Puget Sound Energy 10-K 2 Mar 18 2017 FY Annual report Financial data

Document And Entity Information

Document And Entity Information	12 Months Ended
	Dec. 31, 2017shares	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	2,017
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
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	2,017
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating revenue:
Electric	$ 2,420,663	$ 2,238,492	$ 2,128,468
Natural gas	997,759	890,510	947,549
Other	41,854	35,299	16,683
Total operating revenue	3,460,276	3,164,301	3,092,700
Energy costs:
Purchased electricity	590,030	531,596	499,522
Electric generation fuel	206,275	215,331	249,907
Residential exchange	(75,933)	(69,824)	(112,473)
Purchased natural gas	360,009	313,954	403,310
Unrealized (gain) loss on derivative instruments, net	30,790	(83,795)	(13,233)
Utility operations and maintenance	584,263	568,492	530,720
Non-utility expense and other	40,487	27,151	10,818
Depreciation and amortization	481,969	439,579	420,807
Conservation amortization	121,216	107,784	110,866
Taxes other than income taxes	360,673	328,649	320,531
Total operating expenses	2,699,779	2,378,917	2,420,775
Operating income (loss)	760,497	785,384	671,925
Other income (deductions):
Other income	27,892	25,539	20,711
Other expense	(14,104)	(10,923)	(6,764)
Non-hedged interest rate swap expense	28	(1,062)	(3,796)
Interest charges:
AFUDC	10,826	9,304	7,575
Interest expense	(354,802)	(355,139)	(356,696)
Income (loss) before income taxes	430,337	453,103	332,955
Income tax (benefit) expense	255,143	140,204	91,776
Net income (loss)	175,194	312,899	241,179
Subsidiaries [Member]
Operating revenue:
Electric	2,420,663	2,238,492	2,128,468
Natural gas	997,759	890,510	947,549
Other	41,854	35,616	17,241
Total operating revenue	3,460,276	3,164,618	3,093,258
Energy costs:
Purchased electricity	590,030	531,596	499,522
Electric generation fuel	206,275	215,331	249,907
Residential exchange	(75,933)	(69,824)	(112,473)
Purchased natural gas	360,009	313,954	403,310
Unrealized (gain) loss on derivative instruments, net	30,790	(83,795)	(12,688)
Utility operations and maintenance	584,263	568,492	530,720
Non-utility expense and other	52,389	37,859	26,618
Depreciation and amortization	481,955	439,579	420,807
Conservation amortization	121,216	107,784	110,866
Taxes other than income taxes	360,673	328,649	320,531
Total operating expenses	2,711,667	2,389,625	2,437,120
Operating income (loss)	748,609	774,993	656,138
Other income (deductions):
Other income	26,853	25,537	20,711
Other expense	(14,104)	(10,923)	(6,764)
Interest charges:
AFUDC	10,826	9,304	7,575
Interest expense	(240,144)	(242,983)	(247,571)
Income (loss) before income taxes	532,040	555,928	430,089
Income tax (benefit) expense	211,986	175,347	125,900
Net income (loss)	$ 320,054	$ 380,581	$ 304,189

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Parent [Line Items]
Net income (loss)	$ 175,194	$ 312,899	$ 241,179
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	9,430	(6,446)	9,444
Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax	0	0	333
Other comprehensive income (loss)	9,430	(6,446)	9,777
Comprehensive income (loss)	184,624	306,453	250,956
Subsidiaries [Member]
Parent [Line Items]
Net income (loss)	320,054	380,581	304,189
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	18,288	3,722	20,404
Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax	0	0	686
Amortization of treasury interest rate swaps to earnings, net of tax	317	317	317
Other comprehensive income (loss)	18,605	4,039	21,407
Comprehensive income (loss)	$ 338,659	$ 384,620	$ 325,596

CONSOLIDATED STATEMENTS OF COM4

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, tax	$ 5,078	$ (3,471)	$ 5,087
Reclassification of net unrealized loss on energy derivative instruments during the period, tax	0	0	179
Subsidiaries [Member]
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, tax	9,848	2,004	10,987
Reclassification of net unrealized loss on energy derivative instruments during the period, tax	0	0	369
Amortization of treasury interest rate swaps to earnings, tax	$ 171	$ 171	$ 171

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Utility Plant [Abstract]
Electric plant	$ 8,135,847	$ 7,673,772
Natural gas plant	3,307,545	3,051,586
Common plant	811,815	594,994
Less: Accumulated depreciation and amortization	(2,428,524)	(2,161,796)
Net utility plant	9,826,683	9,158,556
Other property and investments:
Goodwill	1,656,513	1,656,513
Other property and investments	182,355	106,418
Total other property and investments	1,838,868	1,762,931
Current assets:
Cash and cash equivalents	26,616	28,878
Restricted cash	10,145	12,418
Accounts receivable, net of allowance for doubtful accounts	341,110	329,375
Unbilled revenue	222,186	234,053
Purchased gas adjustment receivable	0	2,785
Materials and supplies, at average cost	107,003	106,378
Fuel and natural gas inventory, at average cost	49,908	58,181
Unrealized gain on derivative instruments	22,247	54,341
Prepaid expense and other	21,996	43,046
Power contract acquisition adjustment gain	12,207	33,413
Total current assets	813,418	902,868
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	0	72,038
Power cost adjustment mechanism	4,576	4,531
Regulatory assets related to power contracts	19,454	22,613
Other regulatory assets	948,532	1,034,348
Unrealized gain on derivative instruments	2,158	8,738
Power contract acquisition adjustment gain	162,711	241,648
Other	74,389	58,109
Total other long-term and regulatory assets	1,211,820	1,442,025
Total assets	13,690,789	13,266,380
Common shareholder’s equity:
Common stock	0	0
Additional paid-in capital	3,308,957	3,308,957
Retained earnings	465,355	413,468
Accumulated other comprehensive income (loss), net of tax	(24,282)	(33,712)
Total common shareholder’s equity	3,750,030	3,688,713
Long-term debt:
First mortgage bonds and senior notes	3,164,412	3,362,000
Pollution control bonds	161,860	161,860
Junior subordinated notes	250,000	250,000
Long-term debt	1,902,600	1,812,480
Debt discount, issuance costs and other	(220,943)	(234,679)
Total long-term debt	5,257,929	5,351,661
Total capitalization	9,007,959	9,040,374
Current liabilities:
Accounts payable	359,586	317,043
Short-term debt	329,463	245,763
Current maturities of long-term debt	200,000	2,412
Purchased gas adjustment payable	16,051	0
Accrued expenses:
Taxes	117,948	111,428
Salaries and wages	53,220	49,749
Interest	73,564	73,610
Unrealized loss on derivative instruments	64,859	44,310
Power Contract Acquisition Adjustment Loss Current	2,762	3,159
Other	80,206	71,996
Total current liabilities	1,297,659	919,470
Other Long-term and regulatory liabilities:
Deferred income taxes	746,868	1,570,931
Unrealized loss on derivative instruments	21,235	16,261
Regulatory liabilities	731,587	654,622
Deferred Tax Liabilities, Regulatory Assets and Liabilities	1,011,626	0
Regulatory Liabilities Related To Power Contracts	174,918	275,061
Power Contract Acquisition Adjustment Loss Non Current	16,693	19,454
Other deferred credits	682,244	770,207
Total other long-term and regulatory liabilities	3,385,171	3,306,536
Commitments and contingencies (Note 15)
Total capitalization and liabilities	13,690,789	13,266,380
Subsidiaries [Member]
Utility Plant [Abstract]
Electric plant	10,232,771	9,813,169
Natural gas plant	3,882,733	3,640,271
Common plant	843,145	632,718
Less: Accumulated depreciation and amortization	(5,131,966)	(4,927,602)
Net utility plant	9,826,683	9,158,556
Other property and investments:
Other property and investments	76,350	77,960
Total other property and investments	76,350	77,960
Current assets:
Cash and cash equivalents	25,864	28,481
Restricted cash	10,145	12,418
Accounts receivable, net of allowance for doubtful accounts	343,546	344,964
Unbilled revenue	222,186	234,053
Purchased gas adjustment receivable	0	2,785
Materials and supplies, at average cost	107,003	106,378
Fuel and natural gas inventory, at average cost	48,585	56,851
Unrealized gain on derivative instruments	22,247	54,341
Prepaid expense and other	21,996	43,046
Total current assets	801,572	883,317
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	0	71,517
Power cost adjustment mechanism	4,576	4,531
Other regulatory assets	948,540	1,034,352
Unrealized gain on derivative instruments	2,158	8,738
Other	71,827	58,109
Total other long-term and regulatory assets	1,027,101	1,177,247
Total assets	11,731,706	11,297,080
Common shareholder’s equity:
Common stock	859	859
Additional paid-in capital	3,275,105	3,275,105
Retained earnings	452,066	359,795
Accumulated other comprehensive income (loss), net of tax	(126,906)	(145,511)
Total common shareholder’s equity	3,601,124	3,490,248
Long-term debt:
First mortgage bonds and senior notes	3,164,412	3,362,000
Pollution control bonds	161,860	161,860
Junior subordinated notes	250,000	250,000
Debt discount, issuance costs and other	(26,361)	(28,974)
Total long-term debt	3,549,911	3,744,886
Total capitalization	7,151,035	7,235,134
Current liabilities:
Accounts payable	359,585	317,043
Short-term debt	329,463	245,763
Current maturities of long-term debt	200,000	2,412
Purchased gas adjustment payable	16,051	0
Accrued expenses:
Taxes	117,063	111,428
Salaries and wages	53,220	49,749
Interest	47,837	48,087
Unrealized loss on derivative instruments	64,859	44,170
Other	80,206	71,996
Total current liabilities	1,268,284	890,648
Other Long-term and regulatory liabilities:
Deferred income taxes	869,473	1,732,390
Unrealized loss on derivative instruments	21,235	16,261
Regulatory liabilities	730,273	653,296
Deferred Tax Liabilities, Regulatory Assets and Liabilities	1,012,260	0
Other deferred credits	679,146	769,351
Total other long-term and regulatory liabilities	3,312,387	3,171,298
Commitments and contingencies (Note 15)
Total capitalization and liabilities	$ 11,731,706	$ 11,297,080

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Assets:
Construction work in progress	$ 495,937	$ 420,278
Current assets:
Allowance for doubtful accounts	$ 8,901	$ 9,798
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	$ 495,937	$ 420,278
Current assets:
Allowance for doubtful accounts	$ 8,901	$ 9,798
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)	Subsidiaries [Member]Financial Support, Capital Contributions [Member]
Balance at Dec. 31, 2014	$ 3,543,328		$ 3,308,957	$ 271,414	$ (37,043)	$ 3,278,729	$ 859	$ 3,246,205	$ 202,622	$ (170,957)
Balance (in shares) at Dec. 31, 2014		200					85,903,791
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	241,179			241,179		304,189			304,189
Common stock dividend paid	(263,059)			(263,059)		(270,233)			(270,233)
Proceeds from Contributed Capital						(28,900)					$ 28,900
Other comprehensive income (loss)	9,777				9,777	21,407				21,407
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	200				85,903,791	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

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities:
Net income (loss)	$ 175,194	$ 312,899	$ 241,179
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	481,969	439,579	420,807
Conservation amortization	121,216	107,784	110,866
Deferred income taxes and tax credits, net	254,524	139,640	91,978
Net unrealized (gain) loss on derivative instruments	30,650	(88,704)	(17,255)
Derivative contracts classified as financing activities due to merger	0	0	8,045
AFUDC - equity	(15,027)	(12,576)	(9,325)
Production tax credits	(53,331)	0	0
Other non-cash	17,568	16,812	16,155
Funding of pension liability	(18,000)	(24,000)	(18,000)
Regulatory assets and liabilities	(88,875)	(153,643)	(156,491)
Other long-term assets and liabilities	(27,411)	16,435	21,729
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	132	(21,763)	(66,703)
Materials and supplies	(625)	(28,134)	4,945
Fuel and natural gas inventory	8,266	473	9,332
Prepayments and other	21,050	(25,927)	4,086
Purchased gas adjustment	18,836	(15,374)	33,662
Accounts payable	26,396	32,465	(48,037)
Taxes payable	6,520	(3,426)	7,072
Other	13,079	36,750	(5,323)
Net cash provided by (used in) operating activities	972,131	729,290	648,722
Investing activities:
Construction expenditures - excluding equity AFUDC	(1,040,135)	(706,444)	(587,225)
Restricted cash	2,273	(4,469)	24,914
Other	(195)	(1,921)	754
Net cash provided by (used in) investing activities	(1,038,057)	(712,834)	(561,557)
Financing activities:
Change in short-term debt, net	83,700	86,759	74,004
Dividends paid	(123,307)	(148,965)	(263,059)
Proceeds from long-term debt and bonds issued	90,120	12,481	825,000
Redemption of bonds and notes	0	0	(711,000)
Derivative contracts classified as financing activities due to merger	0	0	(8,045)
Other	13,151	19,653	902
Net cash provided by (used in) financing activities	63,664	(30,072)	(82,198)
Net increase (decrease) in cash and cash equivalents	(2,262)	(13,616)	4,967
Cash and cash equivalents at beginning of period	28,878	42,494	37,527
Cash and cash equivalents at end of period	26,616	28,878	42,494
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	326,798	329,603	339,866
Cash payments (refunds) for income taxes	1,649	0	2
Accounts payable for capital expenditures eliminated from cash flows	92,959	76,813	51,588
Reclassification of Colstrip from utility plant to a regulatory asset	(49,177)	176,804	0
Reclassification of hydro treasury grants to a regulatory liability	95,935	0	0
Subsidiaries [Member]
Operating activities:
Net income (loss)	320,054	380,581	304,189
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	481,955	439,579	420,807
Conservation amortization	121,216	107,784	110,866
Deferred income taxes and tax credits, net	210,842	174,776	125,900
Net unrealized (gain) loss on derivative instruments	30,790	(83,795)	(12,688)
AFUDC - equity	(15,027)	(12,576)	(9,325)
Production tax credits	(53,331)	0	0
Other non-cash	6,445	5,672	5,512
Funding of pension liability	(18,000)	(24,000)	(18,000)
Regulatory assets and liabilities	(88,875)	(152,786)	(156,491)
Other long-term assets and liabilities	(14,547)	30,235	36,481
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	13,285	(37,385)	(66,547)
Materials and supplies	(625)	(28,134)	4,945
Fuel and natural gas inventory	8,266	473	9,332
Prepayments and other	21,050	(25,927)	4,089
Purchased gas adjustment	18,836	(15,374)	33,662
Accounts payable	26,396	32,465	(48,031)
Taxes payable	5,635	(3,426)	7,072
Other	12,438	30,754	(12,992)
Net cash provided by (used in) operating activities	1,086,803	818,916	738,781
Investing activities:
Construction expenditures - excluding equity AFUDC	(963,652)	(681,112)	(587,225)
Restricted cash	2,273	(4,469)	24,914
Other	241	4,156	6,386
Net cash provided by (used in) investing activities	(961,138)	(681,425)	(555,925)
Financing activities:
Change in short-term debt, net	83,700	86,759	74,004
Dividends paid	(227,783)	(257,364)	(270,233)
Loan from (payment to) parent	0	0	(28,933)
Investment from parent	0	0	28,900
Proceeds from long-term debt and bonds issued	0	0	425,000
Redemption of bonds and notes	0	0	(412,000)
Other	15,801	19,739	4,796
Net cash provided by (used in) financing activities	(128,282)	(150,866)	(178,466)
Net increase (decrease) in cash and cash equivalents	(2,617)	(13,375)	4,390
Cash and cash equivalents at beginning of period	28,481	41,856	37,466
Cash and cash equivalents at end of period	25,864	28,481	41,856
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	224,423	227,668	242,774
Cash payments (refunds) for income taxes	3,058	0	2
Accounts payable for capital expenditures eliminated from cash flows	92,959	76,813	51,588
Reclassification of Colstrip from utility plant to a regulatory asset	(49,177)	176,804	0
Reclassification of hydro treasury grants to a regulatory liability	$ 95,935	$ 0	$ 0

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Basis of Presentation Puget Energy, Inc. (Puget Energy) is an energy services holding company that owns Puget Sound Energy, Inc. (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, named Puget LNG, LLC (Puget LNG), formed in 2016, which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur under PSE and are allocated to Puget LNG are related party transactions by nature. As of December 31, 2017 , Puget LNG has incurred $104.3 million in construction work in progress and operating costs related to Puget LNG’s portion of the Tacoma LNG facility. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company.” The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any ASC 805 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 2.8% , for each of 2017 , 2016 and 2015 ; depreciable natural gas utility plant was 3.4% , for each of 2017 , 2016 and 2015 ; and depreciable common utility plant was 8.3% , 9.7% and 8.5% in 2017 , 2016 and 2015 , 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 remeasured the carrying amount of all its assets and liabilities to fair value, which resulted in recognition of approximately $1.7 billion in goodwill. 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. The goodwill recorded by Puget Energy represents the potential long-term return to the Company’s investors. Goodwill is tested for impairment annually using a qualitative and quantitative test. Management must first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill. If, after assessing the totality of events or circumstances during a qualitative assessment, management determines 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 would entail a full valuation of Puget Energy’s assets and liabilities and comparing the valuation to its carrying amounts, with the aggregate difference indicating the amount of impairment. Goodwill of a reporting unit is required to be tested for impairment on an interim basis if an event occurs or circumstances change that would cause the fair value of a reporting unit to fall below its carrying amount. Puget Energy conducted its annual impairment test in 2017 using an 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 has 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 later during different seasons. LNG will also provide fuel to transportation customers, particularly in the marine market. On January 24, 2018, the Puget Sound Clean Air Agency’s 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 a Supplemental Environmental Impact Statement, 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 the Washington Commission’s order, PSE will be allocated approximately 43.0% of common capital and operating costs, consistent with the regulated portion of Tacoma LNG facility. The remaining 57.0% of common capital and operating costs of the Tacoma LNG facility will be allocated to Puget LNG. For Puget Energy, $104.0 million in construction work in progress related to Puget LNG’s portion of the Tacoma LNG facility is reported in the “Other property and investments” financial statement line item. For PSE, construction work in progress of $87.2 million related to PSE’s portion of the Tacoma LNG facility is reported in the “Utility plant - Natural gas plant” 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 liquefied natural gas (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 3, "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, in accordance with ASC 605, “Revenue Recognition” (ASC 605). 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 $257.1 million , $235.3 million and $234.2 million for 2017 , 2016 and 2015 , 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 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, 2017 and 2016 was $8.9 million and $9.8 million , respectively. Self-Insurance PSE is self-insured for storm damage and environmental contamination 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 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 was 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 charge 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 $2.1 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. Puget Energy and PSE elected to de-designate all energy related derivative contracts previously recorded as cash flow hedges for the purpose of simplifying its financial reporting. The contracts that were de-designated related to physical electric supply contracts and natural gas swap contracts used to fix the price of natural gas for electric generation. For these contracts and for contracts initiated after such date, all mark-to-market adjustments are recognized through earnings. The amount previously recorded in accumulated other comprehensive income (AOCI) is transferred to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if management determines that the forecasted transaction is probable of not occurring. When these contracts are settled, the contract price becomes part of purchased electricity or electric generation fuel which becomes part of PSE’s PCA mechanism and the unrealized gain or loss is listed separately under energy costs, as it represents the non-rate treatment of energy costs. The Company may enter into swap instruments or other financial derivative instruments to manage the interest rate risk associated with its long-term debt financing and debt instruments. As of December 31, 2017 , Puget Energy has interest rate swap contracts outstanding originally related to its long-term debt. For additional information, see Note 9 , "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 10 , "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, 2017
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements	New Accounting Pronouncements Revenue Recognition In May 2014, the FASB issued ASU No. 2014-09, " Revenue from Contracts with Customers (Topic 606) ". Accounting Standards Update (ASU) 2014-09 and the related amendments outline a single comprehensive model for use in accounting for revenue arising from contracts with customers and supersedes 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 standard is effective for the Company beginning January 1, 2018 and allows for two methods of adoption: application of the standard to each prior reporting period presented (full retrospective), or application of a cumulative effect on retained earnings recognized at the date of initial application (modified retrospective method). The Company will adopt the standard using the modified retrospective method. In preparation for adoption of the standard, the Company initiated a project team that met bi-weekly to make key accounting assessments related to the standard, which included the implementation of associated internal controls. As a result of implementation of this standard, the Company has concluded there to be no impact on revenue for contracts with customers open as of January 1, 2018 . The Company's revenue is 93.6% comprised of contracts with customers from rate-regulated sales of electricity and natural gas to retail customers where revenue will continue to be recognized over time as delivered. Pursuant to the new standard, the Company's current presentation of revenue on the income statement will not change; however, enhanced disclosure for revenue from contracts with customers and revenue outside the scope of ASC 606 will be disclosed. Lease Accounting In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" . The FASB issued this ASU and the related amendments 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 Accounting Standards Codification 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. This amendment is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Earlier adoption is permitted for all entities upon issuance. Reporting entities must apply a modified retrospective approach for the adoption of the new standard. The Company will adopt ASU 2016-02 during the first quarter of fiscal year 2019. The Company expects the adoption of the standard will result in recognition of right-of-use assets and liabilities that have not previously been recorded, which will have a material impact on the consolidated balance sheets. For a current breakout of existing operating and capital leases, see Note 8, "Leases" to the consolidated financial statements included in Item 8 of this report. 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 will adopt ASU 2016-15 during the first quarter of fiscal year 2018 and is in the process of evaluating the impact this standard will have on its consolidated statement of cash flows. 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 will adopt ASU 2016-18 during the first quarter of fiscal year 2018 retrospectively to all periods presented 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. Additionally, the Company will disclose the nature of the Company's restricted cash. Retirement Benefits In March 2017, the FASB issued 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. This amendment is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. Early adoption is permitted as of the beginning of an annual period for which financial statements (interim or annual) have not been issued or made available for issuance. The Company will adopt ASU 2017-07 during the first quarter of fiscal year 2018 by applying the amendments related to income statement activity retrospectively, and balance sheet activity prospectively. The Company’s non-service components for the year ended December 31, 2017 , was a credit of $18.4 million for Puget Energy and $4.7 million for PSE. The non-service cost components are in an income position and will be presented in the other income section, upon adoption. 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 Tax Cuts and Jobs Act (TCJA) and will improve the usefulness of information reported to financial statement users. This amendment is 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 will early adopt ASU 2018-02 during the first quarter of fiscal year 2018 through a retrospective reclassification from accumulated other comprehensive income to retained earnings. The Company is still evaluating the impact of the reclassification to retained earnings.

