Puget Energy (PSD) 10-K 3 Mar 17 2016 FY Annual report Financial data

Document And Entity Information

Document And Entity Information	12 Months Ended
	Dec. 31, 2016shares	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	2,016
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
PUGET SOUND ENERGY, INC.
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	2,016
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating revenue:
Electric	$ 2,238,492	$ 2,128,468	$ 2,083,797
Natural gas	890,510	947,549	1,012,859
Other	35,299	16,683	16,515
Total operating revenue	3,164,301	3,092,700	3,113,171
Energy costs:
Purchased electricity	531,596	499,522	514,087
Electric generation fuel	215,331	249,907	263,493
Residential exchange	(69,824)	(112,473)	(129,036)
Purchased natural gas	313,954	403,310	458,691
Unrealized (gain) loss on derivative instruments, net	(83,795)	(13,233)	84,146
Utility operations and maintenance	568,492	530,720	550,146
Non-utility expense and other	27,151	10,818	13,109
Depreciation and amortization	439,579	420,807	365,606
Conservation amortization	107,784	110,866	104,096
Taxes other than income taxes	328,649	320,531	310,982
Total operating expenses	2,378,917	2,420,775	2,535,320
Operating income (loss)	785,384	671,925	577,851
Other income (deductions):
Other income	25,539	20,711	24,038
Other expense	(10,923)	(6,764)	(7,457)
Non-hedged interest rate swap expense	(1,062)	(3,796)	(3,915)
Interest charges:
AFUDC	9,304	7,575	5,611
Interest expense	(355,139)	(356,696)	(367,308)
Income (loss) before income taxes	453,103	332,955	228,820
Income tax (benefit) expense	140,204	91,776	56,985
Net income (loss)	312,899	241,179	171,835
PUGET SOUND ENERGY, INC.
Operating revenue:
Electric	2,238,492	2,128,468	2,083,797
Natural gas	890,510	947,549	1,012,859
Other	35,616	17,241	19,467
Total operating revenue	3,164,618	3,093,258	3,116,123
Energy costs:
Purchased electricity	531,596	499,522	514,087
Electric generation fuel	215,331	249,907	263,493
Residential exchange	(69,824)	(112,473)	(129,036)
Purchased natural gas	313,954	403,310	458,691
Unrealized (gain) loss on derivative instruments, net	(83,795)	(12,688)	85,636
Utility operations and maintenance	568,492	530,720	550,146
Non-utility expense and other	37,859	26,618	23,729
Depreciation and amortization	439,579	420,807	365,606
Conservation amortization	107,784	110,866	104,096
Taxes other than income taxes	328,649	320,531	310,982
Total operating expenses	2,389,625	2,437,120	2,547,430
Operating income (loss)	774,993	656,138	568,693
Other income (deductions):
Other income	25,537	20,711	24,036
Other expense	(10,923)	(6,764)	(7,457)
Interest charges:
AFUDC	9,304	7,575	5,611
Interest expense	(242,983)	(247,571)	(264,927)
Income (loss) before income taxes	555,928	430,089	325,956
Income tax (benefit) expense	175,347	125,900	89,342
Net income (loss)	$ 380,581	$ 304,189	$ 236,614

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Parent [Line Items]
Net income (loss)	$ 312,899	$ 241,179	$ 171,835
Other comprehensive income (loss):
Other Comprehensive Income Reclassification Of Net Unrealized Gain Loss On Interest Rate Swaps During Period Net Of Tax	0	0	94
Net unrealized gain (loss) from pension and postretirement plans, net of tax	(6,446)	9,444	(85,224)
Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax	0	333	372
Other comprehensive income (loss)	(6,446)	9,777	(84,758)
Comprehensive income (loss)	306,453	250,956	87,077
PUGET SOUND ENERGY, INC.
Parent [Line Items]
Net income (loss)	380,581	304,189	236,614
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	3,722	20,404	(76,876)
Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax	0	686	1,341
Amortization of treasury interest rate swaps to earnings, net of tax	317	317	317
Other comprehensive income (loss)	4,039	21,407	(75,218)
Comprehensive income (loss)	$ 384,620	$ 325,596	$ 161,396

CONSOLIDATED STATEMENTS OF COM4

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other comprehensive income (loss):
Net tax on reclassification of net unrealized loss on interest rate swaps during the period, tax	$ 0	$ 0	$ 50
Net unrealized gain (loss) from pension and postretirement plans, tax	(3,471)	5,087	(45,890)
Reclassification of net unrealized loss on energy derivative instruments during the period, tax	0	179	200
PUGET SOUND ENERGY, INC.
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, tax	2,004	10,987	(41,395)
Reclassification of net unrealized loss on energy derivative instruments during the period, tax	0	369	722
Amortization of treasury interest rate swaps to earnings, tax	$ 171	$ 171	$ 171

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Utility Plant [Abstract]
Electric plant	$ 7,673,772	$ 7,432,490
Natural gas plant	3,051,586	2,850,290
Common plant	594,994	508,750
Less: Accumulated depreciation and amortization	(2,161,796)	(1,878,868)
Net utility plant	9,158,556	8,912,662
Other property and investments:
Goodwill	1,656,513	1,656,513
Other property and investments	106,418	86,731
Total other property and investments	1,762,931	1,743,244
Current assets:
Cash and cash equivalents	28,878	42,494
Restricted cash	12,418	7,949
Accounts receivable, net of allowance for doubtful accounts	329,375	324,391
Unbilled revenue	234,053	217,274
Purchased gas adjustment receivable	2,785	0
Materials and supplies, at average cost	106,378	78,244
Fuel and natural gas inventory, at average cost	58,181	58,658
Unrealized gain on derivative instruments	54,341	24,418
Prepaid expense and other	43,046	17,120
Power contract acquisition adjustment gain	33,413	37,031
Total current assets	902,868	807,579
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	72,038	73,231
Power cost adjustment mechanism	4,531	4,749
Regulatory assets related to power contracts	22,613	26,223
Other regulatory assets	1,034,348	894,071
Unrealized gain on derivative instruments	8,738	5,225
Power contract acquisition adjustment gain	241,648	288,757
Other	58,109	58,513
Total other long-term and regulatory assets	1,442,025	1,350,769
Total assets	13,266,380	12,814,254
Common shareholder’s equity:
Common stock	0	0
Additional paid-in capital	3,308,957	3,308,957
Retained earnings	413,468	249,534
Accumulated other comprehensive income (loss), net of tax	(33,712)	(27,266)
Total common shareholder’s equity	3,688,713	3,531,225
Long-term debt:
First mortgage bonds and senior notes	3,362,000	3,364,412
Pollution control bonds	161,860	161,860
Junior subordinated notes	250,000	250,000
Long-term debt	1,812,480	1,800,000
Debt discount, issuance costs and other	(234,679)	(248,754)
Total long-term debt	5,351,661	5,327,518
Total capitalization	9,040,374	8,858,743
Current liabilities:
Accounts payable	317,043	259,353
Short-term debt	245,763	159,004
Current maturities of long-term debt	2,412	0
Purchased gas adjustment liability	0	12,589
Accrued expenses:
Taxes	111,428	114,854
Salaries and wages	49,749	38,457
Interest	73,610	73,378
Unrealized loss on derivative instruments	44,310	136,173
Power Contract Acquisition Adjustment Loss Current	3,159	3,611
Other	71,996	53,867
Total current liabilities	919,470	851,286
Other Long-term and regulatory liabilities:
Deferred income taxes	1,570,931	1,435,955
Unrealized loss on derivative instruments	16,261	48,073
Regulatory liabilities	654,622	652,441
Regulatory Liabilities Related To Power Contracts	275,061	325,788
Power Contract Acquisition Adjustment Loss Non Current	19,454	22,613
Other deferred credits	770,207	619,355
Total other long-term and regulatory liabilities	3,306,536	3,104,225
Commitments and contingencies (Note 15)
Total capitalization and liabilities	13,266,380	12,814,254
PUGET SOUND ENERGY, INC.
Utility Plant [Abstract]
Electric plant	9,813,169	9,601,091
Natural gas plant	3,640,271	3,444,744
Common plant	632,718	548,657
Less: Accumulated depreciation and amortization	(4,927,602)	(4,681,830)
Net utility plant	9,158,556	8,912,662
Other property and investments:
Other property and investments	77,960	83,069
Total other property and investments	77,960	83,069
Current assets:
Cash and cash equivalents	28,481	41,856
Restricted cash	12,418	7,949
Accounts receivable, net of allowance for doubtful accounts	344,964	324,358
Unbilled revenue	234,053	217,274
Purchased gas adjustment receivable	2,785	0
Materials and supplies, at average cost	106,378	78,244
Fuel and natural gas inventory, at average cost	56,851	57,324
Unrealized gain on derivative instruments	54,341	24,418
Prepaid expense and other	43,046	17,119
Total current assets	883,317	768,542
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	71,517	72,694
Power cost adjustment mechanism	4,531	4,749
Other regulatory assets	1,034,352	894,059
Unrealized gain on derivative instruments	8,738	5,225
Other	58,109	58,513
Total other long-term and regulatory assets	1,177,247	1,035,240
Total assets	11,297,080	10,799,513
Common shareholder’s equity:
Common stock	859	859
Additional paid-in capital	3,275,105	3,275,105
Retained earnings	359,795	236,578
Accumulated other comprehensive income (loss), net of tax	(145,511)	(149,550)
Total common shareholder’s equity	3,490,248	3,362,992
Long-term debt:
First mortgage bonds and senior notes	3,362,000	3,364,412
Pollution control bonds	161,860	161,860
Junior subordinated notes	250,000	250,000
Debt discount, issuance costs and other	(28,974)	(31,910)
Total long-term debt	3,744,886	3,744,362
Total capitalization	7,235,134	7,107,354
Current liabilities:
Accounts payable	317,043	259,353
Short-term debt	245,763	159,004
Current maturities of long-term debt	2,412	0
Purchased gas adjustment liability	0	12,589
Accrued expenses:
Taxes	111,428	114,854
Salaries and wages	49,749	38,457
Interest	48,087	47,772
Unrealized loss on derivative instruments	44,170	131,420
Other	71,996	53,868
Total current liabilities	890,648	817,317
Other Long-term and regulatory liabilities:
Deferred income taxes	1,732,390	1,556,616
Unrealized loss on derivative instruments	16,261	47,776
Regulatory liabilities	653,296	651,094
Other deferred credits	769,351	619,356
Total other long-term and regulatory liabilities	3,171,298	2,874,842
Commitments and contingencies (Note 15)
Total capitalization and liabilities	$ 11,297,080	$ 10,799,513

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Assets:
Construction work in progress	$ 420,278	$ 408,795
Current assets:
Allowance for doubtful accounts	$ 9,798	$ 9,756
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
PUGET SOUND ENERGY, INC.
Assets:
Construction work in progress	$ 420,278	$ 408,795
Current assets:
Allowance for doubtful accounts	$ 9,798	$ 9,756
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)	PUGET SOUND ENERGY, INC.	PUGET SOUND ENERGY, INC.Common Stock	PUGET SOUND ENERGY, INC.Additional Paid-in Capital	PUGET SOUND ENERGY, INC.Retained Earnings	PUGET SOUND ENERGY, INC.Accumulated Other Comprehensive Income (Loss)	PUGET SOUND ENERGY, INC.Financial Support, Capital Contributions [Member]
Balance at Dec. 31, 2013	$ 3,679,679		$ 3,308,957	$ 323,007	$ 47,715	$ 3,440,757	$ 859	$ 3,246,205	$ 289,432	$ (95,739)
Balance (in shares) at Dec. 31, 2013		200					85,903,791
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	171,835			171,835		236,614			236,614
Common stock dividend	(223,428)			(223,428)		(323,424)			(323,424)
Other comprehensive income (loss)	(84,758)				(84,758)	(75,218)				(75,218)
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	(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	200				85,903,791	85,903,791
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 312,899			312,899		$ 380,581			380,581
Common stock dividend	(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

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating activities:
Net income (loss)	$ 312,899	$ 241,179	$ 171,835
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	439,579	420,807	365,606
Conservation amortization	107,784	110,866	104,096
Deferred income taxes and tax credits, net	139,640	91,978	56,984
Net unrealized (gain) loss on derivative instruments	(88,704)	(17,255)	80,139
Derivative contracts classified as financing activities due to merger	0	(8,045)	(16,349)
AFUDC - equity	(12,576)	(9,325)	(7,002)
Funding of pension liability	(24,000)	(18,000)	(18,000)
Regulatory assets and liabilities	(150,855)	(153,877)	(228,334)
Other long-term assets and liabilities	30,459	35,270	19,691
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	(21,763)	(66,703)	153,434
Materials and supplies	(28,134)	4,945	4,951
Fuel and natural gas inventory	473	9,332	(2,742)
Prepayments and other	(25,927)	4,086	(2,140)
Purchased gas adjustment	(15,374)	33,662	(27,011)
Accounts payable	32,465	(48,037)	9,098
Taxes payable	(3,426)	7,072	(1,777)
Other	36,750	(5,323)	6,605
Net cash provided by (used in) operating activities	729,290	648,722	701,782
Investing activities:
Construction expenditures - excluding equity AFUDC	(706,444)	(587,225)	(493,130)
Treasury grant payment received	0	0	107,876
Proceeds from disposition of assets	0	0	20,296
Restricted cash	(4,469)	24,914	(25,692)
Other	(1,921)	754	(4,512)
Net cash provided by (used in) investing activities	(712,834)	(561,557)	(395,162)
Financing activities:
Change in short-term debt, net	86,759	74,004	(77,000)
Dividends paid	(148,965)	(263,059)	(223,428)
Proceeds from long-term debt and bonds issued	12,481	825,000	299,000
Redemption of bonds and notes	0	(711,000)	(299,000)
Derivative contracts classified as financing activities due to merger	0	(8,045)	(16,349)
Other	19,653	902	3,382
Net cash provided by (used in) financing activities	(30,072)	(82,198)	(313,395)
Net increase (decrease) in cash and cash equivalents	(13,616)	4,967	(6,775)
Cash and cash equivalents at beginning of period	42,494	37,527	44,302
Cash and cash equivalents at end of period	28,878	42,494	37,527
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	329,603	339,866	349,402
Income Taxes Paid, Net	0	2	0
Capital Expenditures Incurred but Not yet Paid	76,813	51,588	51,776
Increase (Decrease) in Regulatory Assets and Liabilities	176,804	0	0
PUGET SOUND ENERGY, INC.
Operating activities:
Net income (loss)	380,581	304,189	236,614
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	439,579	420,807	365,606
Conservation amortization	107,784	110,866	104,096
Deferred income taxes and tax credits, net	174,776	125,900	89,342
Net unrealized (gain) loss on derivative instruments	(83,795)	(12,688)	85,636
AFUDC - equity	(12,576)	(9,325)	(7,002)
Funding of pension liability	(24,000)	(18,000)	(18,000)
Regulatory assets and liabilities	(149,998)	(153,877)	(228,334)
Other long-term assets and liabilities	33,119	39,379	16,518
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	(37,385)	(66,547)	153,626
Materials and supplies	(28,134)	4,945	4,951
Fuel and natural gas inventory	473	9,332	(2,742)
Prepayments and other	(25,927)	4,089	(2,140)
Purchased gas adjustment	(15,374)	33,662	(27,011)
Accounts payable	32,465	(48,031)	9,098
Taxes payable	(3,426)	7,072	(1,777)
Other	30,754	(12,992)	4,246
Net cash provided by (used in) operating activities	818,916	738,781	782,727
Investing activities:
Construction expenditures - excluding equity AFUDC	(681,112)	(587,225)	(493,130)
Treasury grant payment received	0	0	107,876
Proceeds from disposition of assets	0	0	20,296
Restricted cash	(4,469)	24,914	(25,692)
Other	4,156	6,386	(1,683)
Net cash provided by (used in) investing activities	(681,425)	(555,925)	(392,333)
Financing activities:
Change in short-term debt, net	86,759	74,004	(77,000)
Dividends paid	(257,364)	(270,233)	(323,424)
Loan from (payment to) parent	0	(28,933)	(665)
Proceeds from Contributions from Parent	0	28,900	0
Proceeds from long-term debt and bonds issued	0	425,000	0
Redemption of bonds and notes	0	(412,000)	0
Other	19,739	4,796	4,050
Net cash provided by (used in) financing activities	(150,866)	(178,466)	(397,039)
Net increase (decrease) in cash and cash equivalents	(13,375)	4,390	(6,645)
Cash and cash equivalents at beginning of period	41,856	37,466	44,111
Cash and cash equivalents at end of period	28,481	41,856	37,466
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	227,668	242,774	253,803
Income Taxes Paid, Net	0	2	0
Capital Expenditures Incurred but Not yet Paid	76,813	51,588	51,776
Increase (Decrease) in Regulatory Assets and Liabilities	$ 176,804	$ 0	$ 0

