194	$ 312,899
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									182,702	184,624	306,453
Net Cash Provided by (Used in) Operating Activities									904,181	972,131	729,290
Net Cash Provided by (Used in) Investing Activities									(1,070,573)	(1,040,330)	(708,365)
Parent Company [Member]
Net income	$ 107,053	$ (21,970)	$ 3,642	$ 146,897	$ (467)	$ 12,836	$ 35,275	$ 127,550	235,622	175,194	312,899
Goodwill, Purchase Accounting Adjustments									4,700	3,900	5,200
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									182,702	184,624	306,453
Net Cash Provided by (Used in) Operating Activities									79,176	139,005	145,719
Net Cash Provided by (Used in) Investing Activities									(59,864)	(102,814)	(6,078)
Subsidiaries [Member]
Net income	$ 123,456	$ 3,891	$ 26,778	$ 163,037	$ 97,208	$ 29,100	$ 50,654	$ 143,092	317,162	320,054	380,581
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									253,184	338,659	384,620
Net Cash Provided by (Used in) Operating Activities									995,904	1,086,803	818,916
Net Cash Provided by (Used in) Investing Activities									$ (1,008,409)	$ (963,411)	$ (676,956)

SCHEDULE II VALUATION AND QUA_2

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) - Allowance for doubtful accounts receivable - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance At Beginning of Period	$ 8,901	$ 9,798	$ 9,756
Additions Charged to Costs and Expenses	24,846	26,266	24,389
Deductions	25,339	27,163	24,347
Balance At End Of Period	$ 8,408	$ 8,901	$ 9,798