Regulation and Rates

Regulation and Rates	12 Months Ended
	Dec. 31, 2017
Regulated Operations [Abstract]
Regulation and Rates	(3) 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, 2017 and 2016 included the following: Puget Sound Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2017 2016 Storm damage costs electric 4 to 6 years 128,508 122,709 Colstrip 1 & 2 Regulatory Asset N/A 127,627 176,804 Decoupling deferrals and interest 98,769 156,408 Decoupling 24-month revenue reserve — (20,847 ) Total decoupling asset Less than 2 years 98,769 135,561 Chelan PUD contract initiation 13.8 years 98,052 105,140 Environmental remediation (a) 81,550 74,557 Lower Snake River 19.4 years 70,975 74,862 Baker Dam licensing operating and maintenance costs N/A 54,817 61,453 Deferred Washington Commission AFUDC 10 years 50,301 51,404 Unamortized loss on reacquired debt 1 to 28 years 39,674 42,196 Property tax tracker Less than 2 years 36,517 41,949 Energy conservation costs (a) 35,538 41,027 PGA deferral of unrealized losses on derivative instruments N/A 26,030 — White River relicensing and other costs 3 years 19,502 21,627 Generation plant major maintenance, excluding Colstrip 5 to 11 years 17,216 13,178 Mint Farm ownership and operating costs 7.3 years 14,319 16,319 Colstrip major maintenance 1.5 years 8,723 6,589 Snoqualmie licensing operating and maintenance costs N/A 7,341 8,018 Ferndale 1.8 years 7,295 11,274 Colstrip common property 7.4 years 4,618 5,334 PCA mechanism N/A 4,576 4,531 Electron unrecovered loss 1 year 3,786 7,178 Deferred income taxes (d) N/A — 71,517 PGA receivable 1 year — 2,785 Various other regulatory assets (a) 17,382 17,173 Total PSE regulatory assets 953,116 1,113,185 Deferred income taxes (d) N/A (1,012,260 ) — Cost of removal (b) (389,579 ) (369,300 ) Treasury grants 20 years (205,775 ) (133,709 ) Production tax credits (c) (93,616 ) (93,616 ) Decoupling ROR excess earnings (18,400 ) (13,300 ) Decoupling deferrals and interest (7,896 ) (16,448 ) Total decoupling liability Less than 2 years (26,296 ) (29,748 ) PGA payable 1 year (16,051 ) — Summit purchase option buy-out 2.8 years (4,463 ) (6,038 ) PGA deferral of unrealized gains on derivative instruments N/A — (7,517 ) Various other regulatory liabilities (a) (10,544 ) (13,368 ) Total PSE regulatory liabilities (1,758,584 ) (653,296 ) PSE net regulatory assets (liabilities) $ (805,468 ) $ 459,889 _______________ (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 13,"Income Taxes" to the consolidated financial statements included in Item 8 of this report. Puget Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2017 2016 Total PSE regulatory assets (a) $ 953,116 $ 1,113,185 Puget Energy acquisition adjustments: Regulatory assets related to power contracts 1 to 20 years 19,454 22,613 Various other regulatory assets Varies (8 ) 517 Total Puget Energy regulatory assets 972,562 1,136,315 Total PSE regulatory liabilities (a) (1,758,584 ) (653,296 ) Puget Energy acquisition adjustments: Deferred income taxes 634 — Regulatory liabilities related to power contracts 1 to 35 years (174,918 ) (275,061 ) Various other regulatory liabilities Varies (1,314 ) (1,326 ) Total Puget Energy regulatory liabilities (1,934,182 ) (929,683 ) Puget Energy net regulatory asset (liabilities) $ (961,620 ) $ 206,632 _______________ (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 $389.6 million and $369.3 million in 2017 and 2016 , respectively, for the cost of removal of utility plant. These amounts are collected from PSE’s customers through depreciation rates. General Rate Case Filing On January 13, 2017, PSE filed its GRC with the Washington Commission, which proposed a weighted cost of capital of 7.74% , or 6.69% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.8% . The requested combined electric tariff changes would result in a net increase of $86.3 million or 4.1% , annually. The requested combined natural gas tariff changes would result in a net decrease of $22.3 million , or 2.4% , annually. Additionally, a depreciation study which calculates annual depreciation accruals related to utility plant was filed as part of the GRC filing. The tariffs were subsequently suspended, which means that the final rates authorized in the proceeding would go into effect on or shortly after the suspension date of December 13, 2017. PSE filed a supplemental filing in the GRC on April 3, 2017, which among other things provided updates to power costs. The requested combined electric tariff changes based on the updated supplemental filing would result in a net increase of $67.9 million , or 3.2% , annually. The requested combined natural gas tariff changes based on the updated supplemental filing would result in a net decrease of $29.3 million , or 3.2% , annually. PSE’s GRC filing included the required plan for Colstrip Units 1 and 2 closures, see Note 14, "Litigation" to the consolidated financial statements included in Item 8 of this report. The filing also requested that electric energy supply fixed costs be included in PSE’s decoupling mechanism. Additionally, PSE’s filing contained requests for two new mechanisms to address regulatory lag. PSE requested procedures for an ERF that can be used to update PSE’s delivery revenues on an expedited basis following a GRC proceeding. PSE also requested approval to establish an electric cost recovery mechanism (CRM), similar to its existing natural gas CRM, which would allow PSE to obtain accelerated cost recovery on specified electric reliability projects. On September 15, 2017, ten of the eleven parties to the proceeding, including PSE, filed a multi-party settlement agreement with the Washington Commission. The multi-party settlement resolved some, but not all, contested issues in the case. Hearings were held on August 30, 2017 regarding the contested issues and on September 29, 2017 regarding the multi-party settlement. The settlement agreement was accepted by the Washington Commission on December 5, 2017 and the rates became effective December 19, 2017. The settlement agreement resolved all but four of the contested issues between the settling parties. The settlement agreement provides for a weighted cost of capital of 7.60% 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% , and a combined natural gas tariff change that resulted in a net decrease of $35.5 million , or 3.8% . The expected closure date for Colstrip Units 1 and 2 is July 1, 2022 and the settlement included a plan to cover the costs for the closure of these Units. As part of the settlement PSE committed to fund a Colstrip Community Transition Fund of $10.0 million of which PSE shareholders will fund $5.0 million and $5.0 million will be funded by the regulatory liability for monetized PTCs, which are PTCs used on the filed tax returns. PSE is recognizing the funding of this commitment at the time the PTC’s are accrued for use in the tax return. The settlement provided that the regulatory liability for monetized PTCs will be used for the following Colstrip costs: (i) Colstrip Community Transition Fund, (ii) recover unrecovered Colstrip plant and (iii) recover incurred decommissioning and remediation costs for Colstrip. In addition, the hydro-related treasury grants were allowed to be used to fund and recover incurred decommissioning and remediation costs for Colstrip 1 and 2 as established in RCW 80.04.350. Depreciation rates were updated which increased PSE's depreciation for Colstrip Units 1 and 2. The increase in depreciation caused the Colstrip regulatory asset to be reduced to $127.6 million as of December 31, 2017. Finally, depreciation rates for Colstrip Units 3 and 4 were also updated, which increased PSE's depreciation to recover plant costs for those units based on a negotiated depreciation life ending on December 31, 2027. The contested issues were PSE’s proposed electric CRM, the majority of decoupling issues, certain portions of electric rate spread/rate design issues and the entire natural gas rate spread/rate design-related issues. The Washington Commission also ruled on the remaining contested issues on December 5, 2017. The Washington Commission approved, PSE's proposal to modify its earning sharing mechanism to exclude normalizing adjustments that are required for Commission Basis Reporting purposes under Washington Administrative Code 480-90-257 (natural gas) and 480-100-257 (electric). The Washington Commission rejected PSE’s requested electric CRM. 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. During the rate plan, which ended in December 2017, the allowed decoupling revenue per customer for the recovery of delivery system costs increased by 3.0% for the electric customers and 2.2% for the natural gas customers on January 1. On December 5, 2017, the Washington Commission approved PSE’s request within the 2017 GRC to extend the decoupling mechanism with some changes to the methodology that took effect on December 19, 2017. Electric and natural gas delivery revenues will continue to be recovered on a per customer basis and electric fixed production energy costs will now be decoupled and recovered on a fixed monthly amount basis. The allowed decoupling revenue will no longer increase annually on January 1 for electric and natural gas customers and these amounts can only be changed in a GRC, Power Cost Only Rate Case (PCORC) or ERF filing. Other changes 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 end on the effective date of PSE’s first rate case or other proceeding filed in or after 2021 unless the continuation of the mechanism is approved in either of those proceedings. 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. There is a 3.0% cap for electric and 5.0% cap for natural gas on annual decoupling increases noted above and the size of decoupling deferral assets on the balance sheet, PSE performed an analysis as of December 31, 2017 to determine if electric and natural gas decoupling revenue deferrals would be collected from customers within 24 months of the annual period, per ASC 980-605. If not, for GAAP purposes only, PSE will need to record a reserve against the decoupling revenue and regulatory asset balance. Once the revenue is forecasted to be collected within 24 months, the reserve can be reversed. The analysis indicated all current deferred revenues for electric and natural gas will be collected within 24 months of the annual period; therefore, there were no adjustments to 2017 decoupling revenues other than to record the previously unrecognized decoupling deferrals of $20.8 million . 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 IEEE outage criteria for system average interruption duration index. In 2017 and 2016 , PSE incurred $30.4 million and $22.0 million , respectively, in storm-related electric transmission and distribution system restoration costs, of which $21.6 million was deferred in 2017 and $12.4 million was deferred in 2016 . 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. Washington Commission Tax Deferral Filing The TCJA was signed into law in December of 2017. As a result of this change, PSE reviewed its deferred tax balances under the new corporate tax rate. As PSE is a regulated utility, the impact of tax rate changes on the deferred tax balance is subject to approval by the Washington Commission. Accordingly, PSE filed an accounting petition on December 29, 2017 requesting deferred accounting treatment for the impacts of tax reform. The 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. The tax rate change for certain deferred tax balances that are not subject to regulatory treatment have been recorded through tax expense. 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 $38.9 million for natural gas and $8.9 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, 2017 , the Company’s share of future remediation costs is estimated to be approximately $28.6 million . The Company's deferred electric environmental costs are $17.6 million , $13.8 million and $14.0 million at December 31, 2017 , 2016 and 2015 , respectively, net of insurance proceeds. The Company's deferred natural gas environmental costs are $63.9 million , $60.7 million , and $52.9 million at December 31, 2017 , 2016 and 2015 , 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, 2017
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, 2017 , approximately $645.1 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant. Pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciation and amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3.0 to 1.0 . The common equity ratio, calculated on a regulatory basis, was 48.0% at December 31, 2017 , and the EBITDA to interest expense was 5.5 to 1.0 for the twelve months ended December 31, 2017 . 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, 2017 . At December 31, 2017 , 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, 2017
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) 2017 2016 2017 2016 Distribution plant 20-65 $ 5,670,351 $ 5,287,542 $ 7,289,998 $ 6,922,176 Production plant 12-90 3,068,135 3,007,546 3,954,057 3,910,129 Transmission plant 43-75 1,361,495 1,307,687 1,471,337 1,420,334 General plant 5-75 586,226 541,424 628,179 611,237 Intangible plant (including capitalized software) NA 447,568 347,697 438,185 338,327 Plant acquisition adjustment NA 242,826 242,826 282,792 282,792 Underground storage 25-60 31,815 30,695 45,288 44,206 Liquefied natural gas storage 25-60 12,628 12,628 14,498 14,498 Plant held for future use NA 53,428 52,484 53,580 52,636 Recoverable Cushion Gas NA 8,655 8,655 8,655 8,655 Plant not classified 1-125 275,014 159,345 275,014 159,345 Grant NA — (99,100 ) — (99,100 ) Capital leases, net of accumulated amortization 1 4-6 1,129 645 1,129 645 Less: accumulated provision for depreciation (2,428,524 ) (2,161,796 ) (5,131,966 ) (4,927,602 ) Subtotal $ 9,330,746 $ 8,738,278 $ 9,330,746 $ 8,738,278 Construction work in progress NA 495,937 420,278 495,937 420,278 Net utility plant $ 9,826,683 $ 9,158,556 $ 9,826,683 $ 9,158,556 _______________ 1 Accumulated amortization of capital leases at Puget Energy and PSE was $0.7 million in 2017 and $0.6 million in 2016 . 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, 2017 . 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% $ 246,510 $ (23 ) $ (38,170 ) Colstrip Units 3 & 4 Coal 25.0% 307,254 1,726 (71,061 ) Colstrip Units 1 – 4 Common Facilities Coal various 83 — (31 ) Frederickson 1 Natural Gas 49.85% 61,783 — (3,850 ) Jackson Prairie Natural Gas Storage 33.34% 31,141 43 (6,325 ) 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 Coal 50.0% $ 378,574 $ (23 ) $ (170,234 ) Colstrip Units 3 & 4 Coal 25.0% 571,604 1,726 (335,414 ) Colstrip Units 1 – 4 Common Facilities Coal various 252 — (199 ) Frederickson 1 Natural Gas 49.85% 67,851 — (9,917 ) Jackson Prairie Natural Gas Storage 33.34% 45,288 43 (20,471 ) Tacoma LNG LNG 43.0% 2,667 87,207 — 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. Due to the updated Colstrip information, additional disposal costs were added to the ARO. On September 6, 2016, PSE entered into two new agreements requiring the Company to close the Colstrip 1 and 2 plants on or before July 1, 2022 and to incur additional monitoring costs, water treatment costs, forced evaporation cost, and post closure care costs for all Colstrip Units. As a result, in 2016 the Company adjusted the Colstrip ARO ending liability to increase by $45.7 million for Colstrip 1 and 2 and $37.0 million for Colstrip 3 and 4. 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, 2017 the Company reviewed the estimated remediation costs at Colstrip and reduced the Colstrip ARO liability by $5.5 million for Colstrip Units 1 and 2 and $12.7 million for Colstrip Units 3 and 4. The Company also recorded the Colstrip relief of liability of $3.8 million . In addition, the Company recorded a new 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, 2017 : Puget Energy and At December 31, (Dollars in Thousands) 2017 2016 Asset retirement obligation at beginning of the period $ 200,345 $ 85,028 New asset retirement obligation recognized in the period 1 2,881 — Liability adjustments (3,841 ) (411 ) Revisions in estimated cash flows (13,748 ) 113,081 Accretion expense 5,539 2,647 Asset retirement obligation at end of period 1 $ 191,176 $ 200,345 _______________ 1 New asset retirement obligations include $2.2 million ARO for Puget LNG only held at Puget Energy. 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, 2017 due to: • 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, 2017
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 2017 and 2016 : (Dollars in Thousands) At December 31, Series Type Due 2017 2016 Puget Sound Energy: 6.740% Senior Secured Note 1 2018 $ 200,000 $ 200,000 5.500% Promissory Note 2 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 4.700% Senior Secured Note 2051 45,000 45,000 6.974% Junior Subordinated Note 2067 250,000 250,000 * Debt discount, issuance cost and other * (26,361 ) (28,974 ) Total PSE long-term debt 3,749,911 3,747,298 Puget Energy: * Fair value adjustment of PSE long-term debt * (190,895 ) (199,436 ) * Revolving Credit Agreement 2022 102,600 12,480 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 * (3,687 ) (6,269 ) Total Puget Energy long-term debt $ 5,457,929 $ 5,354,073 _______________ * Not Applicable. 1 6.74% Senior Secured Note in the amount of $200.0 million is classified on the Balance Sheet as a current maturity of long-term debt as of June 15, 2017. 2 5.50% Promissory Note (Puget Western Note Payable) in the amount of $2.4 million was classified on the Balance Sheet as a current maturity of long-term debt from January 1, 2017 to August 13, 2017, at which time the agreement was amended and extended until August 13, 2020. The Promissory Note is currently classified as long-term debt on the Balance sheet as of September 1, 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, 2017 , the latest maturity date of the first mortgage bonds, other than pledged first mortgage bonds, is December 22, 2025. 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 $800.0 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, 2017 , the earnings available for interest exceeded the required amount. 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) 2018 2019 2020 2021 2022 Thereafter Total Maturities of: PSE $ 200,000 $ — $ 2,412 $ — $ — $ 3,573,860 $ 3,776,272 Puget Energy — — 450,000 500,000 552,600 400,000 1,902,600 Total long-term debt $ 200,000 $ — $ 452,412 $ 500,000 $ 552,600 $ 3,973,860 $ 5,678,872

Liquidity Facilities and Other

Liquidity Facilities and Other Financing Arrangements	12 Months Ended
	Dec. 31, 2017
Liquidity Facilities and Other Financing Arrangements [Abstract]
Liquidity Facilities and Other Financing Arrangements	Liquidity Facilities and Other Financing Arrangements As of December 31, 2017 and 2016 , PSE had $329.5 million and $245.8 million in short-term debt outstanding, respectively. Outside of the consolidation of PSE’s short-term debt, Puget Energy had no short-term debt outstanding in either year as borrowings under its credit facility are classified as long-term. PSE’s weighted-average interest rate on short-term debt, including borrowing rate, commitment fees and the amortization of debt issuance costs, during 2017 and 2016 was 3.5% and 3.2% , respectively. As of December 31, 2017 , 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, 2017 , 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, 2017 , no amounts were drawn and outstanding under PSE's credit facility. No letters of credit were outstanding and $329.5 million was outstanding under the commercial paper program. Outside of the credit agreement, PSE had a $3.1 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, 2017 , 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, 2017 , there was $102.6 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, 2017 , Puget Energy was in compliance with all applicable covenants.

Leases

Leases	12 Months Ended
	Dec. 31, 2017
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 2017 , 2016 and 2015 . Operating lease expenses net of sublease receipts were: (Dollars in Thousands) At December 31, Operating Lease Expense Years 2017 $ 35,198 2016 31,786 2015 27,843 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 2018 $ 21,371 $ 527 2019 19,077 306 2020 17,507 232 2021 9,137 97 2022 6,747 — Thereafter 97,974 — Total minimum lease payments $ 171,813 $ 1,162

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2017
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. In November 2017, PSE implemented a risk-responsive component to its hedging strategy for the core natural gas portfolio. This strategy 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. As of December 31, 2017 , the Company did not have any outstanding interest rate swap instruments. 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 2017 2016 2017 2016 2017 2016 Interest rate swap derivatives 3 $0.0 $450.0 $ — $ — $ — $ 141 Electric portfolio derivatives * * 13,391 36,460 49,050 41,329 Natural gas derivatives (MMBtus) 4 332.1 336.4 11,014 26,619 37,044 19,101 Total derivative contracts $ 24,405 $ 63,079 $ 86,094 $ 60,571 Current $ 22,247 $ 54,341 $ 64,859 $ 44,310 Long-term 2,158 8,738 21,235 16,261 Total derivative contracts $ 24,405 $ 63,079 $ 86,094 $ 60,571 _______________ 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 Interest rate swap contracts are only held at Puget Energy and matured in January 2017. 4 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 166.8 million One Million British Thermal Units (MMBtus) and purchased electricity of 2.9 million megawatt hours (MWhs) at December 31, 2017 and 186.8 million MMBtus and 3.6 million MWhs at December 31, 2016 . 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 10, "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, 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 Puget Energy and Puget Sound Energy At December 31, 2016 (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 $ 63,079 $ — $ 63,079 $ (42,858 ) $ — $ 20,221 Liabilities: Energy derivative contracts 60,430 — 60,430 (42,858 ) — 17,572 Interest rate swaps 2 141 — 141 — — 141 _______________ 1 All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of set-off. 2 Interest Rate Swap Contracts are only held at Puget Energy and matured in January 2017. 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 Year Ended December 31, (Dollars in Thousands) Location 2017 2016 2015 Interest rate contracts: Non-hedged interest rate swap (expense) income $ 28 $ (1,062 ) $ (3,796 ) Interest expense — — 560 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net (32,492 ) 62,318 (9,315 ) Realized Electric generation fuel (23,195 ) (39,656 ) (44,648 ) Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 1 1,702 21,477 22,548 Realized Purchased electricity (17,873 ) (21,998 ) (39,137 ) Total gain (loss) recognized in income on derivatives $ (71,830 ) $ 21,079 $ (73,788 ) Puget Sound Energy Year Ended December 31, (Dollars in Thousands) Location 2017 2016 2015 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net $ (32,492 ) $ 62,318 $ (9,315 ) Realized Electric generation fuel (23,195 ) (39,656 ) (44,648 ) Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 1 1,702 21,477 22,003 Realized Purchased electricity (17,873 ) (21,998 ) (39,137 ) Total gain (loss) recognized in income on derivatives $ (71,858 ) $ 22,141 $ (71,097 ) _______________ 1 Differences between Puget Energy and PSE for the twelve months ended December 31, 2015 are due to certain derivative contracts recorded at fair value in 2009 and subsequently designated as NPNS or cash flow hedges. These differences occurred through February 2015. The Company is exposed to credit risk primarily through buying and selling electricity and natural gas to serve its customers. Credit risk is the potential loss resulting from a counterparty's non-performance under an agreement. The Company manages credit risk with policies and procedures for, among other things, counterparty credit analysis, exposure measurement, and exposure monitoring and mitigation. The Company monitors counterparties for significant swings in credit default swap rates, credit rating changes by external rating agencies, ownership changes or financial distress. Where deemed appropriate, the Company may request collateral or other security from its counterparties to mitigate potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of December 31, 2017 , approximately 99.5% 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 0.5% 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, 2017 , 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. In March 2017, PSE began transacting power futures contracts on the Intercontinental Exchange (ICE) platform. Execution of these contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of December 31, 2017 , PSE had cash posted as collateral of $2.6 million related to contracts executed on this platform. Also, as of December 31, 2017 , PSE has a $1.0 million letter of credit posted as collateral as a condition of transacting on a physical energy exchange and clearinghouse in Canada. PSE did not trigger any collateral requirements with any of its counterparties during the twelve months ended December 31, 2017 , 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) 2017 2016 Contingent Feature Fair Value 1 Liability Posted Collateral Contingent Collateral Fair Value 1 Liability Posted Collateral Contingent Collateral Credit rating 2 $ 3,187 $ — $ 3,187 $ 4,894 $ — $ 4,894 Requested credit for adequate assurance 37,374 — — 7,427 — — Forward value of contract 3 353 2,639 — 507 — — Total $ 40,914 $ 2,639 $ 3,187 $ 12,828 $ — $ 4,894 _______________ 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, 2017
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 $48.5 million and $49.1 million at December 31, 2017 and 2016 , 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, 2017 At December 31, 2016 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 238,935 $ 250,000 $ 210,261 Long-term debt (fixed-rate), net of discount 1 2 5,105,329 6,520,515 5,091,593 6,337,287 Long-term debt (variable-rate) 2 102,600 102,600 12,480 12,480 Total $ 5,457,929 $ 6,862,050 $ 5,354,073 $ 6,560,028 Puget Sound Energy At December 31, 2017 At December 31, 2016 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 238,935 $ 250,000 $ 210,261 Long-term debt (fixed-rate), net of discount 2 2 3,499,911 4,550,130 3,497,298 4,360,783 Total $ 3,749,911 $ 4,789,065 $ 3,747,298 $ 4,571,044 _______________ 1 The carrying value includes debt issuances costs of $27.9 million and $33.0 million for December 31, 2017 and 2016 , respectively, which are not included in fair value. 2 The carrying value includes debt issuances costs of $24.6 million and $27.2 million for December 31, 2017 and 2016 , 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, 2017 At December 31, 2016 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 9,866 $ 3,525 $ 13,391 $ 30,666 $ 5,794 $ 36,460 Natural gas derivative instruments 6,973 4,041 11,014 23,316 3,303 26,619 Total derivative assets $ 16,839 $ 7,566 $ 24,405 $ 53,982 $ 9,097 $ 63,079 Liabilities: Interest rate derivative instruments 1 $ — $ — $ — $ 141 $ — $ 141 Electric derivative instruments 46,623 2,427 49,050 36,507 4,822 41,329 Natural gas derivative instruments 34,926 2,118 37,044 16,423 2,678 19,101 Total derivative liabilities $ 81,549 $ 4,545 $ 86,094 $ 53,071 $ 7,500 $ 60,571 _______________ 1 Interest rate derivative instruments are only held at Puget Energy, and matured January 2017. Puget Energy and Puget Sound Energy Year Ended December 31, Level 3 Roll-Forward Net (Liability) 2017 2016 2015 (Dollars in Thousands) Electric Gas Total Electric Gas Total Electric Gas Total Balance at beginning of period $ 972 $ 625 $ 1,597 $ (7,345 ) $ (2,383 ) $ (9,728 ) $ (12,062 ) $ (2,040 ) $ (14,102 ) Changes during period Realized and unrealized energy derivatives: Included in earnings 1 2,781 — 2,781 4,007 — 4,007 (6,432 ) — (6,432 ) Included in regulatory assets / liabilities — 6,346 6,346 — 4,312 4,312 — 3,695 3,695 Settlements 2 (6,549 ) (6,372 ) (12,921 ) (1,129 ) (2,679 ) (3,808 ) 902 (3,885 ) (2,983 ) Transferred into Level 3 523 (553 ) (30 ) (3,021 ) — (3,021 ) (787 ) — (787 ) Transferred out Level 3 3,371 1,877 5,248 8,460 1,375 9,835 11,034 (153 ) 10,881 Balance at end of period $ 1,098 $ 1,923 $ 3,021 $ 972 $ 625 $ 1,597 $ (7,345 ) $ (2,383 ) $ (9,728 ) _______________ 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 $1.5 million , $2.0 million and $(7.4) million for the years ended December 31, 2017 , 2016 and 2015 , 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, 2017 , 2016 and 2015 . 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, 2017 : Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $3,525 $2,427 Discounted cash flow Power Prices (per MWh) $7.02 $28.94 $18.61 Natural gas $4,041 $2,118 Discounted cash flow Natural Gas Prices (per MMBtu) $1.22 $2.80 $1.54 _______________ 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, 2017 , 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 $0.9 million . Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis Puget Energy records the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle. ASC 360 requires long-lived assets to be tested for impairment on an annual basis, and upon the occurrence of any events or circumstances that would be more likely than not to reduce the fair value of the long-lived assets below their carrying value. One such triggering event is a significant decrease in the forward market prices of power. During 2017 and 2016 , Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. In 2017 and 2016 , due to continued 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 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 September 30, 2016 Priest Rapids RP $ 18,969 $ 6,191 $ 12,778 March 31, 2016 Wells Hydro 25,193 19,855 5,338 Total 2016 Impairments $ 18,116 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 2017 and 2016 : Puget Energy Valuation Date Contract Unobservable Input Low High Average 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 September 30, 2016 Priest Rapids RP Power prices (per MWh) 24.24 58.96 39.31 Power contract costs per year (in thousands) 618 4,633 2,472 March 31, 2016 Wells Hydro Power prices (per MWh) 9.46 25.96 21.38 Power contract costs per quarter (in thousands) 4,100 4,659 4,452