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
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. In 2009, Puget Holdings LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company.” The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and PSE’s financial statements 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. Change in Accounting Principle On January 1, 2016, the Company changed its method of presenting unamortized debt issuance costs in the balance sheet. The new method of presenting debt issuance costs was adopted to comply with Accounting Standards Update (ASU) 2015-03, "Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" . ASU 2015-03 requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with the presentation of a debt discount. The prior year comparative balance sheet has been adjusted to apply the new method retrospectively. Due to the change in accounting principle, the December 31, 2015 financial statement line item “Other long-term assets” decreased and “Debt discount, issuance costs and other” increased 38.4 million and 30.0 million at Puget Energy and PSE, respectively. 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 its natural gas fired combustion turbines 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. Non-Utility Property, Plant and Equipment For PSE, the costs of other property, plant and equipment 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 For financial statement purposes, 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 depreciation of vehicles and equipment is allocated to the asset and expense accounts based on usage. The annual depreciation provision stated as a percent of a depreciable electric utility plant was 2.8% , for each of 2016 , 2015 and 2014 ; depreciable natural gas utility plant was 3.4% , for each of 2016 , 2015 and 2014 ; and depreciable common utility plant was 9.7% , 8.5% and 8.5% in 2016 , 2015 and 2014 , respectively. Depreciation on other property, plant and equipment is calculated primarily on a straight-line basis over the useful lives of the assets. 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 two-step process. The first step compares the carrying amount of the reporting unit with its fair value, with a carrying value higher than fair value indicating potential impairment. If the first step test fails, the second step is performed. 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 2016 using an October 1, 2016 measurement date. The fair value of Puget Energy’s reporting unit was estimated using both discounted cash flow and market approach. Such approaches are considered methodologies that market participants would use. This analysis 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, 2016 . There were no known events or circumstances from the date of the assessment through December 31, 2016 that would impact management’s conclusion. 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. Puget Energy and PSE record 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. Puget Energy and PSE record these items at the lower of cost or market value using the weighted-average cost 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 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 and losses 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 due to the length of the amortization. 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 as of July 1, 2013 is 7.77% . 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). 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 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 $235.3 million , $234.2 million and $231.7 million for 2016 , 2015 and 2014 , 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. The non-utility subsidiary recognizes revenue when services are performed or upon the sale of assets. Revenue from retail sales is billed based on tariff rates approved by the Washington Commission. 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 due to weather and gross margin erosion related to 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. To record revenues under this program, the Company must be able to collect the revenue 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. For GAAP purposes only, 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-recorded amounts will be recorded. 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, 2016 and 2015 was $9.8 million each year. 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. The Washington Commission has approved the deferral of certain uninsured qualifying storm damage costs that exceed $8.0 million which will be requested for collection in future rates. 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, who 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. Non-Core Natural 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 Credits (PTCs) represent federal income tax incentives available to taxpayers that generate energy from qualifying renewable sources. PSE records the benefit of the PTCs as a deferred credit until such time as PSE utilizes the tax credit on its tax return. Once utilized, PSE will reclassify the credits to a regulatory liability and pass the benefit to customers. 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, 2016 , 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.

New Accounting Pronouncements

New Accounting Pronouncements	12 Months Ended
	Dec. 31, 2016
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)". 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. In August 2015, the FASB issued ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date," deferring the effective date for ASU 2014-09 to fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. In addition to the FASB's deferral decision, FASB provided reporting entities with an option to adopt ASU 2014-09 for the fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, the original effective date. The Company plans to adopt ASU 2014-09 during the first quarter of fiscal year 2018. Reporting entities have the option of using either a full retrospective or a modified retrospective approach for the adoption of the new standard. At this time, the Company has not yet selected a transition method; however, it is in the process of completing its analysis and expects to decide in early 2017. Additionally, the Company initiated a steering committee and project team to evaluate the impact of this standard, update any policies and procedures that may be affected, and implement the new revenue recognition guidance. After a substantial evaluation of this standard, the Company does not anticipate significant impacts to its results of operations or on its consolidated financial statements. The Company is still waiting on the resolution of certain industry implementation issues, including contributions in aid of construction (CIAC), to determine the full impact. The Company is anticipating additional disclosures related to the implementation of the new standard. Lease Accounting In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)". 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. 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 plans to adopt ASU 2016-02 during the first quarter of fiscal year 2019. At this time, the Company plans to initiate a steering committee and project team to evaluate the impact this standard will have on its results of operations and consolidated financial statements. Derivatives and Hedging In March 2016, the FASB issued ASU 2016-06, "Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments". Topic 815 requires that embedded derivatives be separated from the host contract and accounted for separately as derivatives if certain criteria are met, including the “clearly and closely related” criterion. ASU 2016-06 clarifies the requirements for assessing whether contingent call or put options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. An entity performing the assessment under the amendment is required to assess the embedded call or put options solely in accordance with the four-step decision sequence. This amendment is effective for financial statements issued for fiscal years beginning after December 15, 2016, 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 plans to adopt ASU 2016-06 during the first quarter of fiscal year 2017. The Company anticipates the new guidance will not have a significant impact on its financial statements. 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. Current GAAP is unclear or does not include specific guidance on the eight cash flow classification issues included in the amendments. 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 plans to 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 beginning after December 15, 2018. The Company plans to adopt ASU 2016-18 during the first quarter of fiscal year 2018 and does not anticipate the new guidance will have a significant impact on its consolidated statement of cash flows.

Regulation and Rates

Regulation and Rates	12 Months Ended
	Dec. 31, 2016
Regulated Operations [Abstract]
Regulation and Rates	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, 2016 and 2015 included the following: Puget Sound Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2016 2015 Colstrip Regulatory Asset (a) $ 176,804 $ — Storm damage costs electric 1 to 2 years 122,709 125,777 Chelan PUD contract initiation 14.8 years 105,140 112,228 Decoupling deferrals and interest 156,408 104,150 Decoupling 24-month revenue reserve (20,847 ) (9,980 ) Total decoupling asset Less than 2 years 135,561 94,170 Lower Snake River 1 to 20.3 years 74,862 79,599 Deferred income taxes (a) 71,517 72,694 Environmental remediation (a) 74,557 66,887 Baker Dam licensing operating and maintenance costs 42 years 61,453 63,394 PGA deferral of unrealized losses on derivative instruments (a) — 60,889 Deferred Washington Commission AFUDC 35 years 51,404 52,197 Unamortized loss on reacquired debt 1 to 30 years 42,196 44,984 Property tax tracker Less than 2 years 41,949 40,353 Energy conservation costs 1 to 2 years 41,027 36,646 White River relicensing and other costs 15.9 years 21,627 23,054 Mint Farm ownership and operating costs 8.3 years 16,319 18,320 Ferndale 2.8 years 11,274 15,253 Electron unrecovered loss 2 years 7,178 10,569 Snoqualmie licensing operating and maintenance costs 28 years 8,018 7,980 Colstrip common property (a) 5,334 6,049 Colstrip major maintenance 2 years 6,589 5,897 Investment in Bonneville Exchange power contract 1 year 1,763 5,290 Snoqualmie 1.8 years 3,251 5,024 PCA mechanism (a) 4,531 — PGA receivable 1 year 2,785 — Various other regulatory assets Varies 25,337 24,248 Total PSE regulatory assets 1,113,185 971,502 Cost of removal (b) (369,300 ) (347,472 ) Treasury grants 3 to 42 years (133,709 ) (157,102 ) Production tax credits (c) (93,616 ) (93,616 ) Decoupling ROR excess earnings (13,300 ) (25,483 ) Decoupling deferrals and interest (16,448 ) — Total decoupling liability Less than 2 years (29,748 ) (25,483 ) PGA payable 1 year — (12,589 ) Summit purchase option buy-out 3.8 years (6,038 ) (7,612 ) Deferral of treasury grant amortization Less than 3 years (3,920 ) (6,058 ) PGA deferral of unrealized gains on derivative instruments (a) (7,517 ) — Lower Snake River interest due Less than 2 years (4,189 ) — Various other regulatory liabilities Up to 4 years (5,259 ) (13,751 ) Total PSE regulatory liabilities (653,296 ) (663,683 ) PSE net regulatory assets (liabilities) $ 459,889 $ 307,819 _______________ (a) Amortization periods vary depending on timing of underlying transactions or awaiting regulatory approval in a future Washington Commission rate proceeding. (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. Puget Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2016 2015 Total PSE regulatory assets (a) $ 1,113,185 $ 971,502 Puget Energy acquisition adjustments: Regulatory assets related to power contracts 1 to 21 years 22,613 26,223 Various other regulatory assets Varies 517 549 Total Puget Energy regulatory assets 1,136,315 998,274 Total PSE regulatory liabilities (a) (653,296 ) (663,683 ) Puget Energy acquisition adjustments: Regulatory liabilities related to power contracts 1 to 36 years (275,061 ) (325,788 ) Various other regulatory liabilities Varies (1,326 ) (1,347 ) Total Puget Energy regulatory liabilities (929,683 ) (990,818 ) Puget Energy net regulatory asset (liabilities) $ 206,632 $ 7,456 _______________ (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 $369.3 million and $347.5 million in 2016 and 2015 , respectively, for the cost of removal of utility plant. These amounts are collected from PSE’s customers through depreciation rates. 2013 Expedited Rate Filing, Decoupling and Centralia Decision PSE filed a settlement agreement with the Washington Commission on March 22, 2013. The agreement was intended to settle all issues regarding decoupling, a power purchase agreement with TransAlta Centralia and the Expedited Rate Filing (ERF) which is limited in scope and rate impact, includes the property tax tracker, and is intended to establish baseline rates on which the decoupling mechanisms are to operate. The Washington Commission placed the ERF and decoupling filings under a common procedural schedule. On June 25, 2013, the Washington Commission issued final orders resolving the amended decoupling petition, the ERF filing and the Petition for Reconsideration (related to the TransAlta Centralia power purchase agreement). Order No. 7 in the ERF/decoupling proceeding approved PSE's ERF filing with a small change to its cost of capital from 7.80% to 7.77% to update long term debt costs and a capital structure that included 48.0% common equity with a return on equity (ROE) of 9.8% . This order also approved the property tax tracker discussed below and approved the amended decoupling and rate plan filing with the further condition that PSE and the customers will share 50.0% each in earnings in excess of the 7.77% authorized rate of return. In addition, the rate plan (K-Factor) increase allowed decoupling revenue per customer for the recovery of delivery system costs to subsequently increase by 3.0% for the electric customers and 2.2% for the natural gas customers on January 1 of each year, until the conclusion of PSE's next General Rate Case (GRC), which was filed on January 13, 2017. In the rate plan, increases are subject to a cap of 3.0% of the total revenue for customers. General Rate Case Filing On March 17, 2016, the Washington Commission approved a joint petition postponing the filing of PSE’s GRC until no later than January 17, 2017. As part of the petition, PSE agreed to update power costs on December 1, 2016 in conjunction with the Centralia PPA compliance filing. Additionally, PSE agreed to include in its GRC filing a plan for closure of coal fired steam electric generation facility in Colstrip, Montana (Colstrip) Units 1 and 2, of which PSE owns a 50% interest. Monthly allowed revenue per customer includes an automatic annual increase and will continue through December 2017 when new rates go into effect from PSE's 2017 GRC. 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% . The requested combined natural gas tariff changes would result in a net decrease of $22.3 million , or 2.4% . The filing was subsequently suspended, which means that the final rates granted in the proceeding will go into effect no later than December 13, 2017. PSE’s GRC filing included the required plan for Colstrip Units 1 and 2 closures, see Item 3, "Legal Proceedings" to the consolidated financial statements included in Item 8 of this report. Additionally, PSE’s filing contains requests for two new mechanisms to address regulatory lag. PSE has 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 CRM similar to its existing natural gas CRM which would allow PSE to obtain accelerated cost recovery on specified electric reliability projects. 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 are expected to mitigate the impact of weather on operating revenue and net income. 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 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 will be recovered on a per customer basis regardless of actual consumption levels. The 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 or refund the difference between allowed decoupling revenue and the corresponding actual revenue to affected customers over a 12-month period beginning the following May. The decoupling mechanism will end on December 31, 2017 unless the continuation of the requested mechanism is approved in PSE's 2017 GRC which PSE filed on January 13, 2017. Decoupling over and under collections will still be collectible or refundable after December 31, 2017, even if the decoupling mechanism is not extended. The Washington Commission approved the following PSE requests to change rates under its electric and natural gas decoupling mechanisms: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) Electric: May 1, 2016 1.0% $20.8 May 1, 2015 2.6 53.8 May 1, 2014 0.5 10.6 Natural Gas: May 1, 2016 2.8% $25.4 May 1, 2015 2.1 22.0 May 1, 2014 (0.1) (1.0) As part of the April 22, 2015 filing, PSE requested to change the methodology of how decoupling deferrals are calculated going forward and adjust deferrals calculated in 2014. The change was done to ensure that the amortization of prior years’ accumulated decoupling deferrals were not included in the calculation of the current year decoupling deferrals. The effect of the methodology change was a reduction of approximately $12.0 million of previously recognized revenue from May through December of 2014. In addition, PSE exceeded the earnings test threshold in 2016, 2015 and 2014. The amount of the reduction to the 2016 decoupling deferral will not be known until the final earnings test result is filed in PSE's decoupling mechanism filing that will be made on March 31, 2017. PSE recorded the following reductions in decoupling deferrals to the electric and natural gas rate increases above: Effective Date Reduction in Rate Increases due to Excess Earnings (Dollars in Millions) Electric: 2016 (estimated) $11.2 2015 16.3 2014 3.4 Natural Gas: 2016 (estimated) $2.1 2015 9.2 2014 — As noted earlier, the Company is also limited to a 3.0% annual decoupling related cap on increases in total revenue. This limitation has been triggered as follows: Effective Date Accrued Through Deferrals not Included in Annual Rate Increases (Dollars in Millions) Electric: 2015 $— 2014 1.9 Natural Gas: 2015 $28.7 2014 8.2 Existing deferrals may be included in customer rates beginning in May 2018, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases. Electric Regulation and Rates Storm Damage Deferral Accounting The Washington Commission issued a GRC order that defined deferrable catastrophic/extraordinary losses and provided that costs in excess of $8.0 million annually may be deferred for qualifying storm damage costs that meet the modified IEEE outage criteria for system average interruption duration index. In 2016 and 2015 , PSE incurred $22.0 million and $33.6 million , respectively, in storm-related electric transmission and distribution system restoration costs, of which $12.4 million was deferred in 2016 and $22.4 million was deferred in 2015 . Power Cost Adjustment Mechanism PSE currently has a PCA mechanism that provides for the deferral of power costs that vary from the “power cost baseline” level of power costs. The “power cost baseline” levels are set, in part, based on normalized assumptions about weather and hydroelectric conditions. Excess power costs or savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism and will trigger a surcharge or refund when the cumulative deferral trigger is reached. The graduated scale that was applicable through December 31, 2016 was as follows: Annual Power Cost Variability Company’s Share Customers' Share +/- $20 million 100% —% +/- $20 million - $40 million 50 50 +/- $40 million - $120 million 10 90 +/- $120 + million 5 95 On August 7, 2015, the Washington Commission issued an order approving the settlement proposing changes to the PCA mechanism. The settlement agreement took effect January 1, 2017 and will apply the following graduated scale: Annual Power Cost Variability Company's Share Customers' Share Over or Under Collection: Over Under Over Under Over or Under Collected by up to $17 million 100% 100% —% —% Over or Under Collected by between $17 million - $40 million 35 50 65 50 Over or Under Collected beyond $40 + million 10 10 90 90 The settlement also resulted in the following changes to the PCA mechanism: • Reduction to the cumulative deferral trigger for surcharge or refund from $30.0 million to $20.0 million ; • Removal of fixed production costs from the PCA mechanism and placing them in the decoupling mechanism, assuming the decoupling mechanism continues after its review in the 2017 GRC. If decoupling was not to continue, those fixed production costs would be treated the same as other non-PCA costs unless permission to treat them in another manner is obtained from the Washington Commission. These fixed production costs include: (i) return and depreciation/amortization on fixed production assets and regulatory assets and liabilities; (ii) return on depreciation, transmission expense and revenues on specific transmission assets; and (iii) hydro, other production and other power related expenses and O&M costs; • Suspension of the requirement that a GRC must be filed within three months after rates are approved in a Power Cost Only Rate Case (PCORC); • Agreement, for a five-year period, that PSE will not file a GRC or PCORC within six months of the date rates go into effect for a PCORC filing; and • Establishment of a five-year moratorium on changes to the PCA. PSE had an annual PCA receivable during the year ended December 31, 2016 , due to under recovering $1.0 million of power costs of which no amounts were apportioned to customers. This compares to an annual PCA receivable of $8.7 million for the year ended December 31, 2015 of which no amounts were apportioned to customers. The change was driven by a decrease in actual costs. Federal Incentive Tracker Tariff The following table sets forth Federal Incentive Tracker Tariff rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates from prior year Total credit to be passed back to eligible customers (Dollars in Millions) January 1, 2017, proposed 0.3% $(51.7) January 1, 2016 (0.2) (57.3) January 1, 2015 (0.2) (55.2) January 1, 2014 (0.3) (58.5) Power Cost Only Rate Case and Update Compliance Filing The following table sets forth PCORC and update compliance filing rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) December 1, 2016 (1.7)% $(37.3) December 1, 2014 (0.9) (19.4) Electric Property Tax Tracker Mechanism The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2016 0.3% $5.7 May 1, 2015 0.3 6.5 May 1, 2014 0.5 11.0 Electric Conservation Rider The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2017, proposed 0.7% $16.5 May 1, 2016 (0.5) (11.7) May 1, 2015 0.2 4.2 May 1, 2014 0.6 12.2 Accounting Orders and Petitions PSE completed the sale of its electric infrastructure assets located in Jefferson County and the transition of electrical services in the county to Jefferson County Public Utility District (JPUD) on March 31, 2013. The proceeds from the sale exceeded the transferred assets' net carrying value of $46.7 million resulting in a pre-tax gain of approximately $60.0 million . A final order was rendered on September 11, 2014 which authorized PSE to retain $7.5 million of the gain and return $52.7 million to customers. The customer portion was booked to a regulatory liability account in other current liabilities and accrued interest at PSE's after-tax rate of return. PSE paid this amount to customers through a bill credit in the month of December 2014. Natural Gas Regulation and Rates Natural Gas General Rate Cases and Other Filings Affecting Rates Purchased Gas Adjustment The following table sets forth PGA rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) November 1, 2016 (0.4)% $(4.1) November 1, 2015 (17.4) (185.9) November 1, 2014 2.5 23.3 Cost Recovery Mechanism The following table sets forth CRM rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) November 1, 2016 0.6% $5.6 November 1, 2015 0.5 5.3 November 1, 2014 0.2 2.3 Natural Gas Property Tax Tracker Mechanism The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2016 0.4% $3.5 June 1, 2015 (0.2) (2.3) May 1, 2014 0.6 5.6 Natural Gas Conservation Rider The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding annual impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2017, proposed (0.1)% (1.0) May 1, 2016 0.3 2.9 May 1, 2015 0.2 2.3 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. PSE has implemented an ongoing program to test, replace and remediate certain underground storage tanks (UST) as required by federal and state laws. The UST replacement component of this effort is finished, but PSE continues its work remediating and/or monitoring relevant sites. During 1992, the Washington Commission issued orders regarding the treatment of costs incurred by the Company for certain sites under its environmental remediation program. The orders authorize the Company to accumulate and defer prudently incurred cleanup costs paid to third parties for recovery in rates established in future rate proceedings, subject to Washington Commission review. The Washington Commission consolidated the natural gas and electric methodological approaches to remediation and deferred accounting in an order issued October 8, 2008. 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 $38.0 million for natural gas and $6.2 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, 2016 , the Company’s share of future remediation costs is estimated to be approximately $24.9 million . The Company's deferred electric environmental costs are $13.8 million , $14.0 million and $13.4 million at December 31, 2016 , 2015 and 2014 , respectively, net of insurance proceeds. The Company's deferred natural gas environmental costs are $60.7 million , $52.9 million , and $52.6 million at December 31, 2016 , 2015 and 2014 , respectively, net of insurance proceeds. In the pending GRC, the Company has requested to ratebase remediation costs incurred, net of insurance, and third party recoveries.

Dividend Payment Restrictions

Dividend Payment Restrictions	12 Months Ended
	Dec. 31, 2016
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, 2016 , approximately $532.9 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant. Pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE’s ratio of earnings before interest, tax, depreciation and amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3.0 to 1.0 . The common equity ratio, calculated on a regulatory basis, was 47.9% at December 31, 2016 , and the EBITDA to interest expense was 5.2 to 1.0 for the twelve months ended December 31, 2016 . 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 3.5 to 1.0 for the twelve months ended December 31, 2016 . At December 31, 2016 , 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, 2016
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) 2016 2015 2016 2015 Distribution plant 10-50 $ 5,287,542 $ 5,007,077 $ 6,922,176 $ 6,657,597 Production plant 25-125 3,007,546 3,028,481 3,910,129 3,950,231 Transmission plant 45-65 1,307,687 1,236,823 1,420,334 1,351,216 General plant 5-35 541,424 491,845 611,237 563,850 Intangible plant (including capitalized software) 3-50 347,697 305,705 338,327 294,380 Plant acquisition adjustment 2-22 242,826 242,826 282,792 282,792 Underground storage 25-60 30,695 28,914 44,206 42,545 Liquefied natural gas storage 25-45 12,628 12,628 14,498 14,498 Plant held for future use NA 52,484 55,890 52,636 56,042 Recoverable Cushion Gas NA 8,655 8,655 8,655 8,655 Plant not classified 1-125 159,345 65,892 159,345 65,892 Grant NA (99,100 ) (102,379 ) (99,100 ) (102,379 ) Capital leases, net of accumulated amortization 1 2 645 378 645 378 Less: accumulated provision for depreciation (2,161,796 ) (1,878,868 ) (4,927,602 ) (4,681,830 ) Subtotal $ 8,738,278 $ 8,503,867 $ 8,738,278 $ 8,503,867 Construction work in progress NA 420,278 408,795 420,278 408,795 Net utility plant $ 9,158,556 $ 8,912,662 $ 9,158,556 $ 8,912,662 _______________ 1 Accumulated amortization of capital leases at Puget Energy and PSE was $0.6 million in 2016 and $32.3 million in 2015 . Jointly owned generating plant service costs are included in utility plant service cost at the Company's ownership share. The following table indicates the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2016 . These amounts are also included in the Utility Plant table above. Puget Energy’s Share Puget Sound Energy’s Share Jointly Owned Generating Plants (Dollars in Thousands) Energy Source (Fuel) Company’s Ownership Share Plant in Service at Cost Accumulated Depreciation Plant in Service at Cost Accumulated Depreciation Colstrip Units 1 & 2 Coal 50% $ 70,717 $ (22,284 ) $ 204,334 $ (155,902 ) Colstrip Units 3 & 4 Coal 25% 307,383 (40,343 ) 575,902 (308,861 ) Colstrip Units 1 – 4 Common Facilities Coal various 83 (27 ) 252 (196 ) Frederickson 1 Natural Gas 49.85% 61,780 (9,779 ) 70,729 (18,728 ) Jackson Prairie Natural Gas Storage 33.34% 30,021 (5,544 ) 44,206 (19,730 ) Asset Retirement Obligation The Company has recorded liabilities for steam generation sites, combustion turbine generation sites, wind generation sites, distribution and transmission poles, gas mains, and leased facilities where disposal is governed by ASC 410 “ARO”. On April 17, 2015, the United States 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 the second quarter of 2015 and the third quarter of 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. During the third quarter 2016, PSE entered into two new legal 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, 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. During the first quarter 2016, the Company updated its estimated decommissioning costs due to the timing of its ARO for Lower Snake River and Hopkins Ridge wind generation sites and increased the ARO liability of $19.7 million . The following table describes the changes to the Company’s ARO liability as of December 31, 2016 and 2015 : At December 31, (Dollars in Thousands) 2016 2015 Asset retirement obligation at beginning of period $ 85,028 $ 48,909 New asset retirement obligation recognized in the period — 34,534 Liability adjustment in the period (411 ) (3,628 ) Revisions in estimated cash flows 113,081 3,403 Accretion expense 2,647 1,810 Asset retirement obligation at end of period $ 200,345 $ 85,028 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, 2016 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, 2016
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 December 31, 2016 and 2015 : (Dollars in Thousands) At December 31, Series Type Due 2016 2015 Puget Sound Energy: 5.500% Promissory Note 2017 $ 2,412 $ 2,412 6.740% Senior Secured Note 2018 200,000 200,000 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 * (28,974 ) (31,910 ) Total PSE long-term debt 3,747,298 3,744,362 Puget Energy: * Fair value adjustment of PSE long-term debt * (199,436 ) (207,977 ) * Revolving Credit Agreement 2018 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 * (6,269 ) (8,867 ) Total Puget Energy long-term debt $ 5,354,073 $ 5,327,518 _______________ * Not Applicable. 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, 2016 , 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, 2016 , the earnings available for interest exceeded the required amount. On May 26, 2015, PSE issued $425.0 million of senior notes secured by first mortgage bonds. The notes mature in May 2045 and have an interest rate of 4.30% , which is payable semi-annually in May and November. Net proceeds of the issuance were used to fund the early retirement, including accrued interest and make-whole call premiums, of the Company's $150.0 million 5.197% senior notes maturing in October 2015 and the Company's $250.0 million 6.75% senior notes maturing in January 2016. Puget Energy Long-Term Debt In May 2015, Puget Energy issued $400.0 million of senior secured notes in a private placement. The notes mature in May 2025 and have an interest rate of 3.65% , which is payable semi-annually in May and November. Net proceeds of the issuance were used to repay outstanding Puget Energy indebtedness and to fund a special dividend to shareholders. In November 2015, Puget Energy exchanged $400.0 million of its 3.65% senior secured notes that were originally issued in the May 2015 private placement for registered notes of the same 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) 2017 2018 2019 2020 2021 Thereafter Total Maturities of: PSE long-term debt $ 2,412 $ 200,000 $ — $ — $ — $ 3,573,860 $ 3,776,272 Puget Energy long-term debt — 12,480 — 450,000 500,000 850,000 1,812,480 Puget Energy long-term debt $ 2,412 $ 212,480 $ — $ 450,000 $ 500,000 $ 4,423,860 $ 5,588,752

Liquidity Facilities and Other

Liquidity Facilities and Other Financing Arrangements	12 Months Ended
	Dec. 31, 2016
Liquidity Facilities and Other Financing Arrangements [Abstract]
Liquidity Facilities and Other Financing Arrangements	Liquidity Facilities and Other Financing Arrangements As of December 31, 2016 and 2015 , PSE had $245.8 million and $159.0 million in short-term debt outstanding, respectively, exclusive of the demand promissory note with Puget Energy. 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 facilities 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 2016 and 2015 was 3.21% and 4.24% , respectively. As of December 31, 2016 , PSE and Puget Energy had several committed credit facilities that are described below. Puget Sound Energy Credit Facilities PSE has two unsecured revolving credit facilities which provide, in aggregate, $1.0 billion of short-term liquidity needs. These facilities consist of a $650.0 million revolving liquidity facility (which includes a liquidity letter of credit facility and a swingline facility) to be used for general corporate purposes, including a backstop to the Company's commercial paper program and a $350.0 million revolving energy hedging facility (which includes an energy hedging letter of credit facility). The $650.0 million liquidity facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million . The credit facilities also have an accordion feature which, upon the banks' approval, would increase the total size of these facilities to $1.5 billion . In April 2014, the Company completed a one-year extension on both of the liquidity and hedging facilities, extending the maturity from February 2018 to April 2019, and updating or clarifying the definitions of other terms and conditions of the facilities from when they were committed in 2013. The credit agreements are syndicated among numerous lenders and contain usual and customary affirmative and negative covenants that, among other things, place limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreements also contain 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, 2016 , PSE was in compliance with all applicable covenant ratios. The credit agreements provide PSE with the ability to borrow at different interest rate options. The credit agreements allow 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 facilities. 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 1.75% and the commitment fee is 0.275% . As of December 31, 2016 , no amounts were drawn under either PSE's $650.0 million facility or PSE's $350.0 million energy hedging facility. No letters of credit were outstanding under either facility, and $245.8 million was outstanding under the commercial paper program. Outside of the credit agreements, PSE had a $3.5 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 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, 2016 , there was no outstanding balance under the Note. Puget Energy Credit Facility At December 31, 2016 , Puget Energy maintained an $800.0 million revolving senior secured credit facility. In April, 2014, the Company completed an amendment to the senior secured credit facility, extending the maturity from February 2017 to April 2018, updating the fee structure, eliminating a financial covenant and updating or clarifying the definitions of other terms and conditions of the facility. The Puget Energy revolving senior secured credit facility also has an accordion 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 December 31, 2016 , there was $12.5 million outstanding under the facility. As a result of Puget Energy's credit rating upgrade in 2014, the spread over LIBOR was 1.75% and the commitment fee was 0.275% as of the date of this report. Puget Energy entered into interest rate swap contracts to manage the interest rate risk associated with the credit facility or similar variable rate 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. 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, 2016 , Puget Energy was in compliance with all applicable covenants.