Employee Investment Plans

Employee Investment Plans	12 Months Ended
	Dec. 31, 2017
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 $19.2 million , $17.2 million and $16.1 million for the years 2017 , 2016 and 2015 , 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, 2017
Retirement Benefits [Abstract]
Retirement Benefits	Retirement Benefits PSE has a defined benefit pension plan (Qualified Pension Benefits) covering the largest portion 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 non-represented and UA-represented employees, along with IBEW-represented employees hired on or after December 12, 2014 who elect to accumulate the Company contribution in the cash balance formula portion of the pension plan, will receive annual pay credits of 4.0% each year. They will also receive interest credits like other participants in the cash balance pension formula of the pension plan, which are at least 1.0% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, he or she will have annuity and lump sum options for distribution. Those who select the lump sum option will receive their current cash balance amount. 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 records purchase accounting adjustments associated with the re-measurement of the retirement plans. 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, 2017 and 2016 : Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Change in benefit obligation: Benefit obligation at beginning of period $ 652,607 $ 643,088 $ 51,734 $ 51,279 $ 11,194 $ 13,946 Service cost 20,081 18,913 913 1,085 72 93 Interest cost 28,373 28,689 2,285 2,325 500 533 Actuarial loss (gain) 40,945 1,545 2,722 106 725 (2,262 ) Benefits paid (40,594 ) (38,730 ) (1,900 ) (3,061 ) (1,137 ) (1,264 ) Medicare part D subsidy received — — — — 100 148 Administrative expense (931 ) (898 ) — — — — Benefit obligation at end of period $ 700,481 $ 652,607 $ 55,754 $ 51,734 $ 11,454 $ 11,194 Puget Energy and Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Change in plan assets: Fair value of plan assets at beginning of period $ 620,260 $ 598,865 $ — $ — $ 7,200 $ 7,203 Actual return on plan assets 107,836 37,022 — — 784 926 Employer contribution 18,000 24,000 1,900 3,061 291 335 Benefits paid (40,594 ) (38,730 ) (1,900 ) (3,061 ) (1,137 ) (1,264 ) Administrative expense (1,142 ) (897 ) — — — — Fair value of plan assets at end of period $ 704,360 $ 620,260 $ — $ — $ 7,138 $ 7,200 Funded status at end of period $ 3,879 $ (32,347 ) $ (55,754 ) $ (51,734 ) $ (4,316 ) $ (3,994 ) Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Amounts recognized in Statement of Financial Position consist of: Noncurrent assets $ 3,879 $ — $ — $ — $ — $ — Current liabilities — — (5,486 ) (1,911 ) (317 ) (325 ) Noncurrent liabilities — (32,347 ) (50,268 ) (49,823 ) (3,999 ) (3,669 ) Net assets (liabilities) $ 3,879 $ (32,347 ) $ (55,754 ) $ (51,734 ) $ (4,316 ) $ (3,994 ) Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets: Projected benefit obligation $ 700,481 $ 652,607 $ 55,754 $ 51,734 $ 11,454 $ 11,194 Accumulated benefit obligation 688,908 641,855 52,681 47,639 11,367 11,092 Fair value of plan assets 704,360 620,260 — — 7,138 7,200 The following tables summarize Puget Energy's and PSE's pension benefit amounts recognized in AOCI for the years ended December 31, 2017 and 2016 : Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 37,693 $ 56,588 $ 10,689 $ 9,043 $ (3,386 ) $ (4,190 ) Prior service cost (credit) (7,843 ) (9,822 ) 204 246 — — Total $ 29,850 $ 46,766 $ 10,893 $ 9,289 $ (3,386 ) $ (4,190 ) Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 185,277 $ 217,143 $ 13,134 $ 11,978 $ (4,901 ) $ (5,994 ) Prior service cost (credit) (6,232 ) (7,806 ) 208 251 — — Total $ 179,045 $ 209,337 $ 13,342 $ 12,229 $ (4,901 ) $ (5,994 ) The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, 2017 , 2016 and 2015 : Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2017 2016 2015 2017 2016 2015 2017 2016 2015 Components of net periodic benefit cost: Service cost $ 20,081 $ 18,913 $ 21,287 $ 913 $ 1,085 $ 1,108 $ 72 $ 93 $ 112 Interest cost 28,373 28,689 28,088 2,285 2,325 2,281 500 533 621 Expected return on plan assets (47,784 ) (46,619 ) (45,038 ) — — — (461 ) (446 ) (531 ) Amortization of prior service cost (credit) (1,980 ) (1,980 ) (1,980 ) 42 42 42 — — — Amortization of net loss (gain) — — 3,887 1,077 911 1,641 (402 ) (386 ) (130 ) Net periodic benefit cost $ (1,310 ) $ (997 ) $ 6,244 $ 4,317 $ 4,363 $ 5,072 $ (291 ) $ (206 ) $ 72 Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2017 2016 2015 2017 2016 2015 2017 2016 2015 Components of net periodic benefit cost: Service cost $ 20,081 $ 18,913 $ 21,287 $ 913 $ 1,085 $ 1,108 $ 72 $ 93 $ 112 Interest cost 28,373 28,689 28,088 2,285 2,325 2,281 500 533 621 Expected return on plan assets (47,862 ) (46,814 ) (45,462 ) — — — (461 ) (446 ) (531 ) Amortization of prior service cost (credit) (1,573 ) (1,573 ) (1,573 ) 44 44 44 — — 3 Amortization of net loss (gain) 13,048 15,257 20,555 1,565 1,330 2,120 (641 ) (632 ) (406 ) Net periodic benefit cost $ 12,067 $ 14,472 $ 22,895 $ 4,807 $ 4,784 $ 5,553 $ (530 ) $ (452 ) $ (201 ) The following tables summarize Puget Energy's and PSE's benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, 2017 and 2016 : Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ (18,896 ) $ 11,141 $ 2,722 $ 106 $ 403 $ (2,742 ) Amortization of net (loss) gain — — (1,076 ) (910 ) 401 385 Amortization of prior service (cost) credit 1,980 1,980 (42 ) (42 ) — — Total change in other comprehensive income for year $ (16,916 ) $ 13,121 $ 1,604 $ (846 ) $ 804 $ (2,357 ) Puget Sound Energy Qualified Pension Benefit SERP Pension Benefits Other Benefits (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ (18,817 ) $ 11,336 $ 2,722 $ 106 $ 452 $ (2,742 ) Amortization of net (loss) gain (13,048 ) (15,257 ) (1,565 ) (1,330 ) 641 631 Amortization of prior service (cost) credit 1,573 1,573 (44 ) (44 ) — — Total change in other comprehensive income for year $ (30,292 ) $ (2,348 ) $ 1,113 $ (1,268 ) $ 1,093 $ (2,111 ) The estimated net (loss) gain and prior service cost (credit) for the pension plans that will be amortized from Accumulated Other Comprehensive Income (AOCI) into net periodic benefit cost in 2018 by PSE are $(14.5) million and $1.6 million , respectively. The estimated net (loss) gain for the SERP that will be amortized from AOCI into net periodic benefit cost in 2018 is $(2.1) million . The estimated prior service cost (credit) for the SERP that will be amortized from AOCI into net periodic benefit cost in 2018 is immaterial . 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 2018 is $0.6 million . For Puget Energy, the overall amounts expected to be amortized from AOCI into net period benefit cost in 2018 is $(1.1) 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, 2018 are expected to be at least $18.0 million , $5.5 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 2017 2016 2015 2017 2016 2015 2017 2016 2015 Discount rate 4.00 % 4.50 % 4.65 % 4.00 % 4.50 % 4.65 % 4.00 % 4.50 % 4.65 % 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 — — — — — — 6.80 8.80 7.20 Benefit Cost Assumptions Discount rate 4.50 % 4.65 % 4.25 % 4.50 % 4.65 % 4.25 % 4.50 % 4.65 % 4.25 % Return on plan assets 7.45 7.75 7.75 — — — 6.75 6.75 7.00 Rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Medical trend rate — — — — — — 9.50 5.30 7.20 The assumed medical inflation rate used to determine benefit obligations is 6.80% in 2018 grading down to 4.10% in 2019 . A 1.0% change in the assumed medical inflation rate would have the following effects: 2017 2016 (Dollars in Thousands) 1% Increase 1% Decrease 1% Increase 1% Decrease Effect on post-retirement benefit obligation $ 23 $ (22 ) $ 38 $ (35 ) Effect on service and interest cost components 1 (1 ) 2 (2 ) 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) 2018 2019 2020 2021 2022 2023-2027 Qualified Pension total benefits $ 42,600 $ 43,400 $ 44,800 $ 45,700 $ 46,900 $ 246,500 SERP Pension total benefits 5,486 6,001 4,684 1,728 4,577 37,394 Other Benefits total with Medicare Part D subsidy 911 885 852 811 863 3,748 Other Benefits total without Medicare Part D subsidy 1,172 1,155 1,131 1,097 1,070 4,844 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, 2017 and 2016 : Recurring Fair Value Measures Recurring Fair Value Measures As of December 31, 2017 As of December 31, 2016 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual Funds $ 117,796 $ — $ 117,796 $ 181,212 $ — $ 181,212 Common Stock 209,504 — 209,504 154,255 — 154,255 Government Securities 18,316 23,782 42,098 18,754 16,197 34,951 Corporate Bonds — 34,588 34,588 — 38,543 38,543 Cash and cash equivalents 2,684 9,304 11,988 — — — Subtotal $ 348,300 $ 67,674 415,974 $ 354,221 $ 54,740 408,961 Investments measured at NAV 1 237,427 222,819 Net (payable) receivable 50,959 (9,894 ) Total assets $ 704,360 $ 621,886 _______________ 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, 2017 . 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, 2017 As of December 31, 2016 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual fund 1 $ 7,089 $ — $ 7,089 $ 7,182 $ — $ 7,182 Investments measured at NAV 2 49 80 Total assets $ 7,138 $ 7,262 _______________ 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, 2017 . 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, 2017 .

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
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) 2017 2016 2015 Charged to operating expenses: Current: Federal $ 1,127 $ — $ — State 17 20 — Deferred: Federal 254,420 140,315 91,968 State (421 ) (131 ) (192 ) Total income tax expense $ 255,143 $ 140,204 $ 91,776 Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2017 2016 2015 Charged to operating expenses: Current: Federal $ 1,127 $ — $ — State 17 20 — Deferred: Federal 210,842 175,327 125,900 State — — — Total income tax expense $ 211,986 $ 175,347 $ 125,900 The following reconciliation compares pre-tax book income at the federal statutory rate of 35.0% to the actual income tax expense in the Statements of Income: Puget Energy Year Ended December 31, (Dollars in Thousands) 2017 2016 2015 Income taxes at the statutory rate $ 148,847 $ 158,586 $ 116,534 Increase (decrease): Production tax credit 1 — (12,925 ) (19,470 ) Utility plant differences — 3,966 5,671 Treasury grant amortization (9,537 ) (9,788 ) (8,807 ) Tax reform 117,185 — — Other - net (1,352 ) 365 (2,152 ) Total income tax expense $ 255,143 $ 140,204 $ 91,776 Effective tax rate 60.0 % 30.9 % 27.6 % Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2017 2016 2015 Income taxes at the statutory rate $ 185,430 $ 194,572 $ 150,531 Increase (decrease): Production tax credit 1 — (12,925 ) (19,470 ) Utility plant differences — 3,966 5,671 Treasury grant amortization (9,537 ) (9,788 ) (8,807 ) Tax reform 36,328 — — Other - net (235 ) (478 ) (2,025 ) Total income tax expense $ 211,986 $ 175,347 $ 125,900 Effective tax rate 40.0 % 31.5 % 29.3 % _______________ 1 PSE's Wild Horse wind plant and Hopkins Ridge wind plant earned their last PTCs in December 2016 and 2015, respectively. No further PTCs are expected. The Company’s net deferred tax liability at December 31, 2017 and 2016 is composed of amounts related to the following types of temporary differences: Puget Energy At December 31, (Dollars in Thousands) 2017 2016 Utility plant and equipment $ 2,034,328 $ 1,880,782 Regulatory asset for income taxes — 72,038 Fair value of debt instruments 38,777 67,444 Pensions and other compensation 46,338 77,230 Other deferred tax liabilities 86,933 119,050 Subtotal deferred tax liabilities 2,206,376 2,216,544 Net operating loss carryforward (212,168 ) (352,827 ) Net regulatory liability for income taxes (1,011,626 ) — Production tax credit carryforward (187,617 ) (190,999 ) Regulatory liability on production tax credit (49,873 ) (101,787 ) Net other deferred tax assets 1,776 — Subtotal deferred tax assets (1,459,508 ) (645,613 ) Total net deferred tax liabilities $ 746,868 $ 1,570,931 Puget Sound Energy At December 31, (Dollars in Thousands) 2017 2016 Utility plant and equipment $ 2,034,328 $ 1,880,782 Regulatory asset for income taxes — 71,517 Other, net deferred tax liabilities 86,933 113,938 Subtotal deferred tax liabilities 2,121,261 2,066,237 Net regulatory liability for income taxes (1,012,260 ) — Net operating loss carryforward — (41,061 ) Production tax credit carryforward (187,617 ) (190,999 ) Regulatory liability on production tax credit (49,873 ) (101,787 ) Net other deferred tax assets (2,038 ) — Subtotal deferred tax assets (1,251,788 ) (333,847 ) Total net deferred tax liabilities $ 869,473 $ 1,732,390 On December 22, 2017 , President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (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% percent to 21.0% percent. 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 September 27, 2017 and continues normalization requirements for accelerated depreciation benefits. For Puget Energy, TCJA provides for full expensing of property acquired after September 27, 2017 and limits a deduction for interest expense to 30.0% percent of adjusted taxable income (which resembles earnings before interest, taxes, depreciation and amortization or “EBITDA”). 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 their 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 the year, 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 which represents the excess deferred taxes that will eventually be refunded to customers. 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 amortized over the remaining lives of the related assets. 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 . The income statement impact for the regulatory deferred tax will come in the future when the Washington Commission issues a final order. The timing for that is unknown but will likely occur in 2018. The impact of the TCJA to income tax expense 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 PTC deferred taxes. The liability owed to customers for PTCs, which previously reduced revenue upon generation of the PTCs, was also revalued at the TCJAs 21 percent rate. The change in the liability owed to customers for PTCs due to TCJA increased revenue by $51.2 million , which increased tax expense by $17.9 million , to reverse the initial deferral. The changes in deferred tax and liability owed to customers for PTCs had no impact on net income. Incrementally, Puget Energy increased their 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) which 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 analyses and accounting (the measurement period). SAB 118 describes three scenarios (or “buckets”) associated with a company’s status of accounting for income tax reform: (1) a company is complete with its accounting for certain effects of tax reform, (2) a company is able to determine a reasonable estimate for certain effects of tax reform and records that estimate as a provisional amount, or (3) a company is not able to determine a reasonable estimate and therefore continues to apply ASC 740, based on the provisions of the tax laws that were in effect immediately prior to the TCJA being enacted. The Company has completed the required analysis and accounting for substantially all the effects of the TCJA's enactment and have made a reasonable estimate as to the other effects, and have reflected the measurement and accounting of the effects in the 2017 consolidated financial statements. The items reflected as provisional amounts include tax depreciation and amortization and other book to tax differences. PSE has accounted for these items based on its interpretation of the TCJA. Further interpretive guidance on the TCJA from the IRS, U.S. Treasury Department, or the Joint Committee on Taxation may require adjustments to PSE's accounting. In accordance with SAB 118, adjustments, if any, will be recorded in 2018 . The Company did not identify any effects on the TCJA for which they were not able to either complete the required analysis or make a reasonable estimate. 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. The Company’s PTC carryforwards expire from 2027 through 2037. The Company’s net operating loss carryforwards expire from 2029 through 2036. No valuation allowance has been provided for PTC or net operating loss carryforwards. The Company accounts for uncertain tax position 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, 2017 and 2016 , 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 2014 through 2017. The Company classifies interest as interest expense and penalties as other expense in the financial statements.

Litigation

Litigation	12 Months Ended
	Dec. 31, 2017
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. On March 6, 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. On July 12, 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 on September 6, 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. As a result, PSE reclassified $176.8 million from a utility plant asset to a regulatory asset, which represents the expected NBV at retirement of Colstrip Units 1 and 2, based on the expected shutdown date of July 1, 2022 as of December 31, 2016. 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 GRC also repurposed PTCs and hydro-related treasury grants to fund and recover decommissioning and remediation costs for Colstrip Units 1 and 2. Colstrip Units 3 and 4, which are newer and more efficient, are not affected by the settlement, and allegations in the lawsuit against Colstrip Units 3 and 4 were dismissed as part of the settlement with the Sierra Club. While PSE has estimated the ARO for Colstrip Units 1 and 2, the full scope of decommissioning activities and costs may vary from the estimates that are available at this time. Greenwood On March 9, 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 on September 20, 2016, seeking up to $3.2 million in fines from PSE. As of September 30, 2016, PSE accrued $3.2 million for the fine. On March 28, 2017, pipeline safety regulators and PSE reached a settlement in response to the complaint. As part of the agreement, PSE agreed to pay a penalty of $2.8 million , of which $1.3 million was suspended on condition that PSE complete a comprehensive inspection and remediation program. On June 19, 2017, the Washington Commission approved the settlement without conditions and adopted the reduced penalty of $2.8 million , of which $1.3 million was suspended. On June 30, 2017, PSE paid the penalty it had previously accrued. However, litigation is still pending regarding damage and personal injury claims. Coal Combustion Residuals On April 17, 2015, the EPA published a final rule, effective October 19, 2015, that regulates CCR's under the Resource Conservation and Recovery Act, Subtitle D. The EPA issued another rule, effective October 4, 2016, extending certain compliance deadlines under the CCR rule. The CCR rule is self-implementing at a federal level or can be taken over by a state. 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 containment structures by establishing technical design, operation and maintenance, closure and post closure care requirements for CCR landfills and surface impoundments, and corrective action requirements for any related leakage. The rule also sets forth recordkeeping and reporting requirements, including posting specific information related to CCR surface impoundments and landfills to publicly-accessible websites. The CCR rule requires significant changes to the Company's Colstrip operations and those changes were reviewed by the Company and the plant operator in the second quarter of 2015. PSE had previously recognized a legal obligation under the EPA rules to dispose of coal ash material at Colstrip in 2003. Due to the CCR rule, additional disposal costs were added to the ARO. 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 on October 23, 2015. The rule was being challenged by other states and parties, and the Supreme Court granted a stay of the rule on February 9, 2016 until the litigation is resolved. On March 31, 2017, the EPA Administrator, Scott Pruitt, signed a notice of withdrawal of the proposed CPP federal plan and model trading rules and, on October 10, 2017, the EPA proposed to repeal the CPP rule and is currently accepting comment on the proposal. PSE is still reviewing the impact of these developments. Washington Clean Air Rule The CAR was adopted on September 15, 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. The CAR covers natural gas distributors and subjects them to an emissions reduction pathway based on the indirect emissions of their customers. The CAR regulates the emissions of natural gas utilities 1.2 million customers across the state, adding to the cost of natural gas for homes and businesses, which may increase costs to PSE customers. On September 27, 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. On September 30, 2016, the four companies filed a similar challenge to the CAR in Thurston County Superior Court. On December 15, 2017, the Thurston County Superior Court invalidated the CAR. A final court order is pending and in the meantime, the Washington State Department of Ecology (WDOE), submitted a brief requesting severability, which would make the rule valid for industries with direct emissions. This would apply to The Company's electric utility thermal generation units but not to its natural gas utility. Appeals could be filed to the Thurston County Court of Appeals after the court's final order, including its ruling on severability. Other Proceedings The Company is also involved in litigation relating to claims arising out of its operations in the normal course of business. The Company has recorded reserves of $2.4 million and $0.7 million relating to these claims as of December 31, 2017 and 2016 , respectively.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies For the year ended December 31, 2017 , approximately 13.3% of the Company’s energy output was obtained at an average cost of approximately $0.022 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 through substantially 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) 2017 2016 2015 PUD contract costs $ 73,827 $ 77,667 $ 72,833 As of December 31, 2017 , 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 2018 Costs 2018 Debt Service Costs Interest included in 2018 Debt Service Costs Debt Outstanding Chelan County PUD: Rock Island Project 2031 25.0 % 156 $ 29,135 $ 10,105 $ 5,354 $ 84,269 Rocky Reach Project 2031 25.0 325 28,800 5,796 2,548 39,563 Douglas County PUD: Wells Project 1 2028 29.9 251 11,002 4,695 1,379 49,629 Grant County PUD: Priest Rapids Development 2052 0.6 6 2,050 1,231 1,231 13,723 Wanapum Development 2052 0.6 7 2,050 1,231 1,231 13,723 Total 745 $ 73,037 $ 23,058 $ 11,743 $ 200,907 _______________ 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) 2018 2019 2020 2021 2022 Thereafter Total Columbia River projects $ 82,200 $ 97,890 $ 95,704 $ 91,862 $ 91,018 $ 708,499 $ 1,167,173 Other utilities 1,257 888 — — — — 2,145 Non-utility contracts 206,233 233,776 238,016 244,962 244,906 1,128,466 2,296,359 Short-term electric supply contracts 70,786 140 — — — — 70,926 Total $ 360,476 $ 332,694 $ 333,720 $ 336,824 $ 335,924 $ 1,836,965 $ 3,536,603 Total purchased power contracts provided the Company with approximately 14.5 million , 13.0 million and 11.2 million MWhs of firm energy at a cost of approximately $456.4 million , $402.5 million and $373.8 million for the years 2017 , 2016 and 2015 , 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 27 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. The Company incurred demand charges for 2017 for firm transportation, storage and peaking services for its natural gas customers of $121.4 million . The Company incurred demand charges in 2017 for firm transportation and storage services for the natural gas supply for its combustion turbines in the amount of $41.8 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) 2018 2019 2020 2021 2022 Thereafter Total Natural gas supply $ 245,669 $ 193,458 $ 163,818 $ 145,662 $ 109,401 $ — $ 858,008 Firm transportation service 154,170 154,204 141,962 126,319 125,335 310,428 1,012,418 Firm storage service 8,328 8,899 7,908 3,108 1,619 857 30,719 Short-term natural gas supply contracts 55,774 13,818 1,651 — — — 71,243 Total $ 463,941 $ 370,379 $ 315,339 $ 275,089 $ 236,355 $ 311,285 $ 1,972,388 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) 2018 2019 2020 2021 2022 Thereafter Total Energy production service contracts $ 28,674 $ 27,939 $ 28,639 $ 29,415 $ 30,142 $ 165,689 $ 310,498 Automated meter reading system 48,245 44,842 43,951 44,497 45,168 187,698 414,401 Total $ 76,919 $ 72,781 $ 72,590 $ 73,912 $ 75,310 $ 353,387 $ 724,899 Other Commitments and Contingencies For information regarding PSE's environmental remediation obligations, see Note 3, "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, 2017
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). Group Health provided coverage to over 600,000 residents in Washington and Northern Idaho. 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 , $23.3 million and $20.3 million for medical coverage for the year ended December 31, 2017 , 2016 and 2015 . Kaiser Permanente is not considered a related party to PSE. Kimberly Harris, the President and Chief Executive Officer and a director of Puget Energy and PSE, is married to Kyle Branum, who as of January 2017 is a partner at Summit Law Group, which provides legal services to PSE. In 2017 Summit Law Group was paid $0.8 million for legal services provided to PSE and Mr. Branum was among the lawyers at Summit Law Group who provided such legal services. This work was performed under the supervision of PSE's General Counsel. Through 2016 , Mr. Branum was a principal at the law firm Riddell Williams P.S., which provided legal services to PSE. In 2016 and 2015 , Riddell Williams was paid $1.0 million and $1.8 million , respectively.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2017
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, 2017
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, 2017 , 2016 and 2015 , 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, 2014 $ (36,710 ) $ (333 ) $ (37,043 ) Other comprehensive income (loss) before reclassifications 7,196 — 7,196 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 2,248 333 2,581 Net current-period other comprehensive income (loss) 9,444 333 9,777 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 ) 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, 2014 $ (164,281 ) $ (686 ) $ (5,990 ) $ (170,957 ) Other comprehensive income (loss) before reclassifications 6,922 — — 6,922 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 13,482 686 317 14,485 Net current-period other comprehensive income (loss) 20,404 686 317 21,407 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 ) Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2017 , 2016 and 2015 , 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) 2017 2016 2015 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,938 $ 1,938 $ 1,938 Amortization of net gain (loss) (a) (675 ) (525 ) (5,397 ) Total before tax 1,263 1,413 (3,459 ) Tax (expense) or benefit (442 ) (495 ) 1,211 Net of Tax 821 918 (2,248 ) Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: Electric derivatives Purchased electricity — — (512 ) Tax (expense) or benefit — — 179 Net of Tax — — (333 ) Total reclassification for the period Net of Tax $ 821 $ 918 $ (2,581 ) _______________ (a) These AOCI components are included in the computation of net periodic pension cost, see Note 12, "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) 2017 2016 2015 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,529 $ 1,529 $ 1,526 Amortization of net gain (loss) (a) (13,972 ) (15,955 ) (22,268 ) Total before tax (12,443 ) (14,426 ) (20,742 ) Tax (expense) or benefit 4,355 5,049 7,260 Net of tax (8,088 ) (9,377 ) (13,482 ) Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: Electric derivatives Purchased electricity — — (1,055 ) Tax (expense) or benefit — — 369 Net of Tax — — (686 ) Net unrealized gain (loss) on treasury interest rate swaps: Interest rate contracts Interest expense (488 ) (488 ) (488 ) Tax (expense) or benefit 171 171 171 Net of Tax (317 ) (317 ) (317 ) Total reclassification for the period Net of Tax $ (8,405 ) $ (9,694 ) $ (14,485 ) _______________ (a) These AOCI components are included in the computation of net periodic pension cost, see Note 12, "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, 2017
Condensed Financial Information of Parent Company Only 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, 2017 2016 2015 Non-utility expense and other $ (1,466 ) $ (5,252 ) $ (1,617 ) Other income (deductions): Equity in earnings of subsidiary 323,568 385,838 309,603 Non-hedged interest rate swap expense 28 (1,062 ) (3,796 ) Interest income 1,039 2 63 Interest expense (106,072 ) (104,600 ) (100,114 ) Income taxes (41,903 ) 37,973 37,040 Net income (loss) 175,194 312,899 241,179 Comprehensive income (loss) $ 184,624 $ 306,453 $ 250,956 See accompanying notes to the condensed financial statements. Puget Energy Condensed Balance Sheets (Dollars in Thousands) December 31, 2017 2016 Assets: Investment in subsidiaries $ 3,721,553 $ 3,571,550 Other property and investments: Goodwill 1,656,513 1,656,513 Current assets: Cash 751 397 Receivables from affiliates 1 78,570 213 Total current assets 79,321 610 Long-term assets: Deferred income taxes 208,889 309,812 Other 3,196 521 Total long-term assets 212,085 310,333 Total assets $ 5,669,472 $ 5,539,006 Capitalization and liabilities: Common equity $ 3,750,030 $ 3,688,713 Long-term debt 1,892,672 1,808,828 Total capitalization 5,642,702 5,497,541 Current liabilities: Account Payable 1,042 15,801 Interest 25,728 25,523 Unrealized loss on derivative instruments — 141 Total current liabilities 26,770 41,465 Long-term liabilities: Total long-term liabilities — — Commitments and contingencies (Note 3) Total capitalization and liabilities $ 5,669,472 $ 5,539,006 _______________ 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, 2017 2016 2015 Operating activities: Net cash provided by (used in) operating activities 139,005 $ 145,719 $ 171,576 Investing activities: Investment in subsidiaries (24,222 ) — (28,900 ) (Increase) decrease in loan to subsidiary (78,155 ) — 28,933 Other (437 ) (6,078 ) (5,632 ) Net cash provided by (used in) investing activities (102,814 ) (6,078 ) (5,599 ) Financing activities: Dividends paid (123,307 ) (148,965 ) (263,059 ) Issuance of bond — — 400,000 Issuance/redemption of term-loan and other long-term debt 90,120 12,480 (299,000 ) Issue costs and others (2,650 ) (3,398 ) (3,341 ) Net cash provided by (used in) by financing activities (35,837 ) (139,883 ) (165,400 ) Increase (decrease) in cash 354 (242 ) 577 Cash at beginning of year 397 639 62 Cash at end of year $ 751 $ 397 $ 639 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 on November 29, 2016, and has the sole purpose of owning, developing and financing the non-regulated activity of a 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 $320.1 million , $380.6 million and $304.2 million for the years ended December 31, 2017 , 2016 and 2015 , respectively, and business combination accounting adjustments under ASC 805 recorded at Puget Energy for PSE of $3.9 million , $5.2 million and $5.4 million for the years ended December 31, 2017 , 2016 and 2015 , 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 6, "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 15, "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, 2017
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, 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 Year Ended December 31, 2015 Accounts deducted from assets on balance sheet: Allowance for doubtful accounts receivable $ 7,472 $ 20,732 $ 18,448 $ 9,756