Leases

Leases	12 Months Ended
	Dec. 31, 2016
Leases [Abstract]
Leases	Leases PSE leases buildings and assets under operating leases. Certain leases contain purchase options, renewal options and escalation provisions. Operating lease expenses net of sublease receipts were: (Dollars in Thousands) At December 31, Years Operating Lease Expense 2016 $ 31,786 2015 27,843 2014 30,737 Payments received for the subleases of properties were immaterial for each of the years ended 2016 , 2015 and 2014 . Future minimum lease payments for non-cancelable leases net of sublease receipts are: (Dollars in Thousands) At December 31, Future Minimum Lease Payments Years Operating Capital 2017 $ 22,212 $ 296 2018 19,834 296 2019 18,078 74 2020 16,507 — 2021 8,137 — Thereafter 102,393 — Total minimum lease payments $ 187,161 $ 666

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Accounting for Derivative Instruments and Hedging Activities	Accounting for Derivative Instruments and Hedging Activities PSE employs various energy portfolio optimization strategies, but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the PCA. Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility in costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. PSE's 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, 2016 , Puget Energy had two interest rate swap contracts outstanding which matured January 2017 . Currently, these swap instruments do not hedge any variable interest rate debt. PSE did not have any outstanding interest rate swap instruments. The following table presents the volumes, fair values and locations 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 Liabilities 2 2016 2015 2016 2015 2016 2015 Interest rate swap derivatives 3 $450.0 $450.0 $ — $ — $ 141 $ 5,050 Electric portfolio derivatives * * 36,460 23,443 41,329 112,106 Natural gas derivatives (MMBtus) 4 336.4 369.5 26,619 6,200 19,101 67,090 Total derivative contracts ** ** $ 63,079 $ 29,643 $ 60,571 $ 184,246 Current ** ** $ 54,341 $ 24,418 $ 44,310 $ 136,173 Long-term ** ** 8,738 5,225 16,261 48,073 Total derivative contracts ** ** $ 63,079 $ 29,643 $ 60,571 $ 184,246 _______________ 1 Balance sheet location: Current and Long-term Unrealized gain on derivative instruments. 2 Balance sheet location: Current and Long-term Unrealized loss on derivative instruments. 3 Interest rate swap contracts are only held at Puget Energy. 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 186.8 million One Million British Thermal Units (MMBtus) and purchased electricity of 3.6 million megawatt hours (MWhs) at December 31, 2016 and 202.1 million MMBtus and 0.1 million MWhs at December 31, 2015 . ** Not meaningful and/or applicable. 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 gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical 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 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, 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 Puget Energy and Puget Sound Energy At December 31, 2015 (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 $ 29,643 $ — $ 29,643 $ (23,998 ) $ — $ 5,645 Liabilities: Energy derivative contracts 179,196 — 179,196 (23,998 ) — 155,198 Interest rate swaps 2 5,050 — 5,050 — — 5,050 _______________ 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. 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 2016 2015 2014 Interest rate contracts: Non-hedged interest rate swap (expense) income $ (1,062 ) $ (3,796 ) $ (3,915 ) Interest expense — 560 500 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 62,318 (9,315 ) (42,334 ) Realized Electric generation fuel (39,656 ) (44,648 ) 6,511 Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 1 21,477 22,548 (41,812 ) Realized Purchased electricity (21,998 ) (39,137 ) (4,212 ) Total gain (loss) recognized in income on derivatives $ 21,079 $ (73,788 ) $ (85,262 ) Puget Sound Energy Year Ended December 31, (Dollars in Thousands) Location 2016 2015 2014 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net $ 62,318 $ (9,315 ) $ (42,334 ) Realized Electric generation fuel (39,656 ) (44,648 ) 6,511 Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 1 21,477 22,003 (43,302 ) Realized Purchased electricity (21,998 ) (39,137 ) (4,212 ) Total gain (loss) recognized in income on derivatives $ 22,141 $ (71,097 ) $ (83,337 ) _______________ 1 Differences between Puget Energy and PSE for the twelve months ended December 31, 2015 and 2014 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, exposure monitoring and exposure mitigation. The Company monitors counterparties that have significant swings in credit default swap rates, have credit rating changes by external rating agencies, have changes in ownership or are experiencing 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, 2016 , approximately 93.1% of the Company's energy portfolio exposure, excluding NPNS transactions, is with counterparties that are rated investment grade by rating agencies and 6.9% 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, 2016 , the Company was in a net asset position with the majority of counterparties, however, 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. As of December 31, 2016 , PSE has posted a $1.0 million letter of credit 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, 2016 , nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades. The table below presents the fair value of the overall contractual contingent liability positions for the Company's derivative activity: Puget Energy and Puget Sound Energy At December 31, (Dollars in Thousands) 2016 2015 Contingent Feature Fair Value 1 Liability Posted Collateral Contingent Collateral Fair Value 1 Liability Posted Collateral Contingent Collateral Credit rating 2 $ 4,894 $ — $ 4,894 $ 24,187 $ — $ 24,187 Requested credit for adequate assurance 7,427 — — 67,003 — — Forward value of contract 3 507 — — — — — Total $ 12,828 $ — $ 4,894 $ 91,190 $ — $ 24,187 _______________ 1 Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable. 2 Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral. 3 Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
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 because 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. For interest rate swaps, the Company obtains monthly mark-to-market values from an independent external pricing service for LIBOR forward rates, which is a significant input. Some of the inputs of the interest rate swap valuations, which are less significant, include the credit standing of the counterparties, assumptions for time value and the impact of the Company's nonperformance risk of its liabilities. The Company classifies cash and cash equivalents, and restricted cash as Level 1 financial instruments due to cash being at stated value, and cash equivalents at quoted market prices. The Company considers its electric, natural gas and interest rate swap contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. Management's assessment was 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 (e.g., Level 2 in the fair value hierarchy) used to value commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter. 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. Assets and Liabilities with Estimated Fair Value The carrying values of cash and cash equivalents, restricted cash, and short-term debt as reported on the balance sheet are reasonable estimates of their fair value due to the short-term nature of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of other investments of $49.1 million and $52.8 million at December 31, 2016 and 2015 , 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 credit spreads as inputs, interpolating to the maturity date of each issue. Carrying values and estimated fair values were as follows: Puget Energy At December 31, 2016 At December 31, 2015 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 210,261 $ 250,000 $ 211,173 Long-term debt (fixed-rate), net of discount 1 2 5,091,593 6,337,287 5,077,518 6,308,831 Long-term debt (variable-rate) 2 12,480 12,480 — — Total $ 5,354,073 $ 6,560,028 $ 5,327,518 $ 6,520,004 Puget Sound Energy At December 31, 2016 At December 31, 2015 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 210,261 $ 250,000 $ 211,173 Long-term debt (fixed-rate), net of discount 2 2 3,497,298 4,360,783 3,494,362 4,329,444 Total $ 3,747,298 $ 4,571,044 $ 3,744,362 $ 4,540,617 _______________ 1 The carrying value includes debt issuances costs of $33.0 million and $38.4 million for December 31, 2016 and 2015 , respectively, which are not included in fair value. 2 The carrying value includes debt issuances costs of $27.2 million and $30.0 million for December 31, 2016 and 2015 , 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 Fair Value Fair Value At December 31, 2016 At December 31, 2015 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Liabilities: Interest rate derivative instruments $ 141 $ — $ 141 $ 5,050 $ — $ 5,050 Total derivative liabilities $ 141 $ — $ 141 $ 5,050 $ — $ 5,050 Puget Energy and Fair Value Fair Value At December 31, 2016 At December 31, 2015 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 30,666 $ 5,794 $ 36,460 $ 10,709 $ 12,734 $ 23,443 Natural gas derivative instruments 23,316 3,303 26,619 4,538 1,662 6,200 Total derivative assets $ 53,982 $ 9,097 $ 63,079 $ 15,247 $ 14,396 $ 29,643 Liabilities: Electric derivative instruments $ 36,507 $ 4,822 $ 41,329 $ 92,027 $ 20,079 $ 112,106 Natural gas derivative instruments 16,423 2,678 19,101 63,045 4,045 67,090 Total derivative liabilities $ 52,930 $ 7,500 $ 60,430 $ 155,072 $ 24,124 $ 179,196 Puget Energy and Puget Sound Energy Year Ended December 31, Level 3 Roll-Forward Net (Liability) 2016 2015 2014 (Dollars in Thousands) Electric Gas Total Electric Gas Total Electric Gas Total Balance at beginning of period $ (7,345 ) $ (2,383 ) $ (9,728 ) $ (12,062 ) $ (2,040 ) $ (14,102 ) $ (15,421 ) $ (361 ) $ (15,782 ) Changes during period Realized and unrealized energy derivatives: Included in earnings 1 4,007 — 4,007 (6,432 ) — (6,432 ) (5,537 ) — (5,537 ) Included in regulatory assets / liabilities — 4,312 4,312 — 3,695 3,695 — 1,630 1,630 Settlements 2 (1,129 ) (2,679 ) (3,808 ) 902 (3,885 ) (2,983 ) 1,036 (1,534 ) (498 ) Transferred into Level 3 (3,021 ) — (3,021 ) (787 ) — (787 ) 5,155 (585 ) 4,570 Transferred out of Level 3 8,460 1,375 9,835 11,034 (153 ) 10,881 2,705 (1,190 ) 1,515 Balance at end of period $ 972 $ 625 $ 1,597 $ (7,345 ) $ (2,383 ) $ (9,728 ) $ (12,062 ) $ (2,040 ) $ (14,102 ) _______________ 1 Income Statement location: 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 $2.0 million , $(7.4) million and $(9.6) million for the years ended December 31, 2016 , 2015 and 2014 , 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, 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, 2016 : Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $5,794 $4,822 Discounted cash flow Power Prices $11.86 per MWh $33.52 per MWh $27.61 per MWh Natural gas $3,303 $2,678 Discounted cash flow Natural Gas Prices $2.00 per MMBtu $3.24 per MMBtu $2.42 per MMBtu _______________ 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, 2016 , 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 $0.2 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 2016 and 2015 , Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. In 2016 and 2015 , due to decreases in forecasted revenue and cost estimates and continued significant decreases in forward power prices, 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, 2016 Priest Rapids $ 18,969 $ 6,191 $ 12,778 March 31, 2016 Wells Hydro 25,193 19,855 5,338 December 31, 2015 Wells Hydro 32,988 27,628 5,360 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 which are 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 2016 and 2015 : Puget Energy Valuation Date Unobservable Input Low High Average September 30, 2016 Power prices $24.24 per MWh $58.96 per MWh $39.31 per MWh Power contract costs (in thousands) $618 per year $4,633 per year $2,472 per year March 31, 2016 Power prices $9.46 per MWh $25.96 per MWh $21.38 per MWh Power contract costs (in thousands) $4,100 per qtr. $4,659 per qtr. $4,452 per qtr. December 31, 2015 Power prices $15.16 per MWh $27.25 per MWh $23.23 per MWh Power contract costs (in thousands) $4,100 per qtr. $4,659 per qtr. $4,417 per qtr.

Employee Investment Plans

Employee Investment Plans	12 Months Ended
	Dec. 31, 2016
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 $17.2 million , $16.1 million and $14.9 million for the years 2016 , 2015 and 2014 , 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% of plan compensation each paycheck, and will make an additional year-end contribution equal to 1% of base pay. • For employees grandfathered under the Final Average Earning retirement plan formula, PSE will match 55% of an employee’s contribution up to 6% 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% of pay contributed and 50% match on the next 3% of pay contributed. An employee who contributes 6% 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% 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% 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% contribution either into the 401(k) plan or into an account in the Cash Balance retirement plan. The Company’s 4% contribution will vest after three years of service.