Summary of Significant Accoun29

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Puget Energy, Inc. (Puget Energy) is an energy services holding company that owns Puget Sound Energy, Inc. (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, named Puget LNG, LLC (Puget LNG), formed in 2016, which has the sole purpose of owning, developing and financing the non-regulated activity of the Tacoma LNG facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur under PSE and are allocated to Puget LNG are related party transactions by nature. As of December 31, 2017 , Puget LNG has incurred $104.3 million in construction work in progress and operating costs related to Puget LNG’s portion of the Tacoma LNG facility. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company.” The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any ASC 805 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 2.8% , for each of 2017 , 2016 and 2015 ; depreciable natural gas utility plant was 3.4% , for each of 2017 , 2016 and 2015 ; and depreciable common utility plant was 8.3% , 9.7% and 8.5% in 2017 , 2016 and 2015 , 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 remeasured the carrying amount of all its assets and liabilities to fair value, which resulted in recognition of approximately $1.7 billion in goodwill. 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. The goodwill recorded by Puget Energy represents the potential long-term return to the Company’s investors. Goodwill is tested for impairment annually using a qualitative and quantitative test. Management must first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill. If, after assessing the totality of events or circumstances during a qualitative assessment, management determines 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 would entail a full valuation of Puget Energy’s assets and liabilities and comparing the valuation to its carrying amounts, with the aggregate difference indicating the amount of impairment. Goodwill of a reporting unit is required to be tested for impairment on an interim basis if an event occurs or circumstances change that would cause the fair value of a reporting unit to fall below its carrying amount. Puget Energy conducted its annual impairment test in 2017 using an 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 has 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 liquefied natural gas (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 3, "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, in accordance with ASC 605, “Revenue Recognition” (ASC 605). 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 $257.1 million , $235.3 million and $234.2 million for 2017 , 2016 and 2015 , 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 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, 2017 and 2016 was $8.9 million and $9.8 million , respectively.
Self Insurance	Self-Insurance PSE is self-insured for storm damage and environmental contamination 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 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 was 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 charge 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 $2.1 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. Puget Energy and PSE elected to de-designate all energy related derivative contracts previously recorded as cash flow hedges for the purpose of simplifying its financial reporting. The contracts that were de-designated related to physical electric supply contracts and natural gas swap contracts used to fix the price of natural gas for electric generation. For these contracts and for contracts initiated after such date, all mark-to-market adjustments are recognized through earnings. The amount previously recorded in accumulated other comprehensive income (AOCI) is transferred to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if management determines that the forecasted transaction is probable of not occurring. When these contracts are settled, the contract price becomes part of purchased electricity or electric generation fuel which becomes part of PSE’s PCA mechanism and the unrealized gain or loss is listed separately under energy costs, as it represents the non-rate treatment of energy costs. The Company may enter into swap instruments or other financial derivative instruments to manage the interest rate risk associated with its long-term debt financing and debt instruments. As of December 31, 2017 , Puget Energy has interest rate swap contracts outstanding originally related to its long-term debt. For additional information, see Note 9 , "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 10 , "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.

Regulation and Rates (Tables)

Regulation and Rates (Tables)	12 Months Ended
	Dec. 31, 2017
Regulation and Rates [Line Items]
Schedule of Net Regulatory Assets and Liabilities	The net regulatory assets and liabilities at December 31, 2017 and 2016 included the following: Puget Sound Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2017 2016 Storm damage costs electric 4 to 6 years 128,508 122,709 Colstrip 1 & 2 Regulatory Asset N/A 127,627 176,804 Decoupling deferrals and interest 98,769 156,408 Decoupling 24-month revenue reserve — (20,847 ) Total decoupling asset Less than 2 years 98,769 135,561 Chelan PUD contract initiation 13.8 years 98,052 105,140 Environmental remediation (a) 81,550 74,557 Lower Snake River 19.4 years 70,975 74,862 Baker Dam licensing operating and maintenance costs N/A 54,817 61,453 Deferred Washington Commission AFUDC 10 years 50,301 51,404 Unamortized loss on reacquired debt 1 to 28 years 39,674 42,196 Property tax tracker Less than 2 years 36,517 41,949 Energy conservation costs (a) 35,538 41,027 PGA deferral of unrealized losses on derivative instruments N/A 26,030 — White River relicensing and other costs 3 years 19,502 21,627 Generation plant major maintenance, excluding Colstrip 5 to 11 years 17,216 13,178 Mint Farm ownership and operating costs 7.3 years 14,319 16,319 Colstrip major maintenance 1.5 years 8,723 6,589 Snoqualmie licensing operating and maintenance costs N/A 7,341 8,018 Ferndale 1.8 years 7,295 11,274 Colstrip common property 7.4 years 4,618 5,334 PCA mechanism N/A 4,576 4,531 Electron unrecovered loss 1 year 3,786 7,178 Deferred income taxes (d) N/A — 71,517 PGA receivable 1 year — 2,785 Various other regulatory assets (a) 17,382 17,173 Total PSE regulatory assets 953,116 1,113,185 Deferred income taxes (d) N/A (1,012,260 ) — Cost of removal (b) (389,579 ) (369,300 ) Treasury grants 20 years (205,775 ) (133,709 ) Production tax credits (c) (93,616 ) (93,616 ) Decoupling ROR excess earnings (18,400 ) (13,300 ) Decoupling deferrals and interest (7,896 ) (16,448 ) Total decoupling liability Less than 2 years (26,296 ) (29,748 ) PGA payable 1 year (16,051 ) — Summit purchase option buy-out 2.8 years (4,463 ) (6,038 ) PGA deferral of unrealized gains on derivative instruments N/A — (7,517 ) Various other regulatory liabilities (a) (10,544 ) (13,368 ) Total PSE regulatory liabilities (1,758,584 ) (653,296 ) PSE net regulatory assets (liabilities) $ (805,468 ) $ 459,889 _______________ (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 13,"Income Taxes" to the consolidated financial statements included in Item 8 of this report. Puget Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2017 2016 Total PSE regulatory assets (a) $ 953,116 $ 1,113,185 Puget Energy acquisition adjustments: Regulatory assets related to power contracts 1 to 20 years 19,454 22,613 Various other regulatory assets Varies (8 ) 517 Total Puget Energy regulatory assets 972,562 1,136,315 Total PSE regulatory liabilities (a) (1,758,584 ) (653,296 ) Puget Energy acquisition adjustments: Deferred income taxes 634 — Regulatory liabilities related to power contracts 1 to 35 years (174,918 ) (275,061 ) Various other regulatory liabilities Varies (1,314 ) (1,326 ) Total Puget Energy regulatory liabilities (1,934,182 ) (929,683 ) Puget Energy net regulatory asset (liabilities) $ (961,620 ) $ 206,632 _______________ (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, 2017
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) 2017 2016 2017 2016 Distribution plant 20-65 $ 5,670,351 $ 5,287,542 $ 7,289,998 $ 6,922,176 Production plant 12-90 3,068,135 3,007,546 3,954,057 3,910,129 Transmission plant 43-75 1,361,495 1,307,687 1,471,337 1,420,334 General plant 5-75 586,226 541,424 628,179 611,237 Intangible plant (including capitalized software) NA 447,568 347,697 438,185 338,327 Plant acquisition adjustment NA 242,826 242,826 282,792 282,792 Underground storage 25-60 31,815 30,695 45,288 44,206 Liquefied natural gas storage 25-60 12,628 12,628 14,498 14,498 Plant held for future use NA 53,428 52,484 53,580 52,636 Recoverable Cushion Gas NA 8,655 8,655 8,655 8,655 Plant not classified 1-125 275,014 159,345 275,014 159,345 Grant NA — (99,100 ) — (99,100 ) Capital leases, net of accumulated amortization 1 4-6 1,129 645 1,129 645 Less: accumulated provision for depreciation (2,428,524 ) (2,161,796 ) (5,131,966 ) (4,927,602 ) Subtotal $ 9,330,746 $ 8,738,278 $ 9,330,746 $ 8,738,278 Construction work in progress NA 495,937 420,278 495,937 420,278 Net utility plant $ 9,826,683 $ 9,158,556 $ 9,826,683 $ 9,158,556 _______________ 1 Accumulated amortization of capital leases at Puget Energy and PSE was $0.7 million in 2017 and $0.6 million in 2016 .
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% $ 246,510 $ (23 ) $ (38,170 ) Colstrip Units 3 & 4 Coal 25.0% 307,254 1,726 (71,061 ) Colstrip Units 1 – 4 Common Facilities Coal various 83 — (31 ) Frederickson 1 Natural Gas 49.85% 61,783 — (3,850 ) Jackson Prairie Natural Gas Storage 33.34% 31,141 43 (6,325 ) 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 Coal 50.0% $ 378,574 $ (23 ) $ (170,234 ) Colstrip Units 3 & 4 Coal 25.0% 571,604 1,726 (335,414 ) Colstrip Units 1 – 4 Common Facilities Coal various 252 — (199 ) Frederickson 1 Natural Gas 49.85% 67,851 — (9,917 ) Jackson Prairie Natural Gas Storage 33.34% 45,288 43 (20,471 ) Tacoma LNG LNG 43.0% 2,667 87,207 —
Schedule of Asset Retirement Obligations	The following table describes the changes to the Company’s ARO for the year ended December 31, 2017 : Puget Energy and At December 31, (Dollars in Thousands) 2017 2016 Asset retirement obligation at beginning of the period $ 200,345 $ 85,028 New asset retirement obligation recognized in the period 1 2,881 — Liability adjustments (3,841 ) (411 ) Revisions in estimated cash flows (13,748 ) 113,081 Accretion expense 5,539 2,647 Asset retirement obligation at end of period 1 $ 191,176 $ 200,345 _______________ 1 New asset retirement obligations include $2.2 million ARO for Puget LNG only held at Puget Energy.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
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 2017 and 2016 : (Dollars in Thousands) At December 31, Series Type Due 2017 2016 Puget Sound Energy: 6.740% Senior Secured Note 1 2018 $ 200,000 $ 200,000 5.500% Promissory Note 2 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 4.700% Senior Secured Note 2051 45,000 45,000 6.974% Junior Subordinated Note 2067 250,000 250,000 * Debt discount, issuance cost and other * (26,361 ) (28,974 ) Total PSE long-term debt 3,749,911 3,747,298 Puget Energy: * Fair value adjustment of PSE long-term debt * (190,895 ) (199,436 ) * Revolving Credit Agreement 2022 102,600 12,480 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 * (3,687 ) (6,269 ) Total Puget Energy long-term debt $ 5,457,929 $ 5,354,073 _______________ * Not Applicable. 1 6.74% Senior Secured Note in the amount of $200.0 million is classified on the Balance Sheet as a current maturity of long-term debt as of June 15, 2017. 2 5.50% Promissory Note (Puget Western Note Payable) in the amount of $2.4 million was classified on the Balance Sheet as a current maturity of long-term debt from January 1, 2017 to August 13, 2017, at which time the agreement was amended and extended until August 13, 2020. The Promissory Note is currently classified as long-term debt on the Balance sheet as of September 1, 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) 2018 2019 2020 2021 2022 Thereafter Total Maturities of: PSE $ 200,000 $ — $ 2,412 $ — $ — $ 3,573,860 $ 3,776,272 Puget Energy — — 450,000 500,000 552,600 400,000 1,902,600 Total long-term debt $ 200,000 $ — $ 452,412 $ 500,000 $ 552,600 $ 3,973,860 $ 5,678,872

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2017
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 2017 $ 35,198 2016 31,786 2015 27,843
Schedule of Future Minimum Lease Payments for Non-cancellable Leases	: (Dollars in Thousands) Future Minimum Lease Payments At December 31, Years Operating Capital 2018 $ 21,371 $ 527 2019 19,077 306 2020 17,507 232 2021 9,137 97 2022 6,747 — Thereafter 97,974 — Total minimum lease payments $ 171,813 $ 1,162

Accounting for Derivative Ins34

Accounting for Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2017
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) 2017 2016 Contingent Feature Fair Value 1 Liability Posted Collateral Contingent Collateral Fair Value 1 Liability Posted Collateral Contingent Collateral Credit rating 2 $ 3,187 $ — $ 3,187 $ 4,894 $ — $ 4,894 Requested credit for adequate assurance 37,374 — — 7,427 — — Forward value of contract 3 353 2,639 — 507 — — Total $ 40,914 $ 2,639 $ 3,187 $ 12,828 $ — $ 4,894 _______________ 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, 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 Puget Energy and Puget Sound Energy At December 31, 2016 (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 $ 63,079 $ — $ 63,079 $ (42,858 ) $ — $ 20,221 Liabilities: Energy derivative contracts 60,430 — 60,430 (42,858 ) — 17,572 Interest rate swaps 2 141 — 141 — — 141 _______________ 1 All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of set-off. 2 Interest Rate Swap Contracts are only held at Puget Energy and matured in January 2017
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 2017 2016 2017 2016 2017 2016 Interest rate swap derivatives 3 $0.0 $450.0 $ — $ — $ — $ 141 Electric portfolio derivatives * * 13,391 36,460 49,050 41,329 Natural gas derivatives (MMBtus) 4 332.1 336.4 11,014 26,619 37,044 19,101 Total derivative contracts $ 24,405 $ 63,079 $ 86,094 $ 60,571 Current $ 22,247 $ 54,341 $ 64,859 $ 44,310 Long-term 2,158 8,738 21,235 16,261 Total derivative contracts $ 24,405 $ 63,079 $ 86,094 $ 60,571 _______________ 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 Interest rate swap contracts are only held at Puget Energy and matured in January 2017. 4 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 166.8 million One Million British Thermal Units (MMBtus) and purchased electricity of 2.9 million megawatt hours (MWhs) at December 31, 2017 and 186.8 million MMBtus and 3.6 million MWhs at December 31, 2016 .
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 Year Ended December 31, (Dollars in Thousands) Location 2017 2016 2015 Interest rate contracts: Non-hedged interest rate swap (expense) income $ 28 $ (1,062 ) $ (3,796 ) Interest expense — — 560 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net (32,492 ) 62,318 (9,315 ) Realized Electric generation fuel (23,195 ) (39,656 ) (44,648 ) Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 1 1,702 21,477 22,548 Realized Purchased electricity (17,873 ) (21,998 ) (39,137 ) Total gain (loss) recognized in income on derivatives $ (71,830 ) $ 21,079 $ (73,788 )
Subsidiaries [Member]
Derivative [Line Items]
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance [Table Text Block]	Puget Sound Energy Year Ended December 31, (Dollars in Thousands) Location 2017 2016 2015 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net $ (32,492 ) $ 62,318 $ (9,315 ) Realized Electric generation fuel (23,195 ) (39,656 ) (44,648 ) Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 1 1,702 21,477 22,003 Realized Purchased electricity (17,873 ) (21,998 ) (39,137 ) Total gain (loss) recognized in income on derivatives $ (71,858 ) $ 22,141 $ (71,097 ) _______________ 1 Differences between Puget Energy and PSE for the twelve months ended December 31, 2015 are due to certain derivative contracts recorded at fair value in 2009 and subsequently designated as NPNS or cash flow hedges. These differences occurred through February 2015.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Liabilities, Quantitative Information	Puget Energy At December 31, 2017 At December 31, 2016 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 238,935 $ 250,000 $ 210,261 Long-term debt (fixed-rate), net of discount 1 2 5,105,329 6,520,515 5,091,593 6,337,287 Long-term debt (variable-rate) 2 102,600 102,600 12,480 12,480 Total $ 5,457,929 $ 6,862,050 $ 5,354,073 $ 6,560,028 Puget Sound Energy At December 31, 2017 At December 31, 2016 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 238,935 $ 250,000 $ 210,261 Long-term debt (fixed-rate), net of discount 2 2 3,499,911 4,550,130 3,497,298 4,360,783 Total $ 3,749,911 $ 4,789,065 $ 3,747,298 $ 4,571,044
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 (Liability) 2017 2016 2015 (Dollars in Thousands) Electric Gas Total Electric Gas Total Electric Gas Total Balance at beginning of period $ 972 $ 625 $ 1,597 $ (7,345 ) $ (2,383 ) $ (9,728 ) $ (12,062 ) $ (2,040 ) $ (14,102 ) Changes during period Realized and unrealized energy derivatives: Included in earnings 1 2,781 — 2,781 4,007 — 4,007 (6,432 ) — (6,432 ) Included in regulatory assets / liabilities — 6,346 6,346 — 4,312 4,312 — 3,695 3,695 Settlements 2 (6,549 ) (6,372 ) (12,921 ) (1,129 ) (2,679 ) (3,808 ) 902 (3,885 ) (2,983 ) Transferred into Level 3 523 (553 ) (30 ) (3,021 ) — (3,021 ) (787 ) — (787 ) Transferred out Level 3 3,371 1,877 5,248 8,460 1,375 9,835 11,034 (153 ) 10,881 Balance at end of period $ 1,098 $ 1,923 $ 3,021 $ 972 $ 625 $ 1,597 $ (7,345 ) $ (2,383 ) $ (9,728 ) _______________ 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 $1.5 million , $2.0 million and $(7.4) million for the years ended December 31, 2017 , 2016 and 2015 , 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]	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 impairment on an annual basis, and upon the occurrence of any events or circumstances that would be more likely than not to reduce the fair value of the long-lived assets below their carrying value. One such triggering event is a significant decrease in the forward market prices of power. During 2017 and 2016 , Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. Below are the forward price ranges for the Company's commodity contracts, as of December 31, 2017 : Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $3,525 $2,427 Discounted cash flow Power Prices (per MWh) $7.02 $28.94 $18.61 Natural gas $4,041 $2,118 Discounted cash flow Natural Gas Prices (per MMBtu) $1.22 $2.80 $1.54 _______________ 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, 2017 , 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 $0.9 million . Below are significant unobservable inputs used in estimating the impaired long term power purchase contracts' fair value in 2017 and 2016 : Puget Energy Valuation Date Contract Unobservable Input Low High Average 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 September 30, 2016 Priest Rapids RP Power prices (per MWh) 24.24 58.96 39.31 Power contract costs per year (in thousands) 618 4,633 2,472 March 31, 2016 Wells Hydro Power prices (per MWh) 9.46 25.96 21.38 Power contract costs per quarter (in thousands) 4,100 4,659 4,452
Schedule of Impaired Intangible Assets [Table Text Block]	n 2017 and 2016 , due to continued 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 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 September 30, 2016 Priest Rapids RP $ 18,969 $ 6,191 $ 12,778 March 31, 2016 Wells Hydro 25,193 19,855 5,338 Total 2016 Impairments $ 18,116
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, 2017 At December 31, 2016 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 9,866 $ 3,525 $ 13,391 $ 30,666 $ 5,794 $ 36,460 Natural gas derivative instruments 6,973 4,041 11,014 23,316 3,303 26,619 Total derivative assets $ 16,839 $ 7,566 $ 24,405 $ 53,982 $ 9,097 $ 63,079 Liabilities: Interest rate derivative instruments 1 $ — $ — $ — $ 141 $ — $ 141 Electric derivative instruments 46,623 2,427 49,050 36,507 4,822 41,329 Natural gas derivative instruments 34,926 2,118 37,044 16,423 2,678 19,101 Total derivative liabilities $ 81,549 $ 4,545 $ 86,094 $ 53,071 $ 7,500 $ 60,571

Retirement Benefits (Tables)

Retirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016 : Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Change in benefit obligation: Benefit obligation at beginning of period $ 652,607 $ 643,088 $ 51,734 $ 51,279 $ 11,194 $ 13,946 Service cost 20,081 18,913 913 1,085 72 93 Interest cost 28,373 28,689 2,285 2,325 500 533 Actuarial loss (gain) 40,945 1,545 2,722 106 725 (2,262 ) Benefits paid (40,594 ) (38,730 ) (1,900 ) (3,061 ) (1,137 ) (1,264 ) Medicare part D subsidy received — — — — 100 148 Administrative expense (931 ) (898 ) — — — — Benefit obligation at end of period $ 700,481 $ 652,607 $ 55,754 $ 51,734 $ 11,454 $ 11,194
Schedule of Changes in Fair Value of Plan Assets	Puget Energy and Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Change in plan assets: Fair value of plan assets at beginning of period $ 620,260 $ 598,865 $ — $ — $ 7,200 $ 7,203 Actual return on plan assets 107,836 37,022 — — 784 926 Employer contribution 18,000 24,000 1,900 3,061 291 335 Benefits paid (40,594 ) (38,730 ) (1,900 ) (3,061 ) (1,137 ) (1,264 ) Administrative expense (1,142 ) (897 ) — — — — Fair value of plan assets at end of period $ 704,360 $ 620,260 $ — $ — $ 7,138 $ 7,200 Funded status at end of period $ 3,879 $ (32,347 ) $ (55,754 ) $ (51,734 ) $ (4,316 ) $ (3,994 )
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) 2017 2016 2017 2016 2017 2016 Amounts recognized in Statement of Financial Position consist of: Noncurrent assets $ 3,879 $ — $ — $ — $ — $ — Current liabilities — — (5,486 ) (1,911 ) (317 ) (325 ) Noncurrent liabilities — (32,347 ) (50,268 ) (49,823 ) (3,999 ) (3,669 ) Net assets (liabilities) $ 3,879 $ (32,347 ) $ (55,754 ) $ (51,734 ) $ (4,316 ) $ (3,994 )
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) 2017 2016 2017 2016 2017 2016 Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets: Projected benefit obligation $ 700,481 $ 652,607 $ 55,754 $ 51,734 $ 11,454 $ 11,194 Accumulated benefit obligation 688,908 641,855 52,681 47,639 11,367 11,092 Fair value of plan assets 704,360 620,260 — — 7,138 7,200
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, 2017 , 2016 and 2015 : Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2017 2016 2015 2017 2016 2015 2017 2016 2015 Components of net periodic benefit cost: Service cost $ 20,081 $ 18,913 $ 21,287 $ 913 $ 1,085 $ 1,108 $ 72 $ 93 $ 112 Interest cost 28,373 28,689 28,088 2,285 2,325 2,281 500 533 621 Expected return on plan assets (47,784 ) (46,619 ) (45,038 ) — — — (461 ) (446 ) (531 ) Amortization of prior service cost (credit) (1,980 ) (1,980 ) (1,980 ) 42 42 42 — — — Amortization of net loss (gain) — — 3,887 1,077 911 1,641 (402 ) (386 ) (130 ) Net periodic benefit cost $ (1,310 ) $ (997 ) $ 6,244 $ 4,317 $ 4,363 $ 5,072 $ (291 ) $ (206 ) $ 72
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, 2017 and 2016 : Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ (18,896 ) $ 11,141 $ 2,722 $ 106 $ 403 $ (2,742 ) Amortization of net (loss) gain — — (1,076 ) (910 ) 401 385 Amortization of prior service (cost) credit 1,980 1,980 (42 ) (42 ) — — Total change in other comprehensive income for year $ (16,916 ) $ 13,121 $ 1,604 $ (846 ) $ 804 $ (2,357 )
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 2017 2016 2015 2017 2016 2015 2017 2016 2015 Discount rate 4.00 % 4.50 % 4.65 % 4.00 % 4.50 % 4.65 % 4.00 % 4.50 % 4.65 % 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 — — — — — — 6.80 8.80 7.20 Benefit Cost Assumptions Discount rate 4.50 % 4.65 % 4.25 % 4.50 % 4.65 % 4.25 % 4.50 % 4.65 % 4.25 % Return on plan assets 7.45 7.75 7.75 — — — 6.75 6.75 7.00 Rate of compensation increase 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 4.50 Medical trend rate — — — — — — 9.50 5.30 7.20
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 6.80% in 2018 grading down to 4.10% in 2019 . A 1.0% change in the assumed medical inflation rate would have the following effects: 2017 2016 (Dollars in Thousands) 1% Increase 1% Decrease 1% Increase 1% Decrease Effect on post-retirement benefit obligation $ 23 $ (22 ) $ 38 $ (35 ) Effect on service and interest cost components 1 (1 ) 2 (2 )
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) 2018 2019 2020 2021 2022 2023-2027 Qualified Pension total benefits $ 42,600 $ 43,400 $ 44,800 $ 45,700 $ 46,900 $ 246,500 SERP Pension total benefits 5,486 6,001 4,684 1,728 4,577 37,394 Other Benefits total with Medicare Part D subsidy 911 885 852 811 863 3,748 Other Benefits total without Medicare Part D subsidy 1,172 1,155 1,131 1,097 1,070 4,844
Schedule of Allocation of Plan Assets	To obtain the desired return needed to fund the pension benefit plans, the Retirement Plan Committee has established investment allocation percentages by asset classes as follows: Allocation Asset Class Minimum Target Maximum Domestic large cap equity 25 % 31 % 40 % Domestic small cap equity — 9 15 Non-U.S. equity 10 25 30 Fixed income 15 25 30 Real estate — — 10 Absolute return 5 10 15 Cash — — 5 The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, 2017 and 2016 : Recurring Fair Value Measures Recurring Fair Value Measures As of December 31, 2017 As of December 31, 2016 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual Funds $ 117,796 $ — $ 117,796 $ 181,212 $ — $ 181,212 Common Stock 209,504 — 209,504 154,255 — 154,255 Government Securities 18,316 23,782 42,098 18,754 16,197 34,951 Corporate Bonds — 34,588 34,588 — 38,543 38,543 Cash and cash equivalents 2,684 9,304 11,988 — — — Subtotal $ 348,300 $ 67,674 415,974 $ 354,221 $ 54,740 408,961 Investments measured at NAV 1 237,427 222,819 Net (payable) receivable 50,959 (9,894 ) Total assets $ 704,360 $ 621,886 _______________ 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, 2017 . 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, 2017 As of December 31, 2016 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual fund 1 $ 7,089 $ — $ 7,089 $ 7,182 $ — $ 7,182 Investments measured at NAV 2 49 80 Total assets $ 7,138 $ 7,262 _______________ 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, 2017 . 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, 2017 .
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, 2017 and 2016 : Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 37,693 $ 56,588 $ 10,689 $ 9,043 $ (3,386 ) $ (4,190 ) Prior service cost (credit) (7,843 ) (9,822 ) 204 246 — — Total $ 29,850 $ 46,766 $ 10,893 $ 9,289 $ (3,386 ) $ (4,190 )
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) 2017 2016 2017 2016 2017 2016 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 185,277 $ 217,143 $ 13,134 $ 11,978 $ (4,901 ) $ (5,994 ) Prior service cost (credit) (6,232 ) (7,806 ) 208 251 — — Total $ 179,045 $ 209,337 $ 13,342 $ 12,229 $ (4,901 ) $ (5,994 )
Schedule of Net Benefit Costs	Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2017 2016 2015 2017 2016 2015 2017 2016 2015 Components of net periodic benefit cost: Service cost $ 20,081 $ 18,913 $ 21,287 $ 913 $ 1,085 $ 1,108 $ 72 $ 93 $ 112 Interest cost 28,373 28,689 28,088 2,285 2,325 2,281 500 533 621 Expected return on plan assets (47,862 ) (46,814 ) (45,462 ) — — — (461 ) (446 ) (531 ) Amortization of prior service cost (credit) (1,573 ) (1,573 ) (1,573 ) 44 44 44 — — 3 Amortization of net loss (gain) 13,048 15,257 20,555 1,565 1,330 2,120 (641 ) (632 ) (406 ) Net periodic benefit cost $ 12,067 $ 14,472 $ 22,895 $ 4,807 $ 4,784 $ 5,553 $ (530 ) $ (452 ) $ (201 )
Schedule of Amounts Recognized in Other Comprehensive Income (Loss)	Puget Sound Energy Qualified Pension Benefit SERP Pension Benefits Other Benefits (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ (18,817 ) $ 11,336 $ 2,722 $ 106 $ 452 $ (2,742 ) Amortization of net (loss) gain (13,048 ) (15,257 ) (1,565 ) (1,330 ) 641 631 Amortization of prior service (cost) credit 1,573 1,573 (44 ) (44 ) — — Total change in other comprehensive income for year $ (30,292 ) $ (2,348 ) $ 1,113 $ (1,268 ) $ 1,093 $ (2,111 )

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
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) 2017 2016 2015 Charged to operating expenses: Current: Federal $ 1,127 $ — $ — State 17 20 — Deferred: Federal 254,420 140,315 91,968 State (421 ) (131 ) (192 ) Total income tax expense $ 255,143 $ 140,204 $ 91,776
Schedule of Effective Income Tax Rate Reconciliation	The following reconciliation compares pre-tax book income at the federal statutory rate of 35.0% to the actual income tax expense in the Statements of Income: Puget Energy Year Ended December 31, (Dollars in Thousands) 2017 2016 2015 Income taxes at the statutory rate $ 148,847 $ 158,586 $ 116,534 Increase (decrease): Production tax credit 1 — (12,925 ) (19,470 ) Utility plant differences — 3,966 5,671 Treasury grant amortization (9,537 ) (9,788 ) (8,807 ) Tax reform 117,185 — — Other - net (1,352 ) 365 (2,152 ) Total income tax expense $ 255,143 $ 140,204 $ 91,776 Effective tax rate 60.0 % 30.9 % 27.6 %
Schedule of Deferred Tax Assets and Liabilities	The Company’s net deferred tax liability at December 31, 2017 and 2016 is composed of amounts related to the following types of temporary differences: Puget Energy At December 31, (Dollars in Thousands) 2017 2016 Utility plant and equipment $ 2,034,328 $ 1,880,782 Regulatory asset for income taxes — 72,038 Fair value of debt instruments 38,777 67,444 Pensions and other compensation 46,338 77,230 Other deferred tax liabilities 86,933 119,050 Subtotal deferred tax liabilities 2,206,376 2,216,544 Net operating loss carryforward (212,168 ) (352,827 ) Net regulatory liability for income taxes (1,011,626 ) — Production tax credit carryforward (187,617 ) (190,999 ) Regulatory liability on production tax credit (49,873 ) (101,787 ) Net other deferred tax assets 1,776 — Subtotal deferred tax assets (1,459,508 ) (645,613 ) Total net deferred tax liabilities $ 746,868 $ 1,570,931
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) 2017 2016 2015 Charged to operating expenses: Current: Federal $ 1,127 $ — $ — State 17 20 — Deferred: Federal 210,842 175,327 125,900 State — — — Total income tax expense $ 211,986 $ 175,347 $ 125,900
Schedule of Effective Income Tax Rate Reconciliation	Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2017 2016 2015 Income taxes at the statutory rate $ 185,430 $ 194,572 $ 150,531 Increase (decrease): Production tax credit 1 — (12,925 ) (19,470 ) Utility plant differences — 3,966 5,671 Treasury grant amortization (9,537 ) (9,788 ) (8,807 ) Tax reform 36,328 — — Other - net (235 ) (478 ) (2,025 ) Total income tax expense $ 211,986 $ 175,347 $ 125,900 Effective tax rate 40.0 % 31.5 % 29.3 %
Schedule of Deferred Tax Assets and Liabilities	Puget Sound Energy At December 31, (Dollars in Thousands) 2017 2016 Utility plant and equipment $ 2,034,328 $ 1,880,782 Regulatory asset for income taxes — 71,517 Other, net deferred tax liabilities 86,933 113,938 Subtotal deferred tax liabilities 2,121,261 2,066,237 Net regulatory liability for income taxes (1,012,260 ) — Net operating loss carryforward — (41,061 ) Production tax credit carryforward (187,617 ) (190,999 ) Regulatory liability on production tax credit (49,873 ) (101,787 ) Net other deferred tax assets (2,038 ) — Subtotal deferred tax assets (1,251,788 ) (333,847 ) Total net deferred tax liabilities $ 869,473 $ 1,732,390

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
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) 2017 2016 2015 PUD contract costs $ 73,827 $ 77,667 $ 72,833 As of December 31, 2017 , 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 2018 Costs 2018 Debt Service Costs Interest included in 2018 Debt Service Costs Debt Outstanding Chelan County PUD: Rock Island Project 2031 25.0 % 156 $ 29,135 $ 10,105 $ 5,354 $ 84,269 Rocky Reach Project 2031 25.0 325 28,800 5,796 2,548 39,563 Douglas County PUD: Wells Project 1 2028 29.9 251 11,002 4,695 1,379 49,629 Grant County PUD: Priest Rapids Development 2052 0.6 6 2,050 1,231 1,231 13,723 Wanapum Development 2052 0.6 7 2,050 1,231 1,231 13,723 Total 745 $ 73,037 $ 23,058 $ 11,743 $ 200,907 _______________ 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) 2017 2016 2015 PUD contract costs $ 73,827 $ 77,667 $ 72,833
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) 2018 2019 2020 2021 2022 Thereafter Total Natural gas supply $ 245,669 $ 193,458 $ 163,818 $ 145,662 $ 109,401 $ — $ 858,008 Firm transportation service 154,170 154,204 141,962 126,319 125,335 310,428 1,012,418 Firm storage service 8,328 8,899 7,908 3,108 1,619 857 30,719 Short-term natural gas supply contracts 55,774 13,818 1,651 — — — 71,243 Total $ 463,941 $ 370,379 $ 315,339 $ 275,089 $ 236,355 $ 311,285 $ 1,972,388 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) 2018 2019 2020 2021 2022 Thereafter Total Energy production service contracts $ 28,674 $ 27,939 $ 28,639 $ 29,415 $ 30,142 $ 165,689 $ 310,498 Automated meter reading system 48,245 44,842 43,951 44,497 45,168 187,698 414,401 Total $ 76,919 $ 72,781 $ 72,590 $ 73,912 $ 75,310 $ 353,387 $ 724,899 These contracts have varying terms and may include escalation and termination provisions. (Dollars in Thousands) 2018 2019 2020 2021 2022 Thereafter Total Columbia River projects $ 82,200 $ 97,890 $ 95,704 $ 91,862 $ 91,018 $ 708,499 $ 1,167,173 Other utilities 1,257 888 — — — — 2,145 Non-utility contracts 206,233 233,776 238,016 244,962 244,906 1,128,466 2,296,359 Short-term electric supply contracts 70,786 140 — — — — 70,926 Total $ 360,476 $ 332,694 $ 333,720 $ 336,824 $ 335,924 $ 1,836,965 $ 3,536,603

Accumulated Other Comprehensi39

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 , 2016 and 2015 , 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, 2014 $ (36,710 ) $ (333 ) $ (37,043 ) Other comprehensive income (loss) before reclassifications 7,196 — 7,196 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 2,248 333 2,581 Net current-period other comprehensive income (loss) 9,444 333 9,777 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 ) 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, 2014 $ (164,281 ) $ (686 ) $ (5,990 ) $ (170,957 ) Other comprehensive income (loss) before reclassifications 6,922 — — 6,922 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 13,482 686 317 14,485 Net current-period other comprehensive income (loss) 20,404 686 317 21,407 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 )
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2017 , 2016 and 2015 , 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) 2017 2016 2015 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,938 $ 1,938 $ 1,938 Amortization of net gain (loss) (a) (675 ) (525 ) (5,397 ) Total before tax 1,263 1,413 (3,459 ) Tax (expense) or benefit (442 ) (495 ) 1,211 Net of Tax 821 918 (2,248 ) Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: Electric derivatives Purchased electricity — — (512 ) Tax (expense) or benefit — — 179 Net of Tax — — (333 ) Total reclassification for the period Net of Tax $ 821 $ 918 $ (2,581 ) _______________ (a) These AOCI components are included in the computation of net periodic pension cost, see Note 12, "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) 2017 2016 2015 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,529 $ 1,529 $ 1,526 Amortization of net gain (loss) (a) (13,972 ) (15,955 ) (22,268 ) Total before tax (12,443 ) (14,426 ) (20,742 ) Tax (expense) or benefit 4,355 5,049 7,260 Net of tax (8,088 ) (9,377 ) (13,482 ) Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: Electric derivatives Purchased electricity — — (1,055 ) Tax (expense) or benefit — — 369 Net of Tax — — (686 ) Net unrealized gain (loss) on treasury interest rate swaps: Interest rate contracts Interest expense (488 ) (488 ) (488 ) Tax (expense) or benefit 171 171 171 Net of Tax (317 ) (317 ) (317 ) Total reclassification for the period Net of Tax $ (8,405 ) $ (9,694 ) $ (14,485 ) _______________ (a) These AOCI components are included in the computation of net periodic pension cost, see Note 12, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.

Summary of Significant Accoun40

Summary of Significant Accounting Policies (Details) $ in Thousands	Dec. 19, 2017	Dec. 31, 2013	Dec. 31, 2017USD ($)mi²unit	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Jan. 01, 2018USD ($)	Jan. 01, 2017USD ($)	Jan. 01, 2015	Dec. 31, 2014USD ($)	Feb. 06, 2009USD ($)
Accounting Policies
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			$ 26,616	28,878	$ 42,494				$ 37,527
Revenue Recognition
Excise taxes collected			257,100	235,300	$ 234,200
Allowance for Doubtful Accounts
Allowance for doubtful accounts			$ 8,901	$ 9,798
Electric Transmission
Accounting Policies
Annual depreciation provision			2.80%
Gas Transmission Equipment
Accounting Policies
Annual depreciation provision			3.40%
Common Plant
Accounting Policies
Annual depreciation provision			8.30%	9.70%	8.50%
Maximum
Accounting Policies
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)	5.00%							3.00%
Subsidiaries [Member]
Accounting Policies
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities	7.60%	7.77%
Area of service territory (sqmi) | mi²			6,000
Cash and Cash Equivalents
Cash and Cash Equivalents, at Carrying Value			$ 25,864	$ 28,481	$ 41,856				$ 37,466
Allowance for Doubtful Accounts
Allowance for doubtful accounts			$ 8,901	$ 9,798
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			$ 104,000
Construction in Progress and O&M Expenses			$ 104,300
Tacoma LNG [Member]
Statements of Cash Flows
Jointly Owned Non-Utility Plant Share			43.00%
Construction in Progress, Gross			$ 87,200

Summary of Significant Accoun41

Summary of Significant Accounting Policies - AFUDC (Details)	12 Months Ended
	Dec. 31, 2017
Regulatory Assets [Line Items]
Public Utilities, Property, Plant and Equipment, Non-project Electric Utility Plant, Estimated Useful Life Average	30 years

New Accounting Pronouncements R

New Accounting Pronouncements Revenue Recognition (Details) - Pension Plan [Member] $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Defined Benefit Plan, Other Cost (Credit)	$ 18.4
Subsidiaries [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Defined Benefit Plan, Other Cost (Credit)	$ 4.7

Regulation and Rates Net regula

Regulation and Rates Net regulatory assets and liabilities (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Deferred income tax charge
Regulatory Assets [Line Items]
Regulatory Liabilities		$ 634	$ 0
Various other regulatory liabilities
Regulatory Assets [Line Items]
Regulatory Liabilities		(1,314)	(1,326)
Regulatory liabilities related to power contracts
Regulatory Assets [Line Items]
Regulatory Liabilities		(174,918)	(275,061)
Liabilities, Total
Regulatory Assets [Line Items]
Regulatory Liabilities		(1,934,182)	(929,683)
Net Regulatory Assets
Regulatory Assets [Line Items]
Net Regulatory Assets		(961,620)
Net Regulatory Assets
Regulatory Assets [Line Items]
Net Regulatory Assets			206,632
Various other regulatory assets
Regulatory Assets [Line Items]
Regulatory Assets		(8)	517
Requlatory Assets Related to Power Contracts
Regulatory Assets [Line Items]
Regulatory Assets		19,454	22,613
Assets, Total
Regulatory Assets [Line Items]
Regulatory Assets		972,562	1,136,315
Subsidiaries [Member] | Deferred income tax charge
Regulatory Assets [Line Items]
Regulatory Liabilities	[1]	(1,012,260)	0
Subsidiaries [Member] | Cost of removal
Regulatory Assets [Line Items]
Regulatory Liabilities	[2]	$ (389,579)	(369,300)
Subsidiaries [Member] | Treasury grants
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		20 years
Regulatory Liabilities		$ (205,775)	(133,709)
Subsidiaries [Member] | Production tax credits [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	[3]	(93,616)	(93,616)
Subsidiaries [Member] | Decoupling rate of return sharing [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities		(18,400)	(13,300)
Subsidiaries [Member] | Deferral and interest decoupling revenue [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities		$ (7,896)	(16,448)
Subsidiaries [Member] | PGA payable
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		1 year
Regulatory Liabilities		$ (16,051)	0
Subsidiaries [Member] | Deferred decoupling revenue, net [Member]
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		2 years
Regulatory Liabilities		$ (26,296)	(29,748)
Subsidiaries [Member] | Summit purchase option buy-out
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		2 years 10 months
Regulatory Liabilities		$ (4,463)	(6,038)
Subsidiaries [Member] | Purchased Gas Adjustment Deferral of Unrealized Gains on Derivatives [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities		0	(7,517)
Subsidiaries [Member] | Various other regulatory liabilities
Regulatory Assets [Line Items]
Regulatory Liabilities	[4]	(10,544)	(13,368)
Subsidiaries [Member] | Liabilities, Total
Regulatory Assets [Line Items]
Regulatory Liabilities	[4]	(1,758,584)	(653,296)
Subsidiaries [Member] | Net Regulatory Assets
Regulatory Assets [Line Items]
Net Regulatory Assets		(805,468)
Subsidiaries [Member] | Net Regulatory Assets
Regulatory Assets [Line Items]
Net Regulatory Assets			459,889
Subsidiaries [Member] | Storm Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets		128,508	122,709
Subsidiaries [Member] | Colstrip Regulatory Asset [Domain]
Regulatory Assets [Line Items]
Regulatory Assets		127,627	176,804
Subsidiaries [Member] | Deferred decoupling revenue, gross [Member]
Regulatory Assets [Line Items]
Regulatory Assets		98,769	156,408
Subsidiaries [Member] | Other decoupling 24 month reserve [Member]
Regulatory Assets [Line Items]
Regulatory Assets		0	(20,847)
Subsidiaries [Member] | Deferred decoupling revenue, net [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 98,769	135,561
Net Regulatory Assets, Remaining Amortization Period		2 years
Subsidiaries [Member] | Chelan PUD contract initiation
Regulatory Assets [Line Items]
Regulatory Assets		$ 98,052	105,140
Net Regulatory Assets, Remaining Amortization Period		13 years 10 months
Subsidiaries [Member] | Environmental remediation
Regulatory Assets [Line Items]
Regulatory Assets	[4]	$ 81,550	74,557
Subsidiaries [Member] | Lower Snake River
Regulatory Assets [Line Items]
Regulatory Assets		$ 70,975	74,862
Net Regulatory Assets, Remaining Amortization Period		19 years 5 months
Subsidiaries [Member] | Baker Dam Licensing Operating Maintenance Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 54,817	61,453
Subsidiaries [Member] | Deferred Washington Commission AFUDC
Regulatory Assets [Line Items]
Regulatory Assets		$ 50,301	51,404
Net Regulatory Assets, Remaining Amortization Period		10 years
Subsidiaries [Member] | Unamortized loss on reacquired debt
Regulatory Assets [Line Items]
Regulatory Assets		$ 39,674	42,196
Subsidiaries [Member] | Property tax tracker
Regulatory Assets [Line Items]
Regulatory Assets		$ 36,517	41,949
Net Regulatory Assets, Remaining Amortization Period		2 years
Subsidiaries [Member] | Energy Conservation Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	[4]	$ 35,538	41,027
Subsidiaries [Member] | PGA deferral of unrealized losses on derivative instruments
Regulatory Assets [Line Items]
Regulatory Assets		26,030	0
Subsidiaries [Member] | White River relicensing and other costs
Regulatory Assets [Line Items]
Regulatory Assets		$ 19,502	21,627
Net Regulatory Assets, Remaining Amortization Period		3 years
Subsidiaries [Member] | Generation plant major maintenance [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 17,216	13,178
Subsidiaries [Member] | Mint Farm ownership and operating costs
Regulatory Assets [Line Items]
Regulatory Assets		$ 14,319	16,319
Net Regulatory Assets, Remaining Amortization Period		7 years 4 months
Subsidiaries [Member] | Colstrip major maintenance [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 8,723	6,589
Net Regulatory Assets, Remaining Amortization Period		1 year 6 months
Subsidiaries [Member] | Snoqualmie Licensing Operating Maintenance Costs
Regulatory Assets [Line Items]
Regulatory Assets		$ 7,341	8,018
Subsidiaries [Member] | Ferndale
Regulatory Assets [Line Items]
Regulatory Assets		$ 7,295	11,274
Net Regulatory Assets, Remaining Amortization Period		1 year 10 months
Subsidiaries [Member] | Colstrip common property
Regulatory Assets [Line Items]
Regulatory Assets		$ 4,618	5,334
Net Regulatory Assets, Remaining Amortization Period		7 years 5 months
Subsidiaries [Member] | PCA Mechanism [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 4,576	4,531
Subsidiaries [Member] | Electron Unrecovered Loss
Regulatory Assets [Line Items]
Regulatory Assets		$ 3,786	7,178
Net Regulatory Assets, Remaining Amortization Period		1 year
Subsidiaries [Member] | Deferred income tax charge
Regulatory Assets [Line Items]
Regulatory Assets	[1]	$ 0	71,517
Subsidiaries [Member] | PGA receivable [Domain]
Regulatory Assets [Line Items]
Regulatory Assets		$ 0	2,785
Net Regulatory Assets, Remaining Amortization Period		1 year
Subsidiaries [Member] | Various other regulatory assets
Regulatory Assets [Line Items]
Regulatory Assets	[4]	$ 17,382	17,173
Subsidiaries [Member] | Assets, Total
Regulatory Assets [Line Items]
Regulatory Assets	[4]	953,116	1,113,185
Colstrip Regulatory Asset [Domain]
Regulatory Assets [Line Items]
Regulatory Assets		$ 127,600	$ 176,800
[1]	(d) For additional information, see Note 13,"Income Taxes" to the consolidated financial statements included in Item 8 of this report.
[2]	The balance is dependent upon the cost of removal of underlying assets and the life of utility plant.
[3]	Amortization will begin once PTCs are utilized by PSE on its tax return.
[4]	Amortization periods vary depending on timing of underlying transactions.