Retirement Benefits

Retirement Benefits	12 Months Ended
	Dec. 31, 2016
Compensation and Retirement Disclosure [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% 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% 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, 2016 and 2015 : Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Change in benefit obligation: Benefit obligation at beginning of period $ 643,088 $ 690,194 $ 51,279 $ 55,855 $ 13,946 $ 15,688 Service cost 18,913 21,287 1,085 1,108 93 112 Interest cost 28,689 28,088 2,325 2,281 533 621 Actuarial loss (gain) 1,545 (55,665 ) 106 (4,430 ) (2,262 ) (1,416 ) Benefits paid (38,730 ) (39,963 ) (3,061 ) (3,535 ) (1,264 ) (1,354 ) Medicare part D subsidy received — — — — 148 295 Administrative expense (898 ) (853 ) — — — — Benefit obligation at end of period $ 652,607 $ 643,088 $ 51,734 $ 51,279 $ 11,194 $ 13,946 Puget Energy and Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Change in plan assets: Fair value of plan assets at beginning of period $ 598,865 $ 626,173 $ — $ — $ 7,203 $ 8,360 Actual return on plan assets 37,022 (4,489 ) — — 926 (378 ) Employer contribution 24,000 18,000 3,061 3,535 335 575 Benefits paid (38,730 ) (39,963 ) (3,061 ) (3,535 ) (1,264 ) (1,354 ) Administrative expense (897 ) (856 ) — — — — Fair value of plan assets at end of period $ 620,260 $ 598,865 $ — $ — $ 7,200 $ 7,203 Funded status at end of period $ (32,347 ) $ (44,223 ) $ (51,734 ) $ (51,279 ) $ (3,994 ) $ (6,743 ) Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Amounts recognized in Statement of Financial Position consist of: Noncurrent assets $ — $ — $ — $ — $ — $ — Current liabilities — — (1,911 ) (2,545 ) (325 ) (353 ) Noncurrent liabilities (32,347 ) (44,223 ) (49,823 ) (48,734 ) (3,669 ) (6,390 ) Net assets (liabilities) $ (32,347 ) $ (44,223 ) $ (51,734 ) $ (51,279 ) $ (3,994 ) $ (6,743 ) Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets: Projected benefit obligation $ 652,607 $ 643,088 $ 51,734 $ 51,279 $ 11,194 $ 13,946 Accumulated benefit obligation 641,855 635,599 47,639 46,978 11,092 13,828 Fair value of plan assets 620,260 598,865 — — 7,200 7,203 The following tables summarize Puget Energy's and PSE's pension benefit amounts recognized in AOCI for the years ended December 31, 2016 and 2015 : Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 56,588 $ 45,447 $ 9,043 $ 9,848 $ (4,190 ) $ (1,834 ) Prior service cost (credit) (9,822 ) (11,802 ) 246 288 — — Total $ 46,766 $ 33,645 $ 9,289 $ 10,136 $ (4,190 ) $ (1,834 ) Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 217,143 $ 221,064 $ 11,978 $ 13,202 $ (5,994 ) $ 3,834 Prior service cost (credit) (7,806 ) (9,379 ) 251 295 — — Total $ 209,337 $ 211,685 $ 12,229 $ 13,497 $ (5,994 ) $ 3,834 The following tables summarize Puget Energy's and PSE's net periodic benefit cost for the years ended December 31, 2016 , 2015 and 2014 : Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2014 2016 2015 2014 2016 2015 2014 Components of net periodic benefit cost: Service cost $ 18,913 $ 21,287 $ 17,437 $ 1,085 $ 1,108 $ 1,042 $ 93 $ 112 $ 112 Interest cost 28,689 28,088 28,039 2,325 2,281 2,310 533 621 684 Expected return on plan assets (46,619 ) (45,038 ) (42,464 ) — — — (446 ) (531 ) (535 ) Amortization of prior service cost (credit) (1,980 ) (1,980 ) (1,980 ) 42 42 42 — — — Amortization of net loss (gain) — 3,887 — 911 1,641 913 (386 ) (130 ) (393 ) Net periodic benefit cost $ (997 ) $ 6,244 $ 1,032 $ 4,363 $ 5,072 $ 4,307 $ (206 ) $ 72 $ (132 ) Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2014 2016 2015 2014 2016 2015 2014 Components of net periodic benefit cost: Service cost $ 18,913 $ 21,287 $ 17,437 $ 1,085 $ 1,108 $ 1,042 $ 93 $ 112 $ 112 Interest cost 28,689 28,088 28,039 2,325 2,281 2,310 533 621 684 Expected return on plan assets (46,814 ) (45,462 ) (43,252 ) — — — (446 ) (531 ) (535 ) Amortization of prior service cost (credit) (1,573 ) (1,573 ) (1,573 ) 44 44 44 — 3 3 Amortization of net loss(gain) 15,257 20,555 13,195 1,330 2,120 1,461 (632 ) (406 ) (702 ) Net periodic benefit cost $ 14,472 $ 22,895 $ 13,846 $ 4,784 $ 5,553 $ 4,857 $ (452 ) $ (201 ) $ (438 ) The following tables summarize Puget Energy's and PSE's benefit obligations recognized in other comprehensive income (OCI) for the years ended December 31, 2016 and 2015 : Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 11,141 $ (6,136 ) $ 106 $ (4,430 ) $ (2,742 ) $ (508 ) Amortization of net loss (gain) — (3,887 ) (910 ) (1,641 ) 385 131 Amortization of prior service credit 1,980 1,980 (42 ) (42 ) — — Total change in other comprehensive income for year $ 13,121 $ (8,043 ) $ (846 ) $ (6,113 ) $ (2,357 ) $ (377 ) Puget Sound Energy Qualified Pension Benefit SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 11,336 $ (5,711 ) $ 106 $ (4,430 ) $ (2,742 ) $ (508 ) Amortization of net (loss) gain (15,257 ) (20,556 ) (1,330 ) (2,120 ) 631 407 Amortization of prior service cost (credit) 1,573 1,573 (44 ) (44 ) — (3 ) Total change in other comprehensive income for year $ (2,348 ) $ (24,694 ) $ (1,268 ) $ (6,594 ) $ (2,111 ) $ (104 ) The estimated net (loss) gain and prior service cost (credit) for the pension plans that will be amortized from accumulated OCI into net periodic benefit cost in 2017 by PSE are $(13.7) million and $(1.6) million , respectively. The estimated net (loss) gain for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2017 is $(1.6) million . The estimated prior service cost (credit) for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2017 is immaterial . The estimated net (loss) gain and prior service cost (credit) for the other postretirement plans that will be amortized from accumulated OCI into net periodic benefit cost in 2017 is immaterial. For Puget Energy, the overall amounts expected to be amortized from accumulated OCI into net period benefit cost in 2017 were immaterial. 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, 2017 are expected to be at least $18.0 million , $1.9 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 2016 2015 2014 2016 2015 2014 2016 2015 2014 Discount rate 4.50 % 4.65 % 4.25 % 4.50 % 4.65 % 4.25 % 4.50 % 4.65 % 4.25 % 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 — — — — — — 8.80 7.20 5.70 Benefit Cost Assumptions Discount rate 4.65 % 4.25 % 5.10 % 4.65 % 4.25 % 5.10 % 4.65 % 4.25 % 5.10 % Return on plan assets 7.75 7.75 7.75 — — — 6.75 7.00 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 — — — — — — 5.30 7.20 6.70 The assumed medical inflation rate used to determine benefit obligations is 8.80% in 2017 grading down to 4.30% in 2018 . A 1.0% change in the assumed medical inflation rate would have the following effects: 2016 2015 (Dollars in Thousands) 1% Increase 1% Decrease 1% Increase 1% Decrease Effect on post-retirement benefit obligation $ 38 $ (35 ) $ 52 $ (42 ) Effect on service and interest cost components 2 (2 ) 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 as follows. PSE market-related value of assets 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) 2017 2018 2019 2020 2021 2022-2026 Qualified Pension total benefits $ 41,400 $ 42,500 $ 43,600 $ 44,600 $ 45,200 $ 240,800 SERP Pension total benefits 1,911 5,278 5,666 4,454 1,724 34,043 Other Benefits total with Medicare Part D subsidy 928 893 863 829 787 3,873 Other Benefits total without Medicare Part D subsidy 1,256 1,239 1,216 1,191 1,158 5,294 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, 2016 and 2015 : Recurring Fair Value Measures Recurring Fair Value Measures As of December 31, 2016 As of December 31, 2015 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual Funds $ 181,212 $ — $ 181,212 $ 169,165 $ — $ 169,165 Common Stock 154,255 — $ 154,255 146,321 — $ 146,321 Government Securities 18,754 16,197 $ 34,951 8,835 14,268 $ 23,103 Corporate Bonds — 38,543 $ 38,543 — 44,157 $ 44,157 Subtotal 354,221 54,740 408,961 324,321 58,425 382,746 Investments measured at NAV 1 * * 222,819 * * 223,663 Net (payable) receivable * * (9,894 ) * * (7,544 ) Total assets * * $ 621,886 * * $ 598,865 _______________ 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 consist of common/collective trust funds and two partnerships held as of December 31, 2016 . 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. * Not Applicable. 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, 2016 As of December 31, 2015 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual fund 1 $ 7,182 $ — $ 7,182 $ 7,135 $ — $ 7,135 Cash equivalents 2 — 80 80 — 68 68 Total assets $ 7,182 $ 80 $ 7,262 $ 7,135 $ 68 $ 7,203 _______________ 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, 2016 . 2 The investment consists of a money market fund (at level 1) and a collective trust fund (at level 2). The money market fund is valued at the net asset value per share of $1.00 per unit as of December 31, 2016 . The collective trust fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or short-term in nature.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
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) 2016 2015 2014 Charged to operating expenses: Current: Federal $ — $ — $ — State 20 — — Deferred: Federal 140,315 91,968 57,152 State (131 ) (192 ) (167 ) Total income tax expense $ 140,204 $ 91,776 $ 56,985 Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2016 2015 2014 Charged to operating expenses: Current: Federal $ — $ — $ — State 20 — — Deferred: Federal 175,327 125,900 89,342 State — — — Total income tax expense $ 175,347 $ 125,900 $ 89,342 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) 2016 2015 2014 Income taxes at the statutory rate $158,586 $116,534 $80,087 Increase (decrease): Production tax credit 1 (12,925) (19,470) (23,073) Utility plant differences 3,966 5,671 7,090 Treasury grant amortization (9,788) (8,807) (8,808) Other - net 365 (2,152) 1,689 Total income tax expense $140,204 $91,776 $56,985 Effective tax rate 30.9% 27.6% 24.9% Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2016 2015 2014 Income taxes at the statutory rate $194,572 $150,531 $114,084 Increase (decrease): Production tax credit 1 (12,925) (19,470) (23,073) Utility plant differences 3,966 5,671 7,090 Treasury grant amortization (9,788) (8,807) (8,808) Other - net (478) (2,025) 49 Total income tax expense $175,347 $125,900 $89,342 Effective tax rate 31.5% 29.3% 27.4% _______________ 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, 2016 and 2015 is composed of amounts related to the following types of temporary differences: Puget Energy At December 31, (Dollars in Thousands) 2016 2015 Utility plant and equipment $ 1,880,782 $ 1,788,078 Regulatory asset for income taxes 72,038 73,231 Fair value of debt instruments 67,444 70,260 Pensions and other compensation 77,230 77,230 Other, net deferred tax liabilities 119,050 84,397 Subtotal deferred tax liabilities 2,216,544 2,093,196 Net operating loss carryforward (352,827 ) (384,338 ) Production tax credit carryforward (190,999 ) (178,075 ) Regulatory liability on production tax credit (101,787 ) (94,828 ) Subtotal deferred tax assets (645,613 ) (657,241 ) Total net deferred tax liabilities $ 1,570,931 $ 1,435,955 Puget Sound Energy At December 31, (Dollars in Thousands) 2016 2015 Utility plant and equipment $ 1,880,782 $ 1,788,078 Regulatory asset for income taxes 71,517 72,694 Other, net deferred tax liabilities 113,938 80,351 Subtotal deferred tax liabilities 2,066,237 1,941,123 Net operating loss carryforward (41,061 ) (111,604 ) Production tax credit carryforward (190,999 ) (178,075 ) Regulatory liability on production tax credit (101,787 ) (94,828 ) Subtotal deferred tax assets (333,847 ) (384,507 ) Total net deferred tax liabilities $ 1,732,390 $ 1,556,616 In November 2015, the FASB issued ASU 2015-17, "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes". ASU 2015-17 requires reporting entities to classify deferred tax liabilities and assets as noncurrent in a classified balance sheet instead of separating such deferred taxes into current and noncurrent amounts. 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 2036. 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. For ratemaking purposes, deferred taxes are not provided for certain temporary differences. PSE has established a regulatory asset for income taxes recoverable through future rates related to those temporary differences for which no deferred taxes have been provided, based on prior and expected future ratemaking treatment. 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, 2016 and 2015 , 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 2013 through 2016. The Company classifies interest as interest expense and penalties as other expense in the financial statements.

Litigation

Litigation	12 Months Ended
	Dec. 31, 2016
Litigation Disclosure [Abstract]
Litigation	Litigation 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. Based on a second amended complaint filed in August 2014, plaintiffs' lawsuit alleged violations of permitting requirements under the New Source Review/Prevention of Significant Deterioration program of the Clean Air Act arising from projects (plaintiffs initially claimed seventy-three projects, but this was reduced to two projects before trial in May 2016) undertaken at Colstrip during the time period from 2001 to 2012. 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, PSE agreed, along with Talen Energy (the owner of the other 50% interest in Colstrip Units 1 and 2), to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana by no later than July 1, 2022. PSE expects that the Washington Commission will allow 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 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. 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. While PSE has estimated the asset retirement obligation for Colstrip Units 1 and 2, the full scope of decommissioning activities and costs are unknown and will 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 September 20, 2016, seeking from PSE $3.2 million in fines. As a result, the Washington Commission will initiate a hearing before making a final determination. As of December 31, 2016 , PSE has accrued $3.2 million for the fine. Clean Air Rule PSE, along with other Washington natural gas utilities, jointly filed a lawsuit in federal court on September 27, 2016 (United States District Court Eastern District of Washington) and Washington State court (Thurston County Superior Court) on September 30, 2016 challenging Washington Department of Ecology’s Clean Air Rule. Other parties in the suit include Avista Corporation, Cascade Natural Gas Corp. and Northwest Natural Gas. The lawsuit contends that this Rule will have the unintended consequence of increasing carbon emissions while penalizing customers for using natural gas. 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 $0.7 million and $0.3 million relating to these claims as of December 31, 2016 and 2015 , respectively.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies For the year ended December 31, 2016 , approximately 13.7% of the Company’s energy output was obtained at an average cost of approximately $0.023 per Kilowatt Hour (kWh) through long-term contracts with three of the Washington Public Utility Districts (PUDs) that own hydroelectric projects on the Columbia River. The purchase of power from the Columbia River projects is on a pro rata share basis under which the Company pays a proportionate share of the annual debt service, operating and maintenance costs and other expenses associated with each project, in proportion to the contractual share of power that PSE obtains from that project. In these instances, PSE’s payments are not contingent upon the projects being operable; therefore, PSE is required to make the payments even if power is not delivered. These projects are financed through substantially level 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) 2016 2015 2014 PUD contract costs $ 77,667 $ 72,833 $ 69,661 As of December 31, 2016 , 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 2017 Costs 2017 Debt Service Costs Interest included in 2017 Debt Service Costs Debt Outstanding Chelan County PUD: Rock Island Project 2031 25.0 % 156 $ 28,886 $ 10,430 $ 5,638 $ 88,518 Rocky Reach Project 2031 25.0 325 28,376 7,574 2,854 44,305 Douglas County PUD: Wells Project 2018 29.9 251 16,547 8,004 2,153 54,847 Grant County PUD: Priest Rapids Development 2052 0.6 8 2,809 1,670 1,670 18,579 Wanapum Development 2052 0.6 9 2,809 1,670 1,670 18,579 Total 749 $ 79,427 $ 29,348 $ 13,985 $ 224,828 The following table summarizes the Company’s estimated payment obligations for power purchases from the Columbia River projects, contracts with other utilities and contracts with non-utilities. These contracts have varying terms and may include escalation and termination provisions. (Dollars in Thousands) 2017 2018 2019 2020 2021 Thereafter Total Columbia River projects $ 73,733 $ 69,527 $ 58,921 $ 59,172 $ 56,396 $ 597,468 $ 915,217 Other utilities 10,499 1,257 888 — — — 12,644 Non-utility contracts 198,681 203,428 208,328 212,042 218,431 935,826 1,976,736 Total $ 282,913 $ 274,212 $ 268,137 $ 271,214 $ 274,827 $ 1,533,294 $ 2,904,597 Total purchased power contracts provided the Company with approximately 13.0 million , 11.2 million and 12.1 million MWhs of firm energy at a cost of approximately $402.5 million , $373.8 million and $401.4 million for the years 2016 , 2015 and 2014 , respectively. PSE enters into short-term energy supply contracts to meet its core customer needs. These contracts are sometimes classified as NPNS, however in most cases recorded at fair value in accordance with ASC 815. Commitments under these contracts are $45.7 million , $10.5 million and $3.9 million in 2017 , 2018 and 2019 , 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 less than one year to 28 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. The Company incurred demand charges for 2016 for firm transportation, storage and peaking services for its natural gas customers of $120.2 million . The Company incurred demand charges in 2016 for firm transportation and storage services for the natural gas supply for its combustion turbines in the amount of $43.2 million . The following table summarizes the Company’s obligations for future natural gas supply and demand charges through the primary terms of its existing contracts. The quantified obligations are based on the FERC and NEB (National Energy Board) currently authorized rates, which are subject to change. Natural Gas Supply and Demand Charge Obligations (Dollars in Thousands) 2017 2018 2019 2020 2021 Thereafter Total Natural gas supply $ 320,238 $ 211,256 $ 230,109 $ 177,390 $ 107,621 $ — $ 1,046,614 Firm transportation service 156,290 154,155 149,277 140,672 128,049 467,266 1,195,709 Firm storage service 6,616 3,861 2,943 1,950 1,619 2,475 19,464 Total $ 483,144 $ 369,272 $ 382,329 $ 320,012 $ 237,289 $ 469,741 $ 2,261,787 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) 2017 2018 2019 2020 2021 Thereafter Total Energy production service contracts $ 31,573 $ 31,970 $ 31,313 $ 50,656 $ 32,934 $ 204,687 $ 383,133 Automated meter reading system 18,175 18,693 18,718 20,191 20,939 116,811 213,527 Total $ 49,748 $ 50,663 $ 50,031 $ 70,847 $ 53,873 $ 321,498 $ 596,660 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, 2016
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 and as a result, PSE paid Group Health a total of $ 23.3 million and $ 20.3 million for medical coverage for the year ended December 31, 2016 and 2015 , respectively. Kimberly Harris, the President and Chief Executive Officer and a director of Puget Energy and PSE, is married to Kyle Branum, who through 2016 was a principal at the law firm Riddell Williams P.S. As of January 2017, Mr. Branum is a partner at Summit Law Group, which provides legal services to PSE. In 2016 and 2015 , Riddell Williams was paid $ 1.0 million and $ 1.8 million , respectively, for legal services provided to PSE and Mr. Branum was among the lawyers at Riddell Williams who provided such legal services. This work was performed under the supervision of PSE's General Counsel. On October 10, 2014, U.S. Bancorp announced the appointment of Kimberly Harris to its board of directors effective October 20, 2014. Ms. Harris is the President and Chief Executive Officer of both Puget Energy and PSE. U.S. Bancorp is the parent company of U.S. Bank N.A., which directly or through its subsidiaries or affiliates provides credit, banking, investment and trust services to both Puget Energy and PSE. For the year ended December 31, 2016 and 2015 , Puget Energy and PSE paid a total of approximately $0.3 million and $1.0 million , respectively, in fees and interest to U.S. Bank N.A. and its subsidiaries or affiliates.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Segment Information	Segment Information Puget Energy operates one reportable business 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. In managing the business, management reviews the consolidated financial statements for Puget Energy and PSE during the year.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 , respectively: Puget 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 interest rate swaps Changes in AOCI, net of tax (Dollars in Thousands) Total Balance at December 31, 2013 $ 48,514 $ (705 ) $ (94 ) $ 47,715 Other comprehensive income (loss) before reclassifications (84,301 ) — — (84,301 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax (923 ) 372 94 (457 ) Net current-period other comprehensive income (loss) (85,224 ) 372 94 (84,758 ) 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 ) 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, 2013 $ (87,405 ) $ (2,027 ) $ (6,307 ) $ (95,739 ) Other comprehensive income (loss) before reclassifications (84,955 ) — — (84,955 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 8,079 1,341 317 9,737 Net current-period other comprehensive income (loss) (76,876 ) 1,341 317 (75,218 ) 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 ) Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2016 , 2015 and 2014 , 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) 2016 2015 2014 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) (525 ) (5,397 ) (519 ) Total before tax 1,413 (3,459 ) 1,419 Tax (expense) or benefit (495 ) 1,211 (496 ) Net of Tax 918 (2,248 ) 923 Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: Electric derivatives Purchased electricity — (512 ) (572 ) Tax (expense) or benefit — 179 200 Net of Tax — (333 ) (372 ) Net unrealized gain (loss) on interest rate swaps: Interest rate contracts Interest expense — — (144 ) Tax (expense) or benefit — — 50 Net of Tax — — (94 ) Total reclassification for the period Net of Tax $ 918 $ (2,581 ) $ 457 _______________ (a) These AOCI components are included in the computation of net periodic pension cost (see Note 12, "Retirement Benefits" 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) 2016 2015 2014 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,529 $ 1,526 $ 1,526 Amortization of net gain (loss) (a) (15,955 ) (22,268 ) (13,954 ) Total before tax (14,426 ) (20,742 ) (12,428 ) Tax (expense) or benefit 5,049 7,260 4,349 Net of tax (9,377 ) (13,482 ) (8,079 ) Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: Electric derivatives Purchased electricity — (1,055 ) (2,063 ) Tax (expense) or benefit — 369 722 Net of Tax — (686 ) (1,341 ) 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 $ (9,694 ) $ (14,485 ) $ (9,737 ) _______________ (a) These AOCI components are included in the computation of net periodic pension cost (see Note 12, "Retirement Benefits" for additional details).