Regulation and Rates Rate Adjus

Regulation and Rates Rate Adjustments (Details) - USD ($) $ in Millions	Dec. 19, 2017	Apr. 03, 2017	Jan. 13, 2017	Jan. 01, 2017	Dec. 31, 2013	Dec. 31, 2017
Decoupling Mechanism [Member]
Regulation and Rates [Line Items]
Deferred Revenue, Revenue Recognized						$ 20.8
Subsidiaries [Member]
Regulation and Rates [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities	7.60%				7.77%
Subsidiaries [Member] | Decoupling Mechanism [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage				2.20%
Subsidiaries [Member] | Decoupling Mechanism [Member] | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage				3.00%
Subsidiaries [Member] | General Rate Case [Member]
Regulation and Rates [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities			7.74%
Regulated Utility, After-tax Allowed Rate of Return on Net Regulatory Assets and Liabilities	6.55%		6.69%
Public Utilities, Requested Equity Capital Structure, Percentage			48.50%
Public Utilities, Requested Return on Equity, Percentage			9.80%
Subsidiaries [Member] | General Rate Case [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage	(3.80%)
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage		(3.20%)
Public Utilities, Approved Rate Increase (Decrease), Amount	$ (35.5)
Public Utilities, Requested Rate Increase (Decrease), Amount			$ (22.3)
Public Utilities, Requested Rate Increase (Decrease), Percentage			(2.40%)
Subsidiaries [Member] | General Rate Case [Member] | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage	0.90%
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage		3.20%
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 20.2
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 86.3
Public Utilities, Requested Rate Increase (Decrease), Percentage			4.10%
Maximum | Decoupling Mechanism [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage	5.00%
Maximum | Subsidiaries [Member] | Decoupling Mechanism [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage	3.00%			3.00%
Colstrip Units 1 & 2
Regulation and Rates [Line Items]
Decommissioning Fund Investments	$ 10
Colstrip Units 1 & 2 | Shareholders Fund Amount [Domain]
Regulation and Rates [Line Items]
Decommissioning Fund Investments	5
Colstrip Units 1 & 2 | Regulatory Liability Monetized PTC Fund Amount [Domain]
Regulation and Rates [Line Items]
Decommissioning Fund Investments	$ 5

Regulation and Rates (Details)

Regulation and Rates (Details)	Dec. 19, 2017USD ($)	Sep. 15, 2017	Apr. 03, 2017USD ($)	Jan. 13, 2017	Jan. 01, 2017USD ($)	Dec. 31, 2013	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Jan. 01, 2018USD ($)	Jan. 01, 2015
Regulation and Rates [Line Items]
Accrual for Environmental Loss Contingencies							$ 28,600,000
Electric [Member]
Regulation and Rates [Line Items]
Environmental Remediation Expense							8,900,000
Environmental Expense and Liabilities							17,600,000	$ 13,800,000	$ 14,000,000
Natural Gas [Member]
Regulation and Rates [Line Items]
Environmental Remediation Expense							38,900,000
Environmental Expense and Liabilities							63,900,000	60,700,000	$ 52,900,000
Subsidiaries [Member]
Regulation and Rates [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities	7.60%					7.77%
Regulatory Liabilities Reclassified from Accumulated Depreciation							389,600,000	369,300,000
Public Utilities, Rate Case, Deferred Storm Costs Threshold					$ 8,000,000					$ 10,000,000
Public Utilities, Rate Case, Deferred Storm Qualifying Costs										$ 500,000
Storm Damage Costs Incurred During Period							30,400,000	22,000,000
Storm Damage Costs Deferred During Period							$ 21,600,000	$ 12,400,000
Decoupling Mechanism [Member] | Subsidiaries [Member] | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage					3.00%
Decoupling Mechanism [Member] | Subsidiaries [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage					2.20%
General Rate Case [Member] | Subsidiaries [Member]
Regulation and Rates [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities				7.74%
Regulated Utility, After-tax Allowed Rate of Return on Net Regulatory Assets and Liabilities	6.55%			6.69%
Public Utilities, Approved Equity Capital Structure, Percentage	48.50%
Public Utilities, Approved Return on Equity, Percentage	9.50%
Number of new mechanisms				2
Number of parties that agreed to settle		10
Number of parties total		11
Number of contested issues not settled		4
Public Utilities, Requested Equity Capital Structure, Percentage				48.50%
Public Utilities, Requested Return on Equity, Percentage				9.80%
General Rate Case [Member] | Subsidiaries [Member] | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage				4.10%
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount			$ 67,900,000
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage			3.20%
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 [Member]
Regulation and Rates [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Percentage				(2.40%)
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount			$ (29,300,000)
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage			(3.20%)
Public Utilities, Approved Rate Increase (Decrease), Amount	$ (35,500,000)
Public Utilities, Approved Rate Increase (Decrease), Percentage	(3.80%)
Maximum
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)	5.00%										3.00%
Maximum | Decoupling Mechanism [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage	5.00%
Maximum | Decoupling Mechanism [Member] | Subsidiaries [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage	3.00%				3.00%
Regulatory liabilities related to power contracts | Parent Company [Member]
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							5 years
Net Regulatory Assets, Remaining Amortization Period, Max							11 years
Chelan PUD contract initiation | Subsidiaries [Member]
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period							13 years 10 months
Ferndale | Subsidiaries [Member]
Regulation and Rates [Line Items]
Net Regulatory Assets, Remaining Amortization Period							1 year 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 | Parent Company [Member]
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							19 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, 2017USD ($)
Parent [Line Items]
Retained Earnings, Unappropriated	$ 645.1
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	48.00%
EBITDA Interest Expense Ratio	5.5
EBITDA to Interest Expense Denominator	1
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End	1

Utility Plant (Details)

Utility Plant (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Public Utility, Property, Plant and Equipment
Accumulated amortization of capital leases		$ 700	$ 600
Utility Plant
Distribution plant		5,670,351	5,287,542
Production plant		3,068,135	3,007,546
Transmission plant		1,361,495	1,307,687
General plant		586,226	541,424
Intangible plant (including capitalized software)		447,568	347,697
Plant acquisition adjustment		242,826	242,826
Underground storage		31,815	30,695
Liquefied natural gas storage		12,628	12,628
Plant held for future use		53,428	52,484
Recoverable cushion gas		8,655	8,655
Public Utilities, Property, Plant and Equipment, Other Property, Plant and Equipment		275,014	159,345
Public Utilities, Property, Plant and Equipment Grant		0	(99,100)
Capital leases, net of accumulated amortization	[1]	1,129	645
Less: Accumulated depreciation and amortization		(2,428,524)	(2,161,796)
Subtotal		9,330,746	8,738,278
Construction work in progress		495,937	420,278
Net utility plant		$ 9,826,683	9,158,556
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	[1]	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	[1]	6 years
Subsidiaries [Member]
Utility Plant
Distribution plant		$ 7,289,998	6,922,176
Production plant		3,954,057	3,910,129
Transmission plant		1,471,337	1,420,334
General plant		628,179	611,237
Intangible plant (including capitalized software)		438,185	338,327
Plant acquisition adjustment		282,792	282,792
Underground storage		45,288	44,206
Liquefied natural gas storage		14,498	14,498
Plant held for future use		53,580	52,636
Recoverable cushion gas		8,655	8,655
Public Utilities, Property, Plant and Equipment, Other Property, Plant and Equipment		275,014	159,345
Public Utilities, Property, Plant and Equipment Grant		0	(99,100)
Capital leases, net of accumulated amortization	[1]	1,129	645
Less: Accumulated depreciation and amortization		(5,131,966)	(4,927,602)
Subtotal		9,330,746	8,738,278
Construction work in progress		495,937	420,278
Net utility plant		$ 9,826,683	$ 9,158,556
[1]	Accumulated amortization of capital leases at Puget Energy and PSE was $0.7 million in 2017 and $0.6 million in 2016.

Utility Plant - Jointly Owned U

Utility Plant - Jointly Owned Utility Plant (Details) $ in Thousands	Dec. 31, 2017USD ($)
Colstrip Units 1 & 2
Jointly Owned Utility Plant Interests
Plant in Service at Cost	$ 246,510
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	(23)
Accumulated Depreciation	(38,170)
Colstrip Units 3 & 4
Jointly Owned Utility Plant Interests
Plant in Service at Cost	307,254
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	1,726
Accumulated Depreciation	(71,061)
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	(31)
Frederickson 1
Jointly Owned Utility Plant Interests
Plant in Service at Cost	61,783
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Accumulated Depreciation	(3,850)
Jackson Prairie [Member]
Jointly Owned Utility Plant Interests
Plant in Service at Cost	31,141
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	43
Accumulated Depreciation	$ (6,325)
Subsidiaries [Member] | Colstrip Units 1 & 2
Jointly Owned Utility Plant Interests
Company’s Ownership Share	50.00%
Plant in Service at Cost	$ 378,574
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	(23)
Accumulated Depreciation	$ (170,234)
Subsidiaries [Member] | Colstrip Units 3 & 4
Jointly Owned Utility Plant Interests
Company’s Ownership Share	25.00%
Plant in Service at Cost	$ 571,604
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	1,726
Accumulated Depreciation	(335,414)
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	$ (199)
Subsidiaries [Member] | Frederickson 1
Jointly Owned Utility Plant Interests
Company’s Ownership Share	49.85%
Plant in Service at Cost	$ 67,851
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Accumulated Depreciation	$ (9,917)
Subsidiaries [Member] | Jackson Prairie [Member]
Jointly Owned Utility Plant Interests
Company’s Ownership Share	33.34%
Plant in Service at Cost	$ 45,288
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	43
Accumulated Depreciation	$ (20,471)
Subsidiaries [Member] | Tacoma LNG [Member]
Jointly Owned Utility Plant Interests
Company’s Ownership Share	43.00%
Plant in Service at Cost	$ 2,667
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	87,207
Accumulated Depreciation	$ 0

Utility Plant - Asset Retiremen

Utility Plant - Asset Retirement Obligation (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Sep. 06, 2016
number of agreements			2
Subsidiaries [Member]
Decommissioning Liability, Noncurrent	$ 3,800
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of period	200,345	$ 85,028
Costs Incurred, Asset Retirement Obligation Incurred	2,881	0
Asset Retirement Obligation, Liabilities Incurred	(3,841)	(411)
Asset Retirement Obligation, Revision of Estimate	(13,748)	113,081
Asset Retirement Obligation, Accretion Expense	5,539	2,647
Asset retirement obligation at end of period	191,176	200,345
Colstrip Units 1 and 2 [Member] | Subsidiaries [Member]
Decommissioning Liability, Noncurrent	5,500	45,700
Colstrip Units 3 and 4 [Member] | Subsidiaries [Member]
Decommissioning Liability, Noncurrent	12,700	$ 37,000
Tacoma LNG [Member] | Subsidiaries [Member]
Decommissioning Liability, Noncurrent	2,700
Tacoma LNG [Member] | Puget LNG [Member]
Decommissioning Liability, Noncurrent	$ 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, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 01, 2017	Jun. 15, 2017
Debt Instrument [Line Items]
Current borrowing capacity of line of credit		$ 800,000
Proceeds from long-term debt and bonds issued		90,120	$ 12,481	$ 825,000
Total PSE long-term debt		5,678,872
Long Term Debt, Reconciliation, Fair Value Adjustment		(190,895)	(199,436)
Long-term Line of Credit, Noncurrent		102,600	12,480
Unamortized discount on senior notes		(3,687)	(6,269)
Net PSE long-term debt		$ 5,457,929	5,354,073
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		0	0	$ 425,000
Total PSE long-term debt		3,776,272
Unamortized discount on senior notes		(26,361)	(28,974)
Net PSE long-term debt		$ 3,749,911	3,747,298
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%			5.50%
Total PSE long-term debt	[1]	$ 2,412	2,412		$ 2,400
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 Notes | 6.974% Series Due 2067
Debt Instrument [Line Items]
Stated interest rate percent		6.974%
Total PSE long-term debt		$ 250,000	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	[2]	$ 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 | 4.700% Series Due 2051
Debt Instrument [Line Items]
Stated interest rate percent		4.70%
Total PSE long-term debt		$ 45,000	$ 45,000
[1]	2 5.50% Promissory Note (Puget Western Note Payable) in the amount of $2.4 million was classified on the Balance Sheet as a current maturity of long-term debt from January 1, 2017 to August 13, 2017, at which time the agreement was amended and extended until August 13, 2020. The Promissory Note is currently classified as long-term debt on the Balance sheet as of September 1, 2017.
[2]	Accumulated amortization of capital leases at Puget Energy and PSE was $0.7 million in 2017 and $0.6 million in 2016.

Long-Term Debt (Narrative) (Det

Long-Term Debt (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term debt	$ 5,678,872
Current borrowing capacity of line of credit	800,000
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%
Subsidiaries [Member]
Debt Instrument [Line Items]
Long-term debt	$ 3,776,272
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%

Long-Term Debt (Schedule of Mat

Long-Term Debt (Schedule of Maturities of Long-Term Debt) (Details) $ in Thousands	Dec. 31, 2017USD ($)
Maturities of Long-term Debt [Abstract]
2,016	$ 200,000
2,017	0
2,018	452,412
2,019	500,000
2,020	552,600
Thereafter	3,973,860
Total long-term debt	5,678,872
Subsidiaries [Member]
Maturities of Long-term Debt [Abstract]
2,016	200,000
2,017	0
2,018	2,412
2,019	0
2,020	0
Thereafter	3,573,860
Total long-term debt	3,776,272
Parent Company [Member]
Maturities of Long-term Debt [Abstract]
2,016	0
2,017	0
2,018	450,000
2,019	500,000
2,020	552,600
Thereafter	400,000
Total long-term debt	$ 1,902,600

Liquidity Facilities and Othe53

Liquidity Facilities and Other Financing Arrangements (Details) - USD ($)	Feb. 10, 2012	Dec. 31, 2017	Oct. 10, 2017	Dec. 31, 2016	Dec. 31, 2015
Short-term Debt [Line Items]
Short-term debt		$ 329,463,000		$ 245,763,000
Line of Credit Facility, Maximum Borrowing Capacity		1,300,000,000
Current borrowing capacity of line of credit		800,000,000
Long-term Line of Credit, Noncurrent		102,600,000		12,480,000
Senior secured credit facility
Short-term Debt [Line Items]
Short-term debt		0			$ 0
Subsidiaries [Member]
Short-term Debt [Line Items]
Short-term debt		$ 329,463,000		$ 245,763,000	$ 245,800,000
Weighted-average interest rate on short-term debt (percent)		3.50%		3.20%
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] | 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		329,500,000
Current borrowing capacity of line of credit		3,100,000
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
Subsidiaries [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Current Same-Day Borrowing Capacity		$ 75,000,000
Line of Credit Facility, Maximum Borrowing Capacity		$ 1,400,000,000
Subsidiaries [Member] | Working Capital Needs
Short-term Debt [Line Items]
Current borrowing capacity of line of credit			$ 800,000,000
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			$ 102,600,000
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, 2017	Dec. 31, 2016	Dec. 31, 2015
Subsidiaries [Member]
Operating Leases, Rent Expense, Net [Abstract]
Operating lease expense net of sublease receipts	$ 35,198	$ 31,786	$ 27,843

Leases (Schedule of Future Mini

Leases (Schedule of Future Minimum Lease Payments for Non-cancellable Leases) (Details) - Subsidiaries [Member] $ in Thousands	Dec. 31, 2017USD ($)
Operating
2,014	$ 21,371
2,015	19,077
2,016	17,507
2,017	9,137
2,018	6,747
Thereafter	97,974
Total minimum lease payments	171,813
Capital
2,014	527
2,015	306
2,016	232
2,017	97
2,018	0
Thereafter	0
Total minimum lease payments	$ 1,162

Accounting for Derivative Ins56

Accounting for Derivative Instruments and Hedging Activities (Narrative) (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Electric Portfolio
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value		$ 2,639	$ 0
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		99.50%
External Credit Rating, Non Investment Grade [Member] | Electric Portfolio
Derivative [Line Items]
Percentage of derivatives with credit risk exposure		0.50%
Credit Rating
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value		$ 2,600
Credit Rating | Electric Portfolio
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	[1]	$ 0	$ 0
[1]	Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral.

Accounting for Derivative Ins57

Accounting for Derivative Instruments and Hedging Activities (Schedule of Derivative Assets and Liabilities) (Details) $ in Thousands, MWh in Millions, MMBTU in Millions		Dec. 31, 2017USD ($)MWhMMBTU	Dec. 31, 2016USD ($)MWhMMBTU
Derivative [Line Items]
Assets, Current		$ 22,247	$ 54,341
Assets, Long-term		2,158	8,738
Liabilities, Current		64,859	44,310
Liabilities, Long-term		21,235	16,261
Parent Company [Member]
Derivative [Line Items]
Liabilities, Current		0	141
Subsidiaries [Member]
Derivative [Line Items]
Assets, Current		22,247	54,341
Assets, Long-term		2,158	8,738
Liabilities, Current		64,859	44,170
Liabilities, Long-term		21,235	16,261
Energy derivative contracts
Derivative [Line Items]
Gross Amounts Recognized in the Statement of Financial Position 1		24,405	63,079
Total derivative assets		24,405	63,079
Total derivative liabilities		86,094	60,430
Interest Rate Contract
Derivative [Line Items]
Total derivative liabilities			141
Not Designated as Hedging Instrument
Derivative [Line Items]
Total derivative assets	[1]	24,405	63,079
Total derivative liabilities	[2]	86,094	60,571
Not Designated as Hedging Instrument | Parent Company [Member]
Derivative [Line Items]
Assets, Current	[1]	22,247	54,341
Assets, Long-term	[1]	2,158	8,738
Liabilities, Current	[2]	64,859	44,310
Liabilities, Long-term	[2]	21,235	16,261
Not Designated as Hedging Instrument | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	[3]	0	450,000
Total derivative assets	[1],[3]	0	0
Total derivative liabilities	[2],[3]	$ 0	$ 141
Not Designated as Hedging Instrument | Electric Generation Fuel
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU		166.8	186.8
Not Designated as Hedging Instrument | Purchased Electricity
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MWh		2.9	3.6
Not Designated as Hedging Instrument | Electric Portfolio
Derivative [Line Items]
Total derivative assets	[1]	$ 13,391	$ 36,460
Total derivative liabilities	[2]	49,050	41,329
Not Designated as Hedging Instrument | Natural Gas Portfolio
Derivative [Line Items]
Total derivative assets	[1],[4]	11,014	26,619
Total derivative liabilities	[2],[4]	$ 37,044	$ 19,101
Not Designated as Hedging Instrument | Gas Derivatives
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	[4]	332.1	336.4
[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]	Interest rate swap contracts are only held at Puget Energy and matured in January 2017.
[4]	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.

Accounting for Derivative Ins58

Accounting for Derivative Instruments and Hedging Activities (Schedule of Amounts Recognized in Statement of Income) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		$ 30,790	$ (83,795)	$ (13,233)
Subsidiaries [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		30,790	(83,795)	(12,688)
Not Designated as Hedging Instrument
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		71,830	(21,079)	73,788
Not Designated as Hedging Instrument | Other Income (Deductions) | Interest Expense
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		(28)	1,062	3,796
Not Designated as Hedging Instrument | Interest Rate Contract | Interest Expense
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		0	0	(560)
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		32,492	(62,318)	9,315
Not Designated as Hedging Instrument | Energy derivative contracts | Electric Generation Fuel
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		23,195	39,656	44,648
Not Designated as Hedging Instrument | Energy derivative contracts | Purchased Electricity
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		17,873	21,998	39,137
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	[1]	(1,702)	(21,477)	(22,548)
Not Designated as Hedging Instrument | Subsidiaries [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		71,858	(22,141)	71,097
Not Designated as Hedging Instrument | Subsidiaries [Member] | Energy Related Derivative [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		32,492	(62,318)	9,315
Not Designated as Hedging Instrument | Subsidiaries [Member] | Energy derivative contracts | Electric Generation Fuel
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		23,195	39,656	44,648
Not Designated as Hedging Instrument | Subsidiaries [Member] | Energy derivative contracts | Purchased Electricity
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		17,873	21,998	39,137
Not Designated as Hedging Instrument | Subsidiaries [Member] | Electric [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	[1]	$ (1,702)	$ (21,477)	$ (22,003)
[1]	Differences between Puget Energy and PSE for the twelve months ended December 31, 2015 are due to certain derivative contracts recorded at fair value in 2009 and subsequently designated as NPNS or cash flow hedges. These differences occurred through February 2015.

Accounting for Derivative Ins59

Accounting for Derivative Instruments and Hedging Activities (Schedule of Amounts Recognized in Other Comprehensive Income) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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	$ (512)

Accounting for Derivative Ins60

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		$ (30,790)	$ 83,795	$ 13,233
Derivative contracts classified as financing activities due to merger		0	0	(8,045)
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		(71,830)	21,079	(73,788)
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		(32,492)	62,318	(9,315)
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	560
Not Designated as Hedging Instrument | Commodity contracts: | Electric Generation Fuel
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		(23,195)	(39,656)	(44,648)
Not Designated as Hedging Instrument | Commodity contracts: | Purchased Electricity
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		(17,873)	(21,998)	(39,137)
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	[1]	1,702	21,477	22,548
Subsidiaries [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		(30,790)	83,795	12,688
Subsidiaries [Member] | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		(71,858)	22,141	(71,097)
Subsidiaries [Member] | 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		(32,492)	62,318	(9,315)
Subsidiaries [Member] | Not Designated as Hedging Instrument | Commodity contracts: | Electric Generation Fuel
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		(23,195)	(39,656)	(44,648)
Subsidiaries [Member] | Not Designated as Hedging Instrument | Commodity contracts: | Purchased Electricity
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		(17,873)	(21,998)	(39,137)
Subsidiaries [Member] | 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	[1]	$ 1,702	$ 21,477	$ 22,003
[1]	Differences between Puget Energy and PSE for the twelve months ended December 31, 2015 are due to certain derivative contracts recorded at fair value in 2009 and subsequently designated as NPNS or cash flow hedges. These differences occurred through February 2015.

Accounting for Derivative Ins61

Accounting for Derivative Instruments and Hedging Activities (Schedule of Contractual Contingent Liability Positions) (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Electric Portfolio
Derivative [Line Items]
Fair Value Liability	[1]	$ 40,914	$ 12,828
Collateral Already Posted, Aggregate Fair Value		2,639	0
Contingent Collateral		3,187	4,894
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	[1],[2]	353	507
Collateral Already Posted, Aggregate Fair Value	[2]	2,639	0
Contingent Collateral	[2]	0	0
Requested Credit for Adequate Assurance | Electric Portfolio
Derivative [Line Items]
Fair Value Liability	[1]	37,374	7,427
Collateral Already Posted, Aggregate Fair Value		0	0
Contingent Collateral		0	0
Credit Rating
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value		2,600
Credit Rating | Electric Portfolio
Derivative [Line Items]
Fair Value Liability	[1],[3]	3,187	4,894
Collateral Already Posted, Aggregate Fair Value	[3]	0	0
Contingent Collateral	[3]	$ 3,187	$ 4,894
[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]	3 Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.
[3]	Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral.

Accounting for Derivative Ins62

Accounting for Derivative Instruments and Hedging Activities (Offsetting) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Energy derivative contracts
Assets:
Gross Amounts Recognized in the Statement of Financial Position 1	$ 24,405	$ 63,079
Gross Amounts Offset in the Statement of Financial Position	0	0
Net of Amounts Presented in the Statement of Financial Position	24,405	63,079
Commodity Contracts	17,940	42,858
Cash Collateral Received/Posted	0	0
Net Amount	6,465	20,221
Liabilities:
Gross Amounts Recognized in the Statement of Financial Position 1	86,094	60,430
Gross Amounts Offset in the Statement of Financial Position	0	0
Net of Amounts Presented in the Statement of Financial Position	86,094	60,430
Commodity Contracts	17,940	42,858
Cash Collateral Received/Posted	353	0
Net Amount	$ 67,801	17,572
Interest rate swaps
Liabilities:
Gross Amounts Recognized in the Statement of Financial Position 1		141
Gross Amounts Offset in the Statement of Financial Position		0
Net of Amounts Presented in the Statement of Financial Position		141
Commodity Contracts		0
Cash Collateral Received/Posted		0
Net Amount		$ 141

Fair Value Measurements - Asset

Fair Value Measurements - Assets and Liabilities Measured on Recurring Basis (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Interest Rate Contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities			$ 141
Fair Value, Measurements, Recurring | Parent Company [Member] | Level 2 | Interest Rate Contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		$ 0	141
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	[1]	3,525
Derivative Liabilities	[1]	2,427
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	[1]	4,041
Derivative Liabilities	[1]	2,118
Fair Value, Measurements, Recurring | Parent Company [Member] | Level 3 | Interest Rate Contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		0	0
Fair Value, Measurements, Recurring | Parent Company [Member] | Total | Interest Rate Contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		0	141
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		16,839	53,982
Derivative Liabilities		81,549	53,071
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		9,866	30,666
Derivative Liabilities		46,623	36,507
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		6,973	23,316
Derivative Liabilities		34,926	16,423
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		7,566	9,097
Derivative Liabilities		4,545	7,500
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			5,794
Derivative Liabilities			4,822
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			3,303
Derivative Liabilities			2,678
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Total
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		24,405	63,079
Derivative Liabilities		86,094	60,571
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Total | Electric Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		13,391	36,460
Derivative Liabilities		49,050	41,329
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Total | Natural Gas Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		11,014	26,619
Derivative Liabilities		37,044	19,101
Carrying Amount | Parent Company [Member] | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Notes receivable and other		$ 48,500	$ 49,100
[1]	The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

Fair Value Measurements - Debt

Fair Value Measurements - Debt at Carrying and Fair Value (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
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		$ 3,749,911	$ 3,747,298
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	27,200
Junior subordinated notes		250,000	250,000
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[1]	3,499,911	3,497,298
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		4,789,065	4,571,044
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		238,935	210,261
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[1]	4,550,130	4,360,783
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		48,500	49,100
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		5,457,929	5,354,073
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		27,900	33,000
Junior subordinated notes		250,000	250,000
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[2]	5,105,329	5,091,593
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure		102,600	12,480
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		6,862,050	6,560,028
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		238,935	210,261
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[2]	6,520,515	6,337,287
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure		$ 102,600	$ 12,480
[1]	2 The carrying value includes debt issuances costs of $24.6 million and $27.2 million for December 31, 2017 and 2016, respectively, which are not included in fair value.
[2]	1 The carrying value includes debt issuances costs of $27.9 million and $33.0 million for December 31, 2017 and 2016, respectively, which are not included in fair value.

Fair Value Measurements - Unobs

Fair Value Measurements - Unobservable Input Reconciliation (Details)		3 Months Ended		9 Months Ended	12 Months Ended
		Mar. 31, 2017USD ($)$ / MWh	Mar. 31, 2016USD ($)$ / MWh	Sep. 30, 2017USD ($)$ / MWh	Dec. 31, 2017USD ($)$ / MWh	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		$ 1,597,000	$ (9,728,000)	$ 1,597,000	$ 1,597,000	$ (9,728,000)	$ (14,102,000)
Included in earnings	[1]				2,781,000	4,007,000	(6,432,000)
Included in regulatory assets / liabilities					6,346,000	4,312,000	3,695,000
Settlements	[2]				(12,921,000)	(3,808,000)	(2,983,000)
Transferred into Level 3					(30,000)	(3,021,000)	(787,000)
Transferred out of Level 3					5,248,000	9,835,000	10,881,000
Balance at end of period					3,021,000	1,597,000	(9,728,000)
Electric Portfolio
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		972,000	(7,345,000)	972,000	972,000	(7,345,000)	(12,062,000)
Included in earnings	[1]				2,781,000	4,007,000	(6,432,000)
Included in regulatory assets / liabilities					0	0	0
Settlements	[2]				(6,549,000)	(1,129,000)	902,000
Transferred into Level 3					523,000	(3,021,000)	(787,000)
Transferred out of Level 3					3,371,000	8,460,000	11,034,000
Balance at end of period					1,098,000	972,000	(7,345,000)
Unrealized gain (loss) on derivative instruments, net					1,500,000	2,000,000	(7,400,000)
Natural Gas Portfolio
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		$ 625,000	$ (2,383,000)	$ 625,000	625,000	(2,383,000)	(2,040,000)
Included in earnings	[1]				0	0	0
Included in regulatory assets / liabilities					6,346,000	4,312,000	3,695,000
Settlements	[2]				(6,372,000)	(2,679,000)	(3,885,000)
Transferred into Level 3					(553,000)	0	0
Transferred out of Level 3					1,877,000	1,375,000	(153,000)
Balance at end of period					$ 1,923,000	$ 625,000	$ (2,383,000)
Income Approach Valuation Technique | Minimum | Electric Portfolio
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh					7.02
Income Approach Valuation Technique | Minimum | Wells Project1
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh		8.76	9.46	14.06
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair Value Inputs, Power Contract Costs		$ 3,965	$ 4,100	$ 4,126
Income Approach Valuation Technique | Maximum | Electric Portfolio
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh					28.94
Income Approach Valuation Technique | Maximum | Wells Project1
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh		26.70	25.96	26.86
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair Value Inputs, Power Contract Costs		$ 4,223	$ 4,659	$ 4,126
Income Approach Valuation Technique | Weighted Average | Electric Portfolio
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh					18.61
Income Approach Valuation Technique | Weighted Average | Wells Project1
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh		20.86	21.38	22.24
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair Value Inputs, Power Contract Costs		$ 4,051	$ 4,452	$ 4,126
[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 $1.5 million, $2.0 million and $(7.4) million for the years ended December 31, 2017, 2016 and 2015, respectively.
[2]	The Company had no purchases, sales or issuances during the reported periods.

Fair Value Measurements - Valua

Fair Value Measurements - Valuation Techniques (Details)		3 Months Ended			9 Months Ended		12 Months Ended
		Sep. 30, 2017USD ($)	Mar. 31, 2017USD ($)$ / MWh	Mar. 31, 2016USD ($)$ / MWh	Sep. 30, 2017USD ($)$ / MWh	Sep. 30, 2016USD ($)$ / MWh	Dec. 31, 2017USD ($)$ / MMBTU$ / MWh	Dec. 31, 2016USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of Intangible Assets (Excluding Goodwill)				$ 5,338,000		$ 12,778,000	$ 81,345,000	$ 18,116,000
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							$ (900,000)
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							24,405,000	63,079,000
Net of Amounts Presented in the Statement of Financial Position							$ 86,094,000	$ 60,430,000
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							1.22
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							2.80
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							1.54
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	[1]						$ 4,041,000
Net of Amounts Presented in the Statement of Financial Position	[1]						$ 2,118,000
Electric Portfolio | Income Approach Valuation Technique | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh							7.02
Electric Portfolio | Income Approach Valuation Technique | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh							28.94
Electric 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 Megawatt-Hour | $ / MWh							18.61
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	[1]						$ 3,525,000
Net of Amounts Presented in the Statement of Financial Position	[1]						$ 2,427,000
Wells Project1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite-Lived Intangible Assets, Net		$ 10,621,000	$ 14,879,000	$ 25,193,000	$ 10,621,000
Impairment of Intangible Assets (Excluding Goodwill)		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]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh			8.76	9.46	14.06
Fair Value Inputs, Power Contract Costs			$ 3,965	$ 4,100	$ 4,126
Wells Project1 | Income Approach Valuation Technique | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh			26.70	25.96	26.86
Fair Value Inputs, Power Contract Costs			$ 4,223	$ 4,659	$ 4,126
Wells Project1 | Income Approach Valuation Technique | Weighted Average
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh			20.86	21.38	22.24
Fair Value Inputs, Power Contract Costs			$ 4,051	$ 4,452	$ 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]
Fair Value Inputs, Price Per Megawatt-Hour | $ / 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]
Fair Value Inputs, Price Per Megawatt-Hour | $ / 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]
Fair Value Inputs, Price Per Megawatt-Hour | $ / 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			$ 18,969,000
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]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh			13.70			24.24
Fair Value Inputs, Power Contract Costs			$ 620			$ 618
Priest Rapids Development | Income Approach Valuation Technique | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh			29.38			58.96
Fair Value Inputs, Power Contract Costs			$ 4,022			$ 4,633
Priest Rapids Development | Income Approach Valuation Technique | Weighted Average
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh			23.14			39.31
Fair Value Inputs, Power Contract Costs			$ 2,306			$ 2,472
Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure				$ 19,855,000		$ 6,191,000
Carrying Amount | Wells Project1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure		$ 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
[1]	The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

Employee Investment Plans (Deta

Employee Investment Plans (Details) - Subsidiaries [Member] $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Defined Contribution Plan
Employer matching contribution, percent	1.00%	4.00%
Employer discretionary contribution amount		$ 19.2	$ 17.2	$ 16.1
Defined Contribution Plan, Vesting Years	3	3
6 percent
Defined Contribution Plan
Employer matching contribution, percent		4.50%
Maximum annual contribution per employee, percent		6.00%
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%
Cash Balance Formula | First 3 Percent
Defined Contribution Plan
Employer matching contribution, percent		100.00%
Maximum annual contribution per employee, percent		3.00%
Cash Balance Formula | Second 3 Percent
Defined Contribution Plan
Employer matching contribution, percent		50.00%
Maximum annual contribution per employee, percent		3.00%
Final Average Earnings Formula
Defined Contribution Plan
Employer matching contribution, percent		55.00%
Maximum annual contribution per employee, percent		6.00%

Retirement Benefits - Change in

Retirement Benefits - Change in Net Benefit Obligation and Fair Value (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Benefits
Change in benefit obligation:
Benefit obligation at beginning of period	$ 11,194	$ 13,946
Service cost	72	93
Interest cost	500	533
Actuarial loss (gain)	725	(2,262)
Benefits paid	(1,137)	(1,264)
Medicare part D subsidy received	100	148
Defined Benefit Plan, Expected Administration Expenses	0	0
Benefit obligation at end of period	11,454	11,194	$ 13,946
Change in plan assets:
Fair value of plan assets at beginning of period	7,200	7,203
Actual return on plan assets	784	926
Employer contribution	291	335
Benefits paid	(1,137)	(1,264)
Defined Benefit Plan, Plan Assets, Administration Expense	0	0
Fair value of plan assets at end of period	7,138	7,200	7,203
Funded status at end of period	(4,316)	(3,994)
Subsidiaries [Member] | Other Benefits
Change in benefit obligation:
Service cost	72	93	112
Interest cost	500	533	621
Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring | Qualified Pension Benefits
Change in plan assets:
Fair value of plan assets at beginning of period	621,886
Fair value of plan assets at end of period	704,360	621,886
Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring | Other Benefits
Change in plan assets:
Fair value of plan assets at beginning of period	7,262
Fair value of plan assets at end of period	7,138	7,262
Estimate of Fair Value Measurement [Member] | Net Receivables [Member] | Fair Value, Measurements, Recurring | Qualified Pension Benefits
Change in plan assets:
Fair value of plan assets at beginning of period	(9,894)
Fair value of plan assets at end of period	50,959	(9,894)
Nonqualified Plan | Qualified Pension Benefits
Change in benefit obligation:
Benefit obligation at beginning of period	51,734	51,279
Service cost	913	1,085
Interest cost	2,285	2,325
Actuarial loss (gain)	2,722	106
Benefits paid	(1,900)	(3,061)
Medicare part D subsidy received	0	0
Defined Benefit Plan, Expected Administration Expenses	0	0
Benefit obligation at end of period	55,754	51,734	51,279
Change in plan assets:
Fair value of plan assets at beginning of period	0	0
Actual return on plan assets	0	0
Employer contribution	1,900	3,061
Benefits paid	(1,900)	(3,061)
Defined Benefit Plan, Plan Assets, Administration Expense	0	0
Fair value of plan assets at end of period	0	0	0
Funded status at end of period	(55,754)	(51,734)
Nonqualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Change in benefit obligation:
Service cost	913	1,085	1,108
Interest cost	2,285	2,325	2,281
Qualified Plan | Qualified Pension Benefits
Change in benefit obligation:
Benefit obligation at beginning of period	652,607	643,088
Service cost	20,081	18,913
Interest cost	28,373	28,689
Actuarial loss (gain)	40,945	1,545
Benefits paid	(40,594)	(38,730)
Medicare part D subsidy received	0	0
Defined Benefit Plan, Expected Administration Expenses	(931)	(898)
Benefit obligation at end of period	700,481	652,607	643,088
Change in plan assets:
Fair value of plan assets at beginning of period	620,260	598,865
Actual return on plan assets	107,836	37,022
Employer contribution	18,000	24,000
Benefits paid	(40,594)	(38,730)
Defined Benefit Plan, Plan Assets, Administration Expense	(1,142)	(897)
Fair value of plan assets at end of period	704,360	620,260	598,865
Funded status at end of period	3,879	(32,347)
Qualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Change in benefit obligation:
Service cost	20,081	18,913	21,287
Interest cost	$ 28,373	$ 28,689	$ 28,088

Retirement Benefits - Amounts R

Retirement Benefits - Amounts Recognized (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation		$ 11,454	$ 11,194	$ 13,946
Defined Benefit Plan, Accumulated Benefit Obligation		11,367	11,092
Defined Benefit Plan, Fair Value of Plan Assets		7,138	7,200	7,203
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets		0	0
Current liabilities		(317)	(325)
Noncurrent liabilities		(3,999)	(3,669)
Net assets (liabilities)		(4,316)	(3,994)
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)		403	(2,742)
Amortization of net (loss) gain		401	385
Amortization of prior service (cost) credit		0	0
Total change in other comprehensive income for year		804	(2,357)
Parent Company [Member] | Other Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)		(3,386)	(4,190)
Prior service cost (credit)		0	0
Total		(3,386)	(4,190)
Subsidiaries [Member] | Other Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)		(4,901)	(5,994)
Prior service cost (credit)		0	0
Total		(4,901)	(5,994)
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)		452	(2,742)
Amortization of net (loss) gain		641	631
Amortization of prior service (cost) credit		0	0
Total change in other comprehensive income for year		1,093	(2,111)
Nonqualified Plan | Qualified Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation		55,754	51,734	51,279
Defined Benefit Plan, Accumulated Benefit Obligation		52,681	47,639
Defined Benefit Plan, Fair Value of Plan Assets		0	0	0
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets		0	0
Current liabilities		(5,486)	(1,911)
Noncurrent liabilities		(50,268)	(49,823)
Net assets (liabilities)		(55,754)	(51,734)
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)		2,722	106
Amortization of net (loss) gain		(1,076)	(910)
Amortization of prior service (cost) credit		(42)	(42)
Total change in other comprehensive income for year		1,604	(846)
Nonqualified Plan | Parent Company [Member] | Qualified Pension Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)		10,689	9,043
Prior service cost (credit)		204	246
Total		10,893	9,289
Nonqualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)		13,134	11,978
Prior service cost (credit)		208	251
Total		13,342	12,229
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)		2,722	106
Amortization of net (loss) gain		(1,565)	(1,330)
Amortization of prior service (cost) credit		(44)	(44)
Total change in other comprehensive income for year		1,113	(1,268)
Qualified Plan | Qualified Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation		700,481	652,607	643,088
Defined Benefit Plan, Accumulated Benefit Obligation		688,908	641,855
Defined Benefit Plan, Fair Value of Plan Assets		704,360	620,260	$ 598,865
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets		3,879	0
Current liabilities		0	0
Noncurrent liabilities		0	(32,347)
Net assets (liabilities)		3,879	(32,347)
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)		(18,896)	11,141
Amortization of net (loss) gain		0	0
Amortization of prior service (cost) credit		1,980	1,980
Total change in other comprehensive income for year		(16,916)	13,121
Qualified Plan | Parent Company [Member] | Qualified Pension Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)		37,693	56,588
Prior service cost (credit)		(7,843)	(9,822)
Total		29,850	46,766
Qualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)		185,277	217,143
Prior service cost (credit)		(6,232)	(7,806)
Total		179,045	209,337
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)		(18,817)	11,336
Amortization of net (loss) gain		(13,048)	(15,257)
Amortization of prior service (cost) credit		1,573	1,573
Total change in other comprehensive income for year		$ (30,292)	$ (2,348)
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	$ (1,100)
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	600
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	(2,100)
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	$ (14,500)

Retirement Benefits - Net Perio

Retirement Benefits - Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Benefits
Components of net periodic benefit cost:
Service cost	$ 72	$ 93
Interest cost	500	533
Parent Company [Member] | Other Benefits
Components of net periodic benefit cost:
Service cost	72	93	$ 112
Interest cost	500	533	621
Expected return on plan assets	(461)	(446)	(531)
Amortization of prior service cost (credit)	0	0	0
Amortization of net loss (gain)	(402)	(386)	(130)
Net periodic benefit cost	(291)	(206)	72
Subsidiaries [Member] | Other Benefits
Components of net periodic benefit cost:
Service cost	72	93	112
Interest cost	500	533	621
Expected return on plan assets	(461)	(446)	(531)
Amortization of prior service cost (credit)	0	0	3
Amortization of net loss (gain)	(641)	(632)	(406)
Net periodic benefit cost	(530)	(452)	(201)
Nonqualified Plan | Qualified Pension Benefits
Components of net periodic benefit cost:
Service cost	913	1,085
Interest cost	2,285	2,325
Nonqualified Plan | Parent Company [Member] | Qualified Pension Benefits
Components of net periodic benefit cost:
Service cost	913	1,085	1,108
Interest cost	2,285	2,325	2,281
Expected return on plan assets	0	0	0
Amortization of prior service cost (credit)	42	42	42
Amortization of net loss (gain)	1,077	911	1,641
Net periodic benefit cost	4,317	4,363	5,072
Nonqualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Components of net periodic benefit cost:
Service cost	913	1,085	1,108
Interest cost	2,285	2,325	2,281
Expected return on plan assets	0	0	0
Amortization of prior service cost (credit)	44	44	44
Amortization of net loss (gain)	1,565	1,330	2,120
Net periodic benefit cost	4,807	4,784	5,553
Qualified Plan | Qualified Pension Benefits
Components of net periodic benefit cost:
Service cost	20,081	18,913
Interest cost	28,373	28,689
Qualified Plan | Parent Company [Member] | Qualified Pension Benefits
Components of net periodic benefit cost:
Service cost	20,081	18,913	21,287
Interest cost	28,373	28,689	28,088
Expected return on plan assets	(47,784)	(46,619)	(45,038)
Amortization of prior service cost (credit)	(1,980)	(1,980)	(1,980)
Amortization of net loss (gain)	0	0	3,887
Net periodic benefit cost	(1,310)	(997)	6,244
Qualified Plan | Subsidiaries [Member] | Qualified Pension Benefits
Components of net periodic benefit cost:
Service cost	20,081	18,913	21,287
Interest cost	28,373	28,689	28,088
Expected return on plan assets	(47,862)	(46,814)	(45,462)
Amortization of prior service cost (credit)	(1,573)	(1,573)	(1,573)
Amortization of net loss (gain)	13,048	15,257	20,555
Net periodic benefit cost	$ 12,067	$ 14,472	$ 22,895

Retirement Benefits - Assumptio

Retirement Benefits - Assumptions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2018
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates
1% Increase, Effect on post-retirement benefit obligation		$ 23	$ 38
1% Decrease, Effect on post-retirement benefit obligation		(22)	(35)
1% Increase, Effect on service and interest cost components		1	2
1% Decrease, Effect on service and interest cost components		$ (1)	$ (2)
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Current and Prior Fiscal Year		1.00%
Other Benefits
Benefit Obligation Assumptions
Discount rate		4.00%	4.50%	4.65%
Rate of compensation increase		4.50%	4.50%	4.50%
Medical trend rate		6.80%	8.80%	7.20%
Benefit Cost Assumptions
Discount rate		4.50%	4.65%	4.25%
Return on plan assets		6.75%	6.75%	7.00%
Rate of compensation increase		4.50%	4.50%	4.50%
Medical trend rate		9.50%	5.30%	7.20%
Nonqualified Plan | Qualified Pension Benefits
Benefit Obligation Assumptions
Discount rate		4.00%	4.50%	4.65%
Rate of compensation increase		4.50%	4.50%	4.50%
Medical trend rate		0.00%	0.00%	0.00%
Benefit Cost Assumptions
Discount rate		4.50%	4.65%	4.25%
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		4.00%	4.50%	4.65%
Rate of compensation increase		4.50%	4.50%	4.50%
Medical trend rate		0.00%	0.00%	0.00%
Benefit Cost Assumptions
Discount rate		4.50%	4.65%	4.25%
Return on plan assets		7.45%	7.75%	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					6.80%
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	4.10%

Retirement Benefits - Future Be

Retirement Benefits - Future Benefit Payments (Details) $ in Thousands	Dec. 31, 2017USD ($)
Other Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,016	$ 911
2,017	885
2,018	852
2,019	811
2,020	863
2021-2025	3,748
2016, without Medicare Part D subsidy	1,172
2017, without Medicare Part D subsidy	1,155
2018, without Medicare Part D subsidy	1,131
2019, without Medicare Part D subsidy	1,097
2020, without Medicare Part D subsidy	1,070
2021-2025, without Medicare Part D subsidy	4,844
Qualified Plan | Qualified Pension Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,016	42,600
2,017	43,400
2,018	44,800
2,019	45,700
2,020	46,900
2021-2025	246,500
Nonqualified Plan | Qualified Pension Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,016	5,486
2,017	6,001
2,018	4,684
2,019	1,728
2,020	4,577
2021-2025	$ 37,394

Retirement Benefits - Plan Asse

Retirement Benefits - Plan Asset Allocation (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
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] | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 704,360	$ 621,886
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, Fair Value of Plan Assets		348,300	354,221
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, Fair Value of Plan Assets		67,674	54,740
Fair Value, Measurements, Recurring | Equities: | Pension Plan [Member] | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		415,974	408,961
Fair Value, Measurements, Recurring | Fair Value Measurement [Domain] | Pension Plan [Member] | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		237,427	222,819
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, Fair Value of Plan Assets	[1]	117,796	181,212
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, Fair Value of Plan Assets	[1]	0	0
Fair Value, Measurements, Recurring | Mutual Funds | Pension Plan [Member] | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[1]	117,796	181,212
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, Fair Value of Plan Assets		209,504	154,255
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, Fair Value of Plan Assets		0	0
Fair Value, Measurements, Recurring | Common Stock | Pension Plan [Member] | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		209,504	154,255
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, Fair Value of Plan Assets		18,316	18,754
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, Fair Value of Plan Assets		23,782	16,197
Fair Value, Measurements, Recurring | US Treasury and Government [Member] | Pension Plan [Member] | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		42,098	34,951
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, Fair Value of Plan Assets		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, Fair Value of Plan Assets		34,588	38,543
Fair Value, Measurements, Recurring | Corporate Bond Securities [Member] | Pension Plan [Member] | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		34,588	38,543
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, Fair Value of Plan Assets		2,684	0
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, Fair Value of Plan Assets		9,304	0
Fair Value, Measurements, Recurring | Cash and cash equivalents | Pension Plan [Member] | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 11,988	$ 0
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
[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, 2017.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.