SCHEDULE I CONDENSED FINANCIAL

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 Non-utility expense and other $ (5,252 ) $ (1,617 ) $ (5,390 ) Other income (deductions): Equity in earnings of subsidiary 385,838 309,603 240,102 Non-hedged interest rate swap expense (1,062 ) (3,796 ) (3,915 ) Interest income 2 63 185 Interest expense (104,600 ) (100,114 ) (93,382 ) Income taxes 37,973 37,040 34,235 Net income (loss) 312,899 241,179 171,835 Comprehensive income (loss) $ 306,453 $ 250,956 $ 87,077 See accompanying notes to the condensed financial statements. Puget Energy Condensed Balance Sheets (Dollars in Thousands) December 31, 2016 2015 Assets: Investment in subsidiaries $ 3,571,550 $ 3,415,571 Other property and investments: Goodwill 1,656,513 1,656,513 Current assets: Cash 397 639 Receivables from affiliates 1 213 203 Total current assets 610 842 Long-term assets: Deferred income taxes 309,812 272,487 Other 521 537 Total long-term assets 310,333 273,024 Total assets $ 5,539,006 $ 5,345,950 Capitalization and liabilities: Common equity $ 3,688,713 $ 3,531,225 Long-term debt 1,808,828 1,783,898 Total capitalization 5,497,541 5,315,123 Current liabilities: Account Payable 15,801 171 Interest 25,523 25,606 Unrealized loss on derivative instruments 141 4,753 Total current liabilities 41,465 30,530 Long-term liabilities: Unrealized loss on derivative instruments — 297 Total long-term liabilities — 297 Commitments and contingencies Total capitalization and liabilities $ 5,539,006 $ 5,345,950 _______________ 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, 2016 2015 2014 Operating activities: Net cash provided by (used in) operating activities $ 145,719 $ 171,576 $ 225,459 Investing activities: Investment in subsidiaries — (28,900 ) — (Increase) decrease in loan to subsidiary — 28,933 665 Other (6,078 ) (5,632 ) (2,829 ) Net cash provided by (used in) investing activities (6,078 ) (5,599 ) (2,164 ) Financing activities: Dividends paid (148,965 ) (263,059 ) (223,428 ) Issuance of bond — 400,000 — Issuance/redemption of term-loan and other long-term debt 12,480 (299,000 ) — Issue costs and others (3,398 ) (3,341 ) 4 Net cash provided by (used in) by financing activities (139,883 ) (165,400 ) (223,424 ) Increase (decrease) in cash (242 ) 577 (129 ) Cash at beginning of year 639 62 191 Cash at end of year $ 397 $ 639 $ 62 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 $380.6 million , $304.2 million and $236.6 million for the years ended December 31, 2016 , 2015 and 2014 , respectively, and business combination accounting adjustments under ASC 805 recorded at Puget Energy for PSE of $5.2 million , $5.4 million and $3.5 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Investment in subsidiaries includes Puget Energy business combination accounting adjustments under ASC 805 that are recorded at Puget Energy. Change in Accounting Principle On January 1, 2016, the Company changed its method of presenting unamortized debt issuance costs in the balance sheet. The new method of presenting debt issuance costs was adopted to comply with ASU 2015-03, "Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" . ASU 2015-03 requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with the presentation of a debt discount. The prior year comparative balance sheet has been adjusted to apply the new method retrospectively. Due to the change in accounting principle, the December 31, 2015 long-term asset financial statement line item “Other” and the liability financial statement line item “Long-term debt” both decreased $15.6 million 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, 2016
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, 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 Year Ended December 31, 2014 Accounts deducted from assets on balance sheet: Allowance for doubtful accounts receivable $ 7,385 $ 27,228 $ 27,141 $ 7,472

Summary of Significant Accoun29

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
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. In 2009, Puget Holdings LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company.” The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and PSE’s financial statements 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 its natural gas fired combustion turbines 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. Non-Utility Property, Plant and Equipment For PSE, the costs of other property, plant and equipment 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 For financial statement purposes, 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 depreciation of vehicles and equipment is allocated to the asset and expense accounts based on usage. The annual depreciation provision stated as a percent of a depreciable electric utility plant was 2.8% , for each of 2016 , 2015 and 2014 ; depreciable natural gas utility plant was 3.4% , for each of 2016 , 2015 and 2014 ; and depreciable common utility plant was 9.7% , 8.5% and 8.5% in 2016 , 2015 and 2014 , respectively. Depreciation on other property, plant and equipment is calculated primarily on a straight-line basis over the useful lives of the assets. 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 two-step process. The first step compares the carrying amount of the reporting unit with its fair value, with a carrying value higher than fair value indicating potential impairment. If the first step test fails, the second step is performed. 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 2016 using an October 1, 2016 measurement date. The fair value of Puget Energy’s reporting unit was estimated using both discounted cash flow and market approach. Such approaches are considered methodologies that market participants would use. This analysis 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, 2016 . There were no known events or circumstances from the date of the assessment through December 31, 2016 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. Puget Energy and PSE record 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. Puget Energy and PSE record these items at the lower of cost or market value using the weighted-average cost 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 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 and losses 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 due to the length of the amortization. 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 as of July 1, 2013 is 7.77% . 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). 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 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 $235.3 million , $234.2 million and $231.7 million for 2016 , 2015 and 2014 , 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. The non-utility subsidiary recognizes revenue when services are performed or upon the sale of assets. Revenue from retail sales is billed based on tariff rates approved by the Washington Commission. 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 due to weather and gross margin erosion related to 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. To record revenues under this program, the Company must be able to collect the revenue 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. For GAAP purposes only, 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-recorded amounts will be recorded. 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, 2016 and 2015 was $9.8 million each year.
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. The Washington Commission has approved the deferral of certain uninsured qualifying storm damage costs that exceed $8.0 million which will be requested for collection in future rates. 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, who 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	Non-Core Natural 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. PSE records the benefit of the PTCs as a deferred credit until such time as PSE utilizes the tax credit on its tax return. Once utilized, PSE will reclassify the credits to a regulatory liability and pass the benefit to customers.
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, 2016 , 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.

Regulation and Rates (Tables)

Regulation and Rates (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2016
Regulation and Rates [Line Items]
Schedule of Net Regulatory Assets and Liabilities		The net regulatory assets and liabilities at December 31, 2016 and 2015 included the following: Puget Sound Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2016 2015 Colstrip Regulatory Asset (a) $ 176,804 $ — Storm damage costs electric 1 to 2 years 122,709 125,777 Chelan PUD contract initiation 14.8 years 105,140 112,228 Decoupling deferrals and interest 156,408 104,150 Decoupling 24-month revenue reserve (20,847 ) (9,980 ) Total decoupling asset Less than 2 years 135,561 94,170 Lower Snake River 1 to 20.3 years 74,862 79,599 Deferred income taxes (a) 71,517 72,694 Environmental remediation (a) 74,557 66,887 Baker Dam licensing operating and maintenance costs 42 years 61,453 63,394 PGA deferral of unrealized losses on derivative instruments (a) — 60,889 Deferred Washington Commission AFUDC 35 years 51,404 52,197 Unamortized loss on reacquired debt 1 to 30 years 42,196 44,984 Property tax tracker Less than 2 years 41,949 40,353 Energy conservation costs 1 to 2 years 41,027 36,646 White River relicensing and other costs 15.9 years 21,627 23,054 Mint Farm ownership and operating costs 8.3 years 16,319 18,320 Ferndale 2.8 years 11,274 15,253 Electron unrecovered loss 2 years 7,178 10,569 Snoqualmie licensing operating and maintenance costs 28 years 8,018 7,980 Colstrip common property (a) 5,334 6,049 Colstrip major maintenance 2 years 6,589 5,897 Investment in Bonneville Exchange power contract 1 year 1,763 5,290 Snoqualmie 1.8 years 3,251 5,024 PCA mechanism (a) 4,531 — PGA receivable 1 year 2,785 — Various other regulatory assets Varies 25,337 24,248 Total PSE regulatory assets 1,113,185 971,502 Cost of removal (b) (369,300 ) (347,472 ) Treasury grants 3 to 42 years (133,709 ) (157,102 ) Production tax credits (c) (93,616 ) (93,616 ) Decoupling ROR excess earnings (13,300 ) (25,483 ) Decoupling deferrals and interest (16,448 ) — Total decoupling liability Less than 2 years (29,748 ) (25,483 ) PGA payable 1 year — (12,589 ) Summit purchase option buy-out 3.8 years (6,038 ) (7,612 ) Deferral of treasury grant amortization Less than 3 years (3,920 ) (6,058 ) PGA deferral of unrealized gains on derivative instruments (a) (7,517 ) — Lower Snake River interest due Less than 2 years (4,189 ) — Various other regulatory liabilities Up to 4 years (5,259 ) (13,751 ) Total PSE regulatory liabilities (653,296 ) (663,683 ) PSE net regulatory assets (liabilities) $ 459,889 $ 307,819 _______________ (a) Amortization periods vary depending on timing of underlying transactions or awaiting regulatory approval in a future Washington Commission rate proceeding. (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. Puget Energy Remaining Amortization Period December 31, (Dollars in Thousands) 2016 2015 Total PSE regulatory assets (a) $ 1,113,185 $ 971,502 Puget Energy acquisition adjustments: Regulatory assets related to power contracts 1 to 21 years 22,613 26,223 Various other regulatory assets Varies 517 549 Total Puget Energy regulatory assets 1,136,315 998,274 Total PSE regulatory liabilities (a) (653,296 ) (663,683 ) Puget Energy acquisition adjustments: Regulatory liabilities related to power contracts 1 to 36 years (275,061 ) (325,788 ) Various other regulatory liabilities Varies (1,326 ) (1,347 ) Total Puget Energy regulatory liabilities (929,683 ) (990,818 ) Puget Energy net regulatory asset (liabilities) $ 206,632 $ 7,456 _______________ (a) Puget Energy’s regulatory assets and liabilities include purchase accounting adjustments under ASC 805.
Decoupling Mechanism [Member]
Regulation and Rates [Line Items]
Schedule of Graduated Scale of Rate Adjustment Mechanisms [Table Text Block] [Table Text Block]		In addition, PSE exceeded the earnings test threshold in 2016, 2015 and 2014. The amount of the reduction to the 2016 decoupling deferral will not be known until the final earnings test result is filed in PSE's decoupling mechanism filing that will be made on March 31, 2017. PSE recorded the following reductions in decoupling deferrals to the electric and natural gas rate increases above: Effective Date Reduction in Rate Increases due to Excess Earnings (Dollars in Millions) Electric: 2016 (estimated) $11.2 2015 16.3 2014 3.4 Natural Gas: 2016 (estimated) $2.1 2015 9.2 2014 —
Schedule of Graduated Scale of Rate Adjustment Mechanisms		The Washington Commission approved the following PSE requests to change rates under its electric and natural gas decoupling mechanisms: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) Electric: May 1, 2016 1.0% $20.8 May 1, 2015 2.6 53.8 May 1, 2014 0.5 10.6 Natural Gas: May 1, 2016 2.8% $25.4 May 1, 2015 2.1 22.0 May 1, 2014 (0.1) (1.0)
Schedule of Deferrals Not Included in Rate Increases [Table Text Block]		As noted earlier, the Company is also limited to a 3.0% annual decoupling related cap on increases in total revenue. This limitation has been triggered as follows: Effective Date Accrued Through Deferrals not Included in Annual Rate Increases (Dollars in Millions) Electric: 2015 $— 2014 1.9 Natural Gas: 2015 $28.7 2014 8.2 Existing deferrals may be included in customer rates beginning in May 2018, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases.
Power Cost Only Rate Case (PCORC) | Electric [Member]
Regulation and Rates [Line Items]
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments		The following table sets forth PCORC and update compliance filing rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) December 1, 2016 (1.7)% $(37.3) December 1, 2014 (0.9) (19.4)
Property tax tracker | Electric [Member]
Regulation and Rates [Line Items]
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments		The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2016 0.3% $5.7 May 1, 2015 0.3 6.5 May 1, 2014 0.5 11.0
Property tax tracker | Gas
Regulation and Rates [Line Items]
Schedule of Graduated Scale of Rate Adjustment Mechanisms		The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2016 0.4% $3.5 June 1, 2015 (0.2) (2.3) May 1, 2014 0.6 5.6
Conservation Rider [Member] | Electric [Member]
Regulation and Rates [Line Items]
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments		The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2017, proposed 0.7% $16.5 May 1, 2016 (0.5) (11.7) May 1, 2015 0.2 4.2 May 1, 2014 0.6 12.2
Conservation Rider [Member] | Gas
Regulation and Rates [Line Items]
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments		The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding annual impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2017, proposed (0.1)% (1.0) May 1, 2016 0.3 2.9 May 1, 2015 0.2 2.3
PCA Mechanism [Member] | Electric [Member]
Regulation and Rates [Line Items]
Schedule of Graduated Scale of Rate Adjustment Mechanisms	Annual Power Cost Variability Company’s Share Customers' Share +/- $20 million 100% —% +/- $20 million - $40 million 50 50 +/- $40 million - $120 million 10 90 +/- $120 + million 5 95	On August 7, 2015, the Washington Commission issued an order approving the settlement proposing changes to the PCA mechanism. The settlement agreement took effect January 1, 2017 and will apply the following graduated scale: Annual Power Cost Variability Company's Share Customers' Share Over or Under Collection: Over Under Over Under Over or Under Collected by up to $17 million 100% 100% —% —% Over or Under Collected by between $17 million - $40 million 35 50 65 50 Over or Under Collected beyond $40 + million 10 10 90 90
Treasury grants | Electric [Member]
Regulation and Rates [Line Items]
Schedule of Graduated Scale of Rate Adjustment Mechanisms		The following table sets forth Federal Incentive Tracker Tariff rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates from prior year Total credit to be passed back to eligible customers (Dollars in Millions) January 1, 2017, proposed 0.3% $(51.7) January 1, 2016 (0.2) (57.3) January 1, 2015 (0.2) (55.2) January 1, 2014 (0.3) (58.5)
Cost recovery mechanism [Member] | Gas
Regulation and Rates [Line Items]
Schedule of Graduated Scale of Rate Adjustment Mechanisms		The following table sets forth CRM rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) November 1, 2016 0.6% $5.6 November 1, 2015 0.5 5.3 November 1, 2014 0.2 2.3
Purchased Gas Adjustment (PGA) | Gas
Regulation and Rates [Line Items]
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments		The following table sets forth PGA rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) November 1, 2016 (0.4)% $(4.1) November 1, 2015 (17.4) (185.9) November 1, 2014 2.5 23.3

Utility Plant (Tables)

Utility Plant (Tables)	12 Months Ended
	Dec. 31, 2016
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) 2016 2015 2016 2015 Distribution plant 10-50 $ 5,287,542 $ 5,007,077 $ 6,922,176 $ 6,657,597 Production plant 25-125 3,007,546 3,028,481 3,910,129 3,950,231 Transmission plant 45-65 1,307,687 1,236,823 1,420,334 1,351,216 General plant 5-35 541,424 491,845 611,237 563,850 Intangible plant (including capitalized software) 3-50 347,697 305,705 338,327 294,380 Plant acquisition adjustment 2-22 242,826 242,826 282,792 282,792 Underground storage 25-60 30,695 28,914 44,206 42,545 Liquefied natural gas storage 25-45 12,628 12,628 14,498 14,498 Plant held for future use NA 52,484 55,890 52,636 56,042 Recoverable Cushion Gas NA 8,655 8,655 8,655 8,655 Plant not classified 1-125 159,345 65,892 159,345 65,892 Grant NA (99,100 ) (102,379 ) (99,100 ) (102,379 ) Capital leases, net of accumulated amortization 1 2 645 378 645 378 Less: accumulated provision for depreciation (2,161,796 ) (1,878,868 ) (4,927,602 ) (4,681,830 ) Subtotal $ 8,738,278 $ 8,503,867 $ 8,738,278 $ 8,503,867 Construction work in progress NA 420,278 408,795 420,278 408,795 Net utility plant $ 9,158,556 $ 8,912,662 $ 9,158,556 $ 8,912,662 _______________ 1 Accumulated amortization of capital leases at Puget Energy and PSE was $0.6 million in 2016 and $32.3 million in 2015 .
Schedule of Jointly Owned Utility Plants	These amounts are also included in the Utility Plant table above. Puget Energy’s Share Puget Sound Energy’s Share Jointly Owned Generating Plants (Dollars in Thousands) Energy Source (Fuel) Company’s Ownership Share Plant in Service at Cost Accumulated Depreciation Plant in Service at Cost Accumulated Depreciation Colstrip Units 1 & 2 Coal 50% $ 70,717 $ (22,284 ) $ 204,334 $ (155,902 ) Colstrip Units 3 & 4 Coal 25% 307,383 (40,343 ) 575,902 (308,861 ) Colstrip Units 1 – 4 Common Facilities Coal various 83 (27 ) 252 (196 ) Frederickson 1 Natural Gas 49.85% 61,780 (9,779 ) 70,729 (18,728 ) Jackson Prairie Natural Gas Storage 33.34% 30,021 (5,544 ) 44,206 (19,730 )
Schedule of Asset Retirement Obligations	The following table describes the changes to the Company’s ARO liability as of December 31, 2016 and 2015 : At December 31, (Dollars in Thousands) 2016 2015 Asset retirement obligation at beginning of period $ 85,028 $ 48,909 New asset retirement obligation recognized in the period — 34,534 Liability adjustment in the period (411 ) (3,628 ) Revisions in estimated cash flows 113,081 3,403 Accretion expense 2,647 1,810 Asset retirement obligation at end of period $ 200,345 $ 85,028

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Instrument [Line Items]
Schedule of Long-Term Debt Instruments	(Dollars in Thousands) At December 31, Series Type Due 2016 2015 Puget Sound Energy: 5.500% Promissory Note 2017 $ 2,412 $ 2,412 6.740% Senior Secured Note 2018 200,000 200,000 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 * (28,974 ) (31,910 ) Total PSE long-term debt 3,747,298 3,744,362 Puget Energy: * Fair value adjustment of PSE long-term debt * (199,436 ) (207,977 ) * Revolving Credit Agreement 2018 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 * (6,269 ) (8,867 ) Total Puget Energy long-term debt $ 5,354,073 $ 5,327,518 _______________ * Not Applicable. PSE's s
Schedule of Maturities of Long-Term Debt	pal amounts of long-term debt maturities for the next five years and thereafter are as follows: (Dollars in Thousands) 2017 2018 2019 2020 2021 Thereafter Total Maturities of: PSE long-term debt $ 2,412 $ 200,000 $ — $ — $ — $ 3,573,860 $ 3,776,272 Puget Energy long-term debt — 12,480 — 450,000 500,000 850,000 1,812,480 Puget Energy long-term debt $ 2,412 $ 212,480 $ — $ 450,000 $ 500,000 $ 4,423,860 $ 5,588,752

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2016
Leases [Abstract]
Schedule of Operating Lease Expense	Operating lease expenses net of sublease receipts were: (Dollars in Thousands) At December 31, Years Operating Lease Expense 2016 $ 31,786 2015 27,843 2014 30,737
Schedule of Future Minimum Lease Payments for Non-cancellable Leases	Future minimum lease payments for non-cancelable leases net of sublease receipts are: (Dollars in Thousands) At December 31, Future Minimum Lease Payments Years Operating Capital 2017 $ 22,212 $ 296 2018 19,834 296 2019 18,078 74 2020 16,507 — 2021 8,137 — Thereafter 102,393 — Total minimum lease payments $ 187,161 $ 666

Accounting for Derivative Ins34

Accounting for Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative [Line Items]
Schedule of Credit Risk Related Contingent Features [Table Text Block]	The table below presents the fair value of the overall contractual contingent liability positions for the Company's derivative activity: Puget Energy and Puget Sound Energy At December 31, (Dollars in Thousands) 2016 2015 Contingent Feature Fair Value 1 Liability Posted Collateral Contingent Collateral Fair Value 1 Liability Posted Collateral Contingent Collateral Credit rating 2 $ 4,894 $ — $ 4,894 $ 24,187 $ — $ 24,187 Requested credit for adequate assurance 7,427 — — 67,003 — — Forward value of contract 3 507 — — — — — Total $ 12,828 $ — $ 4,894 $ 91,190 $ — $ 24,187 _______________ 1 Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable. 2 Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral. 3 Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.
Offsetting Assets and Liabilities [Table Text Block]	The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities: Puget Energy and Puget Sound Energy At December 31, 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 Puget Energy and Puget Sound Energy At December 31, 2015 (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 $ 29,643 $ — $ 29,643 $ (23,998 ) $ — $ 5,645 Liabilities: Energy derivative contracts 179,196 — 179,196 (23,998 ) — 155,198 Interest rate swaps 2 5,050 — 5,050 — — 5,050 _______________ 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.
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	The following table presents the volumes, fair values and locations 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 Liabilities 2 2016 2015 2016 2015 2016 2015 Interest rate swap derivatives 3 $450.0 $450.0 $ — $ — $ 141 $ 5,050 Electric portfolio derivatives * * 36,460 23,443 41,329 112,106 Natural gas derivatives (MMBtus) 4 336.4 369.5 26,619 6,200 19,101 67,090 Total derivative contracts ** ** $ 63,079 $ 29,643 $ 60,571 $ 184,246 Current ** ** $ 54,341 $ 24,418 $ 44,310 $ 136,173 Long-term ** ** 8,738 5,225 16,261 48,073 Total derivative contracts ** ** $ 63,079 $ 29,643 $ 60,571 $ 184,246 _______________ 1 Balance sheet location: Current and Long-term Unrealized gain on derivative instruments. 2 Balance sheet location: Current and Long-term Unrealized loss on derivative instruments. 3 Interest rate swap contracts are only held at Puget Energy. 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 186.8 million One Million British Thermal Units (MMBtus) and purchased electricity of 3.6 million megawatt hours (MWhs) at December 31, 2016 and 202.1 million MMBtus and 0.1 million MWhs at December 31, 2015 . ** Not meaningful and/or applicable.
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 2016 2015 2014 Interest rate contracts: Non-hedged interest rate swap (expense) income $ (1,062 ) $ (3,796 ) $ (3,915 ) Interest expense — 560 500 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 62,318 (9,315 ) (42,334 ) Realized Electric generation fuel (39,656 ) (44,648 ) 6,511 Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 1 21,477 22,548 (41,812 ) Realized Purchased electricity (21,998 ) (39,137 ) (4,212 ) Total gain (loss) recognized in income on derivatives $ 21,079 $ (73,788 ) $ (85,262 )
PUGET SOUND ENERGY, INC.
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 2016 2015 2014 Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net $ 62,318 $ (9,315 ) $ (42,334 ) Realized Electric generation fuel (39,656 ) (44,648 ) 6,511 Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 1 21,477 22,003 (43,302 ) Realized Purchased electricity (21,998 ) (39,137 ) (4,212 ) Total gain (loss) recognized in income on derivatives $ 22,141 $ (71,097 ) $ (83,337 ) _______________ 1 Differences between Puget Energy and PSE for the twelve months ended December 31, 2015 and 2014 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, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Liabilities, Quantitative Information	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 credit spreads as inputs, interpolating to the maturity date of each issue. Carrying values and estimated fair values were as follows: Puget Energy At December 31, 2016 At December 31, 2015 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 210,261 $ 250,000 $ 211,173 Long-term debt (fixed-rate), net of discount 1 2 5,091,593 6,337,287 5,077,518 6,308,831 Long-term debt (variable-rate) 2 12,480 12,480 — — Total $ 5,354,073 $ 6,560,028 $ 5,327,518 $ 6,520,004 Puget Sound Energy At December 31, 2016 At December 31, 2015 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 210,261 $ 250,000 $ 211,173 Long-term debt (fixed-rate), net of discount 2 2 3,497,298 4,360,783 3,494,362 4,329,444 Total $ 3,747,298 $ 4,571,044 $ 3,744,362 $ 4,540,617
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) 2016 2015 2014 (Dollars in Thousands) Electric Gas Total Electric Gas Total Electric Gas Total Balance at beginning of period $ (7,345 ) $ (2,383 ) $ (9,728 ) $ (12,062 ) $ (2,040 ) $ (14,102 ) $ (15,421 ) $ (361 ) $ (15,782 ) Changes during period Realized and unrealized energy derivatives: Included in earnings 1 4,007 — 4,007 (6,432 ) — (6,432 ) (5,537 ) — (5,537 ) Included in regulatory assets / liabilities — 4,312 4,312 — 3,695 3,695 — 1,630 1,630 Settlements 2 (1,129 ) (2,679 ) (3,808 ) 902 (3,885 ) (2,983 ) 1,036 (1,534 ) (498 ) Transferred into Level 3 (3,021 ) — (3,021 ) (787 ) — (787 ) 5,155 (585 ) 4,570 Transferred out of Level 3 8,460 1,375 9,835 11,034 (153 ) 10,881 2,705 (1,190 ) 1,515 Balance at end of period $ 972 $ 625 $ 1,597 $ (7,345 ) $ (2,383 ) $ (9,728 ) $ (12,062 ) $ (2,040 ) $ (14,102 ) _______________ 1 Income Statement location: 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 $2.0 million , $(7.4) million and $(9.6) million for the years ended December 31, 2016 , 2015 and 2014 , respectively. 2 The Company had no purchases, sales or issuances during the reported periods.
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Table Text Block]	Below are the forward price ranges for the Company's commodity contracts, as of December 31, 2016 : Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $5,794 $4,822 Discounted cash flow Power Prices $11.86 per MWh $33.52 per MWh $27.61 per MWh Natural gas $3,303 $2,678 Discounted cash flow Natural Gas Prices $2.00 per MMBtu $3.24 per MMBtu $2.42 per MMBtu _______________ 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, 2016 , 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 $0.2 million . Below are significant unobservable inputs used in estimating the impaired long term power purchase contracts' fair value in 2016 and 2015 : Puget Energy Valuation Date Unobservable Input Low High Average September 30, 2016 Power prices $24.24 per MWh $58.96 per MWh $39.31 per MWh Power contract costs (in thousands) $618 per year $4,633 per year $2,472 per year March 31, 2016 Power prices $9.46 per MWh $25.96 per MWh $21.38 per MWh Power contract costs (in thousands) $4,100 per qtr. $4,659 per qtr. $4,452 per qtr. December 31, 2015 Power prices $15.16 per MWh $27.25 per MWh $23.23 per MWh Power contract costs (in thousands) $4,100 per qtr. $4,659 per qtr. $4,417 per qtr. 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 2016 and 2015 , Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets.
Schedule of Impaired Intangible Assets [Table Text Block]	n 2016 and 2015 , due to decreases in forecasted revenue and cost estimates and continued significant decreases in forward power prices, 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, 2016 Priest Rapids $ 18,969 $ 6,191 $ 12,778 March 31, 2016 Wells Hydro 25,193 19,855 5,338 December 31, 2015 Wells Hydro 32,988 27,628 5,360
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 Fair Value Fair Value At December 31, 2016 At December 31, 2015 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Liabilities: Interest rate derivative instruments $ 141 $ — $ 141 $ 5,050 $ — $ 5,050 Total derivative liabilities $ 141 $ — $ 141 $ 5,050 $ — $ 5,050 Puget Energy and Fair Value Fair Value At December 31, 2016 At December 31, 2015 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 30,666 $ 5,794 $ 36,460 $ 10,709 $ 12,734 $ 23,443 Natural gas derivative instruments 23,316 3,303 26,619 4,538 1,662 6,200 Total derivative assets $ 53,982 $ 9,097 $ 63,079 $ 15,247 $ 14,396 $ 29,643 Liabilities: Electric derivative instruments $ 36,507 $ 4,822 $ 41,329 $ 92,027 $ 20,079 $ 112,106 Natural gas derivative instruments 16,423 2,678 19,101 63,045 4,045 67,090 Total derivative liabilities $ 52,930 $ 7,500 $ 60,430 $ 155,072 $ 24,124 $ 179,196