Retirement Benefits - Textuals

Retirement Benefits - Textuals (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017
Subsidiaries [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent	1.00%		4.00%
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)		$ (1.1)
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)		0.6
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)		(14.5)
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)		(2.1)
Estimated Future Employer Contributions in Current Fiscal Year		$ 5.5

Retirement Benefits Accumulated

Retirement Benefits Accumulated Benefit Obligation (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation		$ 11,454	$ 11,194	$ 13,946
Defined Benefit Plan, Accumulated Benefit Obligation		11,367	11,092
Defined Benefit Plan, Fair Value of Plan Assets		7,138	7,200	$ 7,203
Fair Value, Measurements, Recurring | Level 1 | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets
Fair Value, Measurements, Recurring | Level 1 | Mutual Funds | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[1]	117,796	181,212
Fair Value, Measurements, Recurring | Level 1 | Mutual Funds | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[2]	7,089	7,182
Fair Value, Measurements, Recurring | Level 1 | Cash and cash equivalents | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		2,684	0
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member] | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		704,360	621,886
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member] | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		7,138	7,262
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member] | Mutual Funds | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[1]	117,796	181,212
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member] | Mutual Funds | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[2]	7,089	7,182
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member] | Cash and cash equivalents | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		11,988	0
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member] | Fair Value Measurement [Domain] | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		237,427	222,819
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member] | Fair Value Measurement [Domain] | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[3]	49	80
Fair Value, Measurements, Recurring | Level 2 | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets
Fair Value, Measurements, Recurring | Level 2 | Mutual Funds | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[1]	0	0
Fair Value, Measurements, Recurring | Level 2 | Mutual Funds | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[2]	0	0
Fair Value, Measurements, Recurring | Level 2 | Cash and cash equivalents | Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 9,304	$ 0
[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, 2017.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.
[2]	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, 2017.
[3]	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, 2017.

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosures [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	35.00%
Other Deductions or Allowable Credits	$ 0.300
Current Federal Tax Expense (Benefit)	1,127,000	$ 0	$ 0
Current State and Local Tax Expense (Benefit)	17,000	20,000	0
Federal	254,420,000	140,315,000	91,968,000
State	(421,000)	(131,000)	(192,000)
Total income tax expense	255,143,000	140,204,000	91,776,000
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Revenue Change	51,200,000
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, effect on income tax expense	17,900,000
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Effect on Income Taxes due to revaluation	80,900,000
Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Current Federal Tax Expense (Benefit)	1,127,000	0	0
Current State and Local Tax Expense (Benefit)	17,000	20,000	0
Federal	210,842,000	175,327,000	125,900,000
State	0	0	0
Total income tax expense	211,986,000	$ 175,347,000	$ 125,900,000
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, unregulated portion	3,000,000
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, PTC revaluation	$ 33,300,000

Income Taxes - Income Tax Recon

Income Taxes - Income Tax Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosures [Line Items]
Current Federal Tax Expense (Benefit)	$ 1,127	$ 0	$ 0
Current State and Local Tax Expense (Benefit)	17	20	0
Federal	254,420	140,315	91,968
State	$ (421)	(131)	(192)
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	35.00%
Income Tax Reconciliation [Abstract]
Income taxes at the statutory rate	$ 148,847	158,586	116,534
Production tax credit1	0	(12,925)	(19,470)
Utility plant differences	0	3,966	5,671
Income Tax Reconciliation, Treasury Grant	(9,537)	(9,788)	(8,807)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	117,185	0	0
Other - net	(1,352)	365	(2,152)
Total income tax expense	$ 255,143	$ 140,204	$ 91,776
Effective tax rate	60.00%	30.90%	27.60%
Regulatory asset for income taxes	$ 0	$ 72,038
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)	1,127	0	$ 0
Current State and Local Tax Expense (Benefit)	17	20	0
Federal	210,842	175,327	125,900
State	0	0	0
Income Tax Reconciliation [Abstract]
Income taxes at the statutory rate	185,430	194,572	150,531
Production tax credit1	0	(12,925)	(19,470)
Utility plant differences	0	3,966	5,671
Income Tax Reconciliation, Treasury Grant	(9,537)	(9,788)	(8,807)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	36,328	0	0
Other - net	(235)	(478)	(2,025)
Total income tax expense	$ 211,986	$ 175,347	$ 125,900
Effective tax rate	40.00%	31.50%	29.30%
Regulatory asset for income taxes	$ 0	$ 71,517
Deferred Tax Assets, Regulatory Assets and Liabilities	$ (1,012,300)

Income Taxes - Deferred Income

Income Taxes - Deferred Income Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Deferred Tax Liabilities, Gross
Utility plant and equipment	$ 2,034,328	$ 1,880,782
Regulatory asset for income taxes	0	72,038
Fair value of debt instruments	38,777	67,444
Deferred Tax Liabilities, Pension and Other Compensation	46,338	77,230
Other deferred tax liabilities	86,933	119,050
Subtotal deferred tax liabilities	2,206,376	2,216,544
Deferred Tax Assets, Net Regulatory Liability for Income Taxes	(1,011,626)	0
Deferred Tax Assets, Gross
Net operating loss carryforward	(212,168)	(352,827)
Production tax credit carryforward	(187,617)	(190,999)
Regulatory liability on production tax credit	(49,873)	(101,787)
Deferred Tax Assets, Other	1,776	0
Subtotal deferred tax assets	(1,459,508)	(645,613)
Total net deferred tax liabilities	746,868	1,570,931
Subsidiaries [Member]
Deferred Tax Liabilities, Gross
Utility plant and equipment	2,034,328	1,880,782
Regulatory asset for income taxes	0	71,517
Other deferred tax liabilities	86,933	113,938
Subtotal deferred tax liabilities	2,121,261	2,066,237
Deferred Tax Assets, Net Regulatory Liability for Income Taxes	(1,012,260)	0
Deferred Tax Assets, Gross
Net operating loss carryforward	0	(41,061)
Production tax credit carryforward	(187,617)	(190,999)
Regulatory liability on production tax credit	(49,873)	(101,787)
Deferred Tax Assets, Other	(2,038)	0
Subtotal deferred tax assets	(1,251,788)	(333,847)
Total net deferred tax liabilities	$ 869,473	$ 1,732,390

Income Taxes - Balance Sheet Lo

Income Taxes - Balance Sheet Location (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosures [Line Items]
Non-current deferred taxes	$ 746,868	$ 1,570,931
Total net deferred tax liabilities	746,868	1,570,931
Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Non-current deferred taxes	869,473	1,732,390
Total net deferred tax liabilities	$ 869,473	$ 1,732,390

Litigation (Details)

Litigation (Details) $ in Millions	Jun. 19, 2017USD ($)	Mar. 28, 2017USD ($)	Dec. 31, 2017USD ($)unit	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Sep. 20, 2016USD ($)
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss						$ 3.2
Loss Contingency, Accrual, Current					$ 3.2
Litigation Settlement, Amount Awarded to Other Party	$ 2.8	$ 2.8
Loss Contingency, Estimate of Possible Loss	$ 1.3	$ 1.3
CAR Emissions Cap % Reduction for Covered Entities			5.00%
Number of Natural Gas Customers			1,200,000
Pending Litigation
Loss Contingencies [Line Items]
Litigation claims accrual			$ 2.4	$ 0.7
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			$ 127.6	$ 176.8

Commitments and Contingencies81

Commitments and Contingencies (Details) $ in Thousands, MWh in Millions	12 Months Ended
	Dec. 31, 2017USD ($)MWhContracts$ / kWhMW	Dec. 31, 2016USD ($)MWh	Dec. 31, 2015USD ($)MWh
Long-term Purchase Commitment [Line Items]
Long-term Line of Credit, Noncurrent	$ 102,600	$ 12,480
Average cost of Company's energy output (US$ per kWh) | $ / kWh	0.022
Number of Public Utility Districts with long term purchase agreements | Contracts	3
Contract expenses	$ 73,827	$ 77,667	$ 72,833
Percent of Output	13.30%
Megawatt Capacity | MW	745
Estimated 2018 Costs	$ 73,037
2018 Debt Service Costs	23,058
Interest included in 2018 Debt Service Costs	11,743
Debt Outstanding	200,907
Payment Obligations for Power Purchases
2,014	360,476
2,015	332,694
2,016	333,720
2,017	336,824
2,018	335,924
Thereafter	1,836,965
Total	$ 3,536,603
Total energy obtained during period under purchased power contracts (MWh) | MWh	14.5	13	11.2
Cost incurred during period to provide energy under purchased power contracts	$ 456,400	$ 402,500	$ 373,800
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	$ 245,669
2,015	193,458
2,016	163,818
2,017	145,662
2,018	109,401
Thereafter	0
Total	858,008
Columbia River projects
Payment Obligations for Power Purchases
2,014	82,200
2,015	97,890
2,016	95,704
2,017	91,862
2,018	91,018
Thereafter	708,499
Total	1,167,173
Other utilities
Payment Obligations for Power Purchases
2,014	1,257
2,015	888
2,016	0
2,017	0
2,018	0
Thereafter	0
Total	2,145
Non-utility contracts
Payment Obligations for Power Purchases
2,014	206,233
2,015	233,776
2,016	238,016
2,017	244,962
2,018	244,906
Thereafter	1,128,466
Total	2,296,359
Firm transportation service
Payment Obligations for Power Purchases
2,014	154,170
2,015	154,204
2,016	141,962
2,017	126,319
2,018	125,335
Thereafter	310,428
Total	1,012,418
Firm Storage and Peaking Service [Member]
Payment Obligations for Power Purchases
2,014	8,328
2,015	8,899
2,016	7,908
2,017	3,108
2,018	1,619
Thereafter	857
Total	30,719
Long-term Purchase Commitment, Demand Charges	121,400
Firm natural gas supply
Payment Obligations for Power Purchases
2,014	463,941
2,015	370,379
2,016	315,339
2,017	275,089
2,018	236,355
Thereafter	311,285
Total	1,972,388
Combustion turbines
Payment Obligations for Power Purchases
Long-term Purchase Commitment, Demand Charges	41,800
Energy production service contracts
Payment Obligations for Power Purchases
2,014	28,674
2,015	27,939
2,016	28,639
2,017	29,415
2,018	30,142
Thereafter	165,689
Total	310,498
Automated meter reading system
Payment Obligations for Power Purchases
2,014	48,245
2,015	44,842
2,016	43,951
2,017	44,497
2,018	45,168
Thereafter	187,698
Total	414,401
Service contract obligations
Payment Obligations for Power Purchases
2,014	76,919
2,015	72,781
2,016	72,590
2,017	73,912
2,018	75,310
Thereafter	353,387
Total	724,899
Short-Term Energy Supply Contracts [Member]
Payment Obligations for Power Purchases
2,014	55,774
2,015	13,818
2,016	1,651
2,017	0
2,018	0
Thereafter	0
Total	71,243
Short-Term Energy Supply Contracts [Member]
Payment Obligations for Power Purchases
2,014	70,786
2,015	140
2,016	0
2,017	0
2,018	0
Thereafter	0
Total	$ 70,926
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	27
Rock Island Project
Long-term Purchase Commitment [Line Items]
Percent of Output	25.00%
Megawatt Capacity | MW	156
Estimated 2018 Costs	$ 29,135
2018 Debt Service Costs	10,105
Interest included in 2018 Debt Service Costs	5,354
Debt Outstanding	$ 84,269
Rocky Reach Project
Long-term Purchase Commitment [Line Items]
Percent of Output	25.00%
Megawatt Capacity | MW	325
Estimated 2018 Costs	$ 28,800
2018 Debt Service Costs	5,796
Interest included in 2018 Debt Service Costs	2,548
Debt Outstanding	$ 39,563
Wells Project1
Long-term Purchase Commitment [Line Items]
Percent of Output	29.90%
Megawatt Capacity | MW	251
Estimated 2018 Costs	$ 11,002
2018 Debt Service Costs	4,695
Interest included in 2018 Debt Service Costs	1,379
Debt Outstanding	$ 49,629
Priest Rapids Development
Long-term Purchase Commitment [Line Items]
Percent of Output	0.60%
Megawatt Capacity | MW	6
Estimated 2018 Costs	$ 2,050
2018 Debt Service Costs	1,231
Interest included in 2018 Debt Service Costs	1,231
Debt Outstanding	$ 13,723
Wanapum Development
Long-term Purchase Commitment [Line Items]
Percent of Output	0.60%
Megawatt Capacity | MW	7
Estimated 2018 Costs	$ 2,050
2018 Debt Service Costs	1,231
Interest included in 2018 Debt Service Costs	1,231
Debt Outstanding	$ 13,723

Related Party Transactions (Det

Related Party Transactions (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Related Party Transaction [Line Items]
Number of Residents receiving Group Health Coverage in WA and N. ID	600,000,000
Related Party Transaction, Due from (to) Related Party		$ 1
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction	$ 0.8	1	$ 1.8
Subsidiaries [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction		$ 23.3	$ 20.3

Segment Information (Details)

Segment Information (Details)	12 Months Ended
	Dec. 31, 2017mi²segment
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 Comprehensi84

Accumulated Other Comprehensive Income (Loss) Changes in AOCI, net of tax (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	$ (33,712)
Accumulated other comprehensive income (loss), net of tax	(24,282)	$ (33,712)
Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(145,511)
Accumulated other comprehensive income (loss), net of tax	(126,906)	(145,511)
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	(33,712)	(27,266)	$ (36,710)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	10,251	(5,528)	7,196
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(821)	(918)	2,248
Other Comprehensive Income (Loss), Net of Tax	9,430	(6,446)	9,444
Accumulated other comprehensive income (loss), net of tax	(24,282)	(33,712)	(27,266)
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	(140,155)	(143,877)	(164,281)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	10,200	(5,655)	6,922
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	8,088	9,377	13,482
Other Comprehensive Income (Loss), Net of Tax	18,288	3,722	20,404
Accumulated other comprehensive income (loss), net of tax	(121,867)	(140,155)	(143,877)
Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(33,712)	(27,266)	(37,043)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	10,251	(5,528)	7,196
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(821)	(918)	2,581
Other Comprehensive Income (Loss), Net of Tax	9,430	(6,446)	9,777
Accumulated other comprehensive income (loss), net of tax	(24,282)	(33,712)	(27,266)
Comprehensive Income [Member] | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(145,511)	(149,550)	(170,957)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	10,200	(5,655)	6,922
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	8,405	9,694	14,485
Other Comprehensive Income (Loss), Net of Tax	18,605	4,039	21,407
Accumulated other comprehensive income (loss), net of tax	(126,906)	(145,511)	(149,550)
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	(333)
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	333
Other Comprehensive Income (Loss), Net of Tax	0	0	333
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	(686)
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	686
Other Comprehensive Income (Loss), Net of Tax	0	0	686
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	(5,356)	(5,673)	(5,990)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	317	317	317
Other Comprehensive Income (Loss), Net of Tax	317	317	317
Accumulated other comprehensive income (loss), net of tax	$ (5,039)	$ (5,356)	$ (5,673)

Accumulated Other Comprehensi85

Accumulated Other Comprehensive Income (Loss) Reclassifications Out of Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification of net unrealized loss on energy derivative instruments during the period, tax		$ 0	$ 0	$ (179)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0	0	(333)
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	(369)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0	0	(686)
Reclassification out of Accumulated Other Comprehensive Income | Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Comprehensive income (loss)		821	918	(2,581)
Reclassification out of Accumulated Other Comprehensive Income | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Comprehensive income (loss)		(8,405)	(9,694)	(14,485)
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]	1,938	1,938	1,938
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax	[1]	(675)	(525)	(5,397)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax		1,263	1,413	(3,459)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax		(442)	(495)	1,211
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, after Tax		821	918	(2,248)
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	(1,055)
Reclassification of net unrealized loss on energy derivative instruments during the period, tax		0	0	369
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0	0	(686)
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		(488)	(488)	(488)
Reclassification of net unrealized loss on energy derivative instruments during the period, tax		171	171	171
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		(317)	(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	[2]	1,529	1,529	1,526
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax	[2]	(13,972)	(15,955)	(22,268)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax		(12,443)	(14,426)	(20,742)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax		4,355	5,049	7,260
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, after Tax		(8,088)	(9,377)	(13,482)
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	(512)
Reclassification of net unrealized loss on energy derivative instruments during the period, tax		0	0	179
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		$ 0	$ 0	$ (333)
[1]	These AOCI components are included in the computation of net periodic pension cost, see Note 12, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.
[2]	These AOCI components are included in the computation of net periodic pension cost, see Note 12, "Retirement Benefits," to the consolidated financial statements included in item 8 of this report for additional details.

SUPPLEMENTAL QUARTERLY FINANCIA

SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information [Line Items]
Operating revenues									$ 3,460,276	$ 3,164,301	$ 3,092,700
Operating income									760,497	785,384	671,925
Net income (loss)									175,194	312,899	241,179
Parent Company [Member]
Quarterly Financial Information [Line Items]
Operating revenues	$ 1,002,900	$ 660,377	$ 719,767	$ 1,077,232	$ 915,157	$ 618,278	$ 668,169	$ 962,697
Operating income	259,696	99,044	130,030	271,727	236,854	88,072	175,634	284,824
Net income (loss)	(467)	12,836	35,275	127,550	104,825	2,335	64,553	141,186	175,194	312,899	241,179
Subsidiaries [Member]
Quarterly Financial Information [Line Items]
Operating revenues	1,002,900	660,377	719,767	1,077,232	915,158	618,594	668,169	962,697	3,460,276	3,164,618	3,093,258
Operating income	257,009	96,369	126,800	268,431	237,101	84,476	171,991	281,425	748,609	774,993	656,138
Net income (loss)	$ 97,208	$ 29,100	$ 50,654	$ 143,092	$ 124,199	$ 18,977	$ 80,900	$ 156,505	$ 320,054	$ 380,581	$ 304,189

SCHEDULE I CONDENSED FINANCIA87

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Statements of Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Financial Statements, Captions [Line Items]
Non-utility expense and other									$ (40,487)	$ (27,151)	$ (10,818)
Non-hedged interest rate swap expense									28	(1,062)	(3,796)
Interest expense									(354,802)	(355,139)	(356,696)
Income taxes									(255,143)	(140,204)	(91,776)
Net income (loss)									175,194	312,899	241,179
Comprehensive income (loss)									184,624	306,453	250,956
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Non-utility expense and other									(1,466)	(5,252)	(1,617)
Equity In Net Income (Loss) Of Subsidiaries									323,568	385,838	309,603
Non-hedged interest rate swap expense									28	(1,062)	(3,796)
Interest income									1,039	2	63
Interest expense									(106,072)	(104,600)	(100,114)
Income taxes									(41,903)	37,973	37,040
Net income (loss)	$ (467)	$ 12,836	$ 35,275	$ 127,550	$ 104,825	$ 2,335	$ 64,553	$ 141,186	175,194	312,899	241,179
Comprehensive income (loss)									$ 184,624	$ 306,453	$ 250,956

SCHEDULE I CONDENSED FINANCIA88

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Balance Sheets (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	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		26,616	28,878	$ 42,494	$ 37,527
Total current assets		813,418	902,868
Long-term assets:
Other		74,389	58,109
Total assets		13,690,789	13,266,380
Capitalization and liabilities:
Common equity		3,750,030	3,688,713	3,531,225	$ 3,543,328
Long-term debt		1,902,600	1,812,480
Total capitalization		9,007,959	9,040,374
Current liabilities:
Accounts payable		359,586	317,043
Interest		73,564	73,610
Deferred income taxes		746,868	1,570,931
Unrealized loss on derivative instruments		64,859	44,310
Total current liabilities		1,297,659	919,470
Long-term liabilities:
Unrealized loss on derivative instruments		21,235	16,261
Total capitalization and liabilities		13,690,789	13,266,380
Parent Company [Member]
Assets:
Investments in subsidiaries		3,721,553	3,571,550
Other property and investments:
Goodwill		1,656,513	1,656,513
Current assets:
Cash and Cash Equivalents, at Carrying Value		751	397	$ 639		$ 62
Receivables from affiliates	[1]	78,570	213
Total current assets		79,321	610
Long-term assets:
Deferred income taxes		208,889	309,812
Other		3,196	521
Total long-term assets		212,085	310,333
Total assets		5,669,472	5,539,006
Capitalization and liabilities:
Common equity		3,750,030	3,688,713
Long-term debt		1,892,672	1,808,828
Total capitalization		5,642,702	5,497,541
Current liabilities:
Accounts payable		1,042	15,801
Interest		25,728	25,523
Unrealized loss on derivative instruments		0	141
Total current liabilities		26,770	41,465
Long-term liabilities:
Total long-term liabilities		0	0
Total capitalization and liabilities		$ 5,669,472	$ 5,539,006
[1]	Eliminated in consolidation.

SCHEDULE I CONDENSED FINANCIA89

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Statements of Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	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	$ 972,131	$ 729,290	$ 648,722
Investing activities:
Other	(195)	(1,921)	754
Net cash provided by (used in) investing activities	(1,038,057)	(712,834)	(561,557)
Financing activities:
Dividends paid	(123,307)	(148,965)	(263,059)
Proceeds from long-term debt and bonds issued	90,120	12,481	825,000
Issuance/redemption of term-loan and other long-term debt	0	0	(711,000)
Net cash provided by (used in) financing activities	63,664	(30,072)	(82,198)
Net increase (decrease) in cash and cash equivalents	(2,262)	(13,616)	4,967
Cash and cash equivalents at beginning of period	28,878	42,494	37,527
Cash and cash equivalents at end of period	26,616	28,878	42,494
Parent Company [Member]
Investing activities:
Adjustments to Additional Paid in Capital, Other	(24,222)	0	(28,900)
(Increase) decrease in loan to subsidiary	(78,155)	0	28,933
Other	(437)	(6,078)	(5,632)
Net cash provided by (used in) investing activities	(102,814)	(6,078)	(5,599)
Financing activities:
Dividends paid	(123,307)	(148,965)	(263,059)
Proceeds from long-term debt and bonds issued	0	0	400,000
Issuance/redemption of term-loan and other long-term debt	90,120	12,480	(299,000)
Issue costs and others	(2,650)	(3,398)	(3,341)
Net cash provided by (used in) financing activities	(35,837)	(139,883)	(165,400)
Net increase (decrease) in cash and cash equivalents	354	(242)	577
Cash and cash equivalents at beginning of period	397	639
Cash and cash equivalents at end of period	$ 751	$ 397	$ 639

SCHEDULE I CONDENSED FINANCIA90

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY Notes (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net income									$ 175,194	$ 312,899	$ 241,179
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									184,624	306,453	250,956
Net Cash Provided by (Used in) Operating Activities									972,131	729,290	648,722
Net Cash Provided by (Used in) Investing Activities									(1,038,057)	(712,834)	(561,557)
Parent Company [Member]
Net income	$ (467)	$ 12,836	$ 35,275	$ 127,550	$ 104,825	$ 2,335	$ 64,553	$ 141,186	175,194	312,899	241,179
Goodwill, Purchase Accounting Adjustments									3,900	5,200	5,400
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									184,624	306,453	250,956
Net Cash Provided by (Used in) Investing Activities									(102,814)	(6,078)	(5,599)
Subsidiaries [Member]
Net income	$ 97,208	$ 29,100	$ 50,654	$ 143,092	$ 124,199	$ 18,977	$ 80,900	$ 156,505	320,054	380,581	304,189
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									338,659	384,620	325,596
Net Cash Provided by (Used in) Operating Activities									1,086,803	818,916	738,781
Net Cash Provided by (Used in) Investing Activities									$ (961,138)	$ (681,425)	$ (555,925)

SCHEDULE II VALUATION AND QUA91

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) - Allowance for doubtful accounts receivable - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance At Beginning of Period	$ 9,798	$ 9,756	$ 7,472
Additions Charged to Costs and Expenses	26,266	24,389	20,732
Deductions	27,163	24,347	18,448
Balance At End Of Period	$ 8,901	$ 9,798	$ 9,756