Retirement Benefits (Tables)

Retirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 : Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Change in benefit obligation: Benefit obligation at beginning of period $ 643,088 $ 690,194 $ 51,279 $ 55,855 $ 13,946 $ 15,688 Service cost 18,913 21,287 1,085 1,108 93 112 Interest cost 28,689 28,088 2,325 2,281 533 621 Actuarial loss (gain) 1,545 (55,665 ) 106 (4,430 ) (2,262 ) (1,416 ) Benefits paid (38,730 ) (39,963 ) (3,061 ) (3,535 ) (1,264 ) (1,354 ) Medicare part D subsidy received — — — — 148 295 Administrative expense (898 ) (853 ) — — — — Benefit obligation at end of period $ 652,607 $ 643,088 $ 51,734 $ 51,279 $ 11,194 $ 13,946
Schedule of Changes in Fair Value of Plan Assets	Puget Energy and Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Change in plan assets: Fair value of plan assets at beginning of period $ 598,865 $ 626,173 $ — $ — $ 7,203 $ 8,360 Actual return on plan assets 37,022 (4,489 ) — — 926 (378 ) Employer contribution 24,000 18,000 3,061 3,535 335 575 Benefits paid (38,730 ) (39,963 ) (3,061 ) (3,535 ) (1,264 ) (1,354 ) Administrative expense (897 ) (856 ) — — — — Fair value of plan assets at end of period $ 620,260 $ 598,865 $ — $ — $ 7,200 $ 7,203 Funded status at end of period $ (32,347 ) $ (44,223 ) $ (51,734 ) $ (51,279 ) $ (3,994 ) $ (6,743 )
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) 2016 2015 2016 2015 2016 2015 Amounts recognized in Statement of Financial Position consist of: Noncurrent assets $ — $ — $ — $ — $ — $ — Current liabilities — — (1,911 ) (2,545 ) (325 ) (353 ) Noncurrent liabilities (32,347 ) (44,223 ) (49,823 ) (48,734 ) (3,669 ) (6,390 ) Net assets (liabilities) $ (32,347 ) $ (44,223 ) $ (51,734 ) $ (51,279 ) $ (3,994 ) $ (6,743 )
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) 2016 2015 2016 2015 2016 2015 Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets: Projected benefit obligation $ 652,607 $ 643,088 $ 51,734 $ 51,279 $ 11,194 $ 13,946 Accumulated benefit obligation 641,855 635,599 47,639 46,978 11,092 13,828 Fair value of plan assets 620,260 598,865 — — 7,200 7,203
Schedule of Net Benefit Costs	Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2014 2016 2015 2014 2016 2015 2014 Components of net periodic benefit cost: Service cost $ 18,913 $ 21,287 $ 17,437 $ 1,085 $ 1,108 $ 1,042 $ 93 $ 112 $ 112 Interest cost 28,689 28,088 28,039 2,325 2,281 2,310 533 621 684 Expected return on plan assets (46,619 ) (45,038 ) (42,464 ) — — — (446 ) (531 ) (535 ) Amortization of prior service cost (credit) (1,980 ) (1,980 ) (1,980 ) 42 42 42 — — — Amortization of net loss (gain) — 3,887 — 911 1,641 913 (386 ) (130 ) (393 ) Net periodic benefit cost $ (997 ) $ 6,244 $ 1,032 $ 4,363 $ 5,072 $ 4,307 $ (206 ) $ 72 $ (132 )
Schedule of Amounts Recognized in Other Comprehensive Income (Loss)	Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 11,141 $ (6,136 ) $ 106 $ (4,430 ) $ (2,742 ) $ (508 ) Amortization of net loss (gain) — (3,887 ) (910 ) (1,641 ) 385 131 Amortization of prior service credit 1,980 1,980 (42 ) (42 ) — — Total change in other comprehensive income for year $ 13,121 $ (8,043 ) $ (846 ) $ (6,113 ) $ (2,357 ) $ (377 )
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 2016 2015 2014 2016 2015 2014 2016 2015 2014 Discount rate 4.50 % 4.65 % 4.25 % 4.50 % 4.65 % 4.25 % 4.50 % 4.65 % 4.25 % 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 — — — — — — 8.80 7.20 5.70 Benefit Cost Assumptions Discount rate 4.65 % 4.25 % 5.10 % 4.65 % 4.25 % 5.10 % 4.65 % 4.25 % 5.10 % Return on plan assets 7.75 7.75 7.75 — — — 6.75 7.00 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 — — — — — — 5.30 7.20 6.70
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates	A 1.0% change in the assumed medical inflation rate would have the following effects: 2016 2015 (Dollars in Thousands) 1% Increase 1% Decrease 1% Increase 1% Decrease Effect on post-retirement benefit obligation $ 38 $ (35 ) $ 52 $ (42 ) Effect on service and interest cost components 2 (2 ) 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) 2017 2018 2019 2020 2021 2022-2026 Qualified Pension total benefits $ 41,400 $ 42,500 $ 43,600 $ 44,600 $ 45,200 $ 240,800 SERP Pension total benefits 1,911 5,278 5,666 4,454 1,724 34,043 Other Benefits total with Medicare Part D subsidy 928 893 863 829 787 3,873 Other Benefits total without Medicare Part D subsidy 1,256 1,239 1,216 1,191 1,158 5,294
Schedule of Allocation of Plan Assets	The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, 2016 and 2015 : Recurring Fair Value Measures Recurring Fair Value Measures As of December 31, 2016 As of December 31, 2015 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual Funds $ 181,212 $ — $ 181,212 $ 169,165 $ — $ 169,165 Common Stock 154,255 — $ 154,255 146,321 — $ 146,321 Government Securities 18,754 16,197 $ 34,951 8,835 14,268 $ 23,103 Corporate Bonds — 38,543 $ 38,543 — 44,157 $ 44,157 Subtotal 354,221 54,740 408,961 324,321 58,425 382,746 Investments measured at NAV 1 * * 222,819 * * 223,663 Net (payable) receivable * * (9,894 ) * * (7,544 ) Total assets * * $ 621,886 * * $ 598,865 _______________ 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 consist of common/collective trust funds and two partnerships held as of December 31, 2016 . 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, 2016 As of December 31, 2015 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual fund 1 $ 7,182 $ — $ 7,182 $ 7,135 $ — $ 7,135 Cash equivalents 2 — 80 80 — 68 68 Total assets $ 7,182 $ 80 $ 7,262 $ 7,135 $ 68 $ 7,203 _______________ 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, 2016 . 2 The investment consists of a money market fund (at level 1) and a collective trust fund (at level 2). The money market fund is valued at the net asset value per share of $1.00 per unit as of December 31, 2016 . The collective trust fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or short-term in nature. 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
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	Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 56,588 $ 45,447 $ 9,043 $ 9,848 $ (4,190 ) $ (1,834 ) Prior service cost (credit) (9,822 ) (11,802 ) 246 288 — — Total $ 46,766 $ 33,645 $ 9,289 $ 10,136 $ (4,190 ) $ (1,834 )
PUGET SOUND ENERGY, INC.
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) 2016 2015 2016 2015 2016 2015 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 217,143 $ 221,064 $ 11,978 $ 13,202 $ (5,994 ) $ 3,834 Prior service cost (credit) (7,806 ) (9,379 ) 251 295 — — Total $ 209,337 $ 211,685 $ 12,229 $ 13,497 $ (5,994 ) $ 3,834
Schedule of Net Benefit Costs	Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2014 2016 2015 2014 2016 2015 2014 Components of net periodic benefit cost: Service cost $ 18,913 $ 21,287 $ 17,437 $ 1,085 $ 1,108 $ 1,042 $ 93 $ 112 $ 112 Interest cost 28,689 28,088 28,039 2,325 2,281 2,310 533 621 684 Expected return on plan assets (46,814 ) (45,462 ) (43,252 ) — — — (446 ) (531 ) (535 ) Amortization of prior service cost (credit) (1,573 ) (1,573 ) (1,573 ) 44 44 44 — 3 3 Amortization of net loss(gain) 15,257 20,555 13,195 1,330 2,120 1,461 (632 ) (406 ) (702 ) Net periodic benefit cost $ 14,472 $ 22,895 $ 13,846 $ 4,784 $ 5,553 $ 4,857 $ (452 ) $ (201 ) $ (438 )
Schedule of Amounts Recognized in Other Comprehensive Income (Loss)	Puget Sound Energy Qualified Pension Benefit SERP Pension Benefits Other Benefits (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 11,336 $ (5,711 ) $ 106 $ (4,430 ) $ (2,742 ) $ (508 ) Amortization of net (loss) gain (15,257 ) (20,556 ) (1,330 ) (2,120 ) 631 407 Amortization of prior service cost (credit) 1,573 1,573 (44 ) (44 ) — (3 ) Total change in other comprehensive income for year $ (2,348 ) $ (24,694 ) $ (1,268 ) $ (6,594 ) $ (2,111 ) $ (104 )

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
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) 2016 2015 2014 Charged to operating expenses: Current: Federal $ — $ — $ — State 20 — — Deferred: Federal 140,315 91,968 57,152 State (131 ) (192 ) (167 ) Total income tax expense $ 140,204 $ 91,776 $ 56,985
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) 2016 2015 2014 Income taxes at the statutory rate $158,586 $116,534 $80,087 Increase (decrease): Production tax credit 1 (12,925) (19,470) (23,073) Utility plant differences 3,966 5,671 7,090 Treasury grant amortization (9,788) (8,807) (8,808) Other - net 365 (2,152) 1,689 Total income tax expense $140,204 $91,776 $56,985 Effective tax rate 30.9% 27.6% 24.9%
Schedule of Deferred Tax Assets and Liabilities	The Company’s net deferred tax liability at December 31, 2016 and 2015 is composed of amounts related to the following types of temporary differences: Puget Energy At December 31, (Dollars in Thousands) 2016 2015 Utility plant and equipment $ 1,880,782 $ 1,788,078 Regulatory asset for income taxes 72,038 73,231 Fair value of debt instruments 67,444 70,260 Pensions and other compensation 77,230 77,230 Other, net deferred tax liabilities 119,050 84,397 Subtotal deferred tax liabilities 2,216,544 2,093,196 Net operating loss carryforward (352,827 ) (384,338 ) Production tax credit carryforward (190,999 ) (178,075 ) Regulatory liability on production tax credit (101,787 ) (94,828 ) Subtotal deferred tax assets (645,613 ) (657,241 ) Total net deferred tax liabilities $ 1,570,931 $ 1,435,955
PUGET SOUND ENERGY, INC.
Income Tax Disclosures [Line Items]
Schedule of Components of Income Tax Expense (Benefit)	Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2016 2015 2014 Charged to operating expenses: Current: Federal $ — $ — $ — State 20 — — Deferred: Federal 175,327 125,900 89,342 State — — — Total income tax expense $ 175,347 $ 125,900 $ 89,342
Schedule of Effective Income Tax Rate Reconciliation	Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2016 2015 2014 Income taxes at the statutory rate $194,572 $150,531 $114,084 Increase (decrease): Production tax credit 1 (12,925) (19,470) (23,073) Utility plant differences 3,966 5,671 7,090 Treasury grant amortization (9,788) (8,807) (8,808) Other - net (478) (2,025) 49 Total income tax expense $175,347 $125,900 $89,342 Effective tax rate 31.5% 29.3% 27.4%
Schedule of Deferred Tax Assets and Liabilities	Puget Sound Energy At December 31, (Dollars in Thousands) 2016 2015 Utility plant and equipment $ 1,880,782 $ 1,788,078 Regulatory asset for income taxes 71,517 72,694 Other, net deferred tax liabilities 113,938 80,351 Subtotal deferred tax liabilities 2,066,237 1,941,123 Net operating loss carryforward (41,061 ) (111,604 ) Production tax credit carryforward (190,999 ) (178,075 ) Regulatory liability on production tax credit (101,787 ) (94,828 ) Subtotal deferred tax assets (333,847 ) (384,507 ) Total net deferred tax liabilities $ 1,732,390 $ 1,556,616

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
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) 2016 2015 2014 PUD contract costs $ 77,667 $ 72,833 $ 69,661 As of December 31, 2016 , 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 2017 Costs 2017 Debt Service Costs Interest included in 2017 Debt Service Costs Debt Outstanding Chelan County PUD: Rock Island Project 2031 25.0 % 156 $ 28,886 $ 10,430 $ 5,638 $ 88,518 Rocky Reach Project 2031 25.0 325 28,376 7,574 2,854 44,305 Douglas County PUD: Wells Project 2018 29.9 251 16,547 8,004 2,153 54,847 Grant County PUD: Priest Rapids Development 2052 0.6 8 2,809 1,670 1,670 18,579 Wanapum Development 2052 0.6 9 2,809 1,670 1,670 18,579 Total 749 $ 79,427 $ 29,348 $ 13,985 $ 224,828
Schedule of Long-term Purchase Commitments	The following table summarizes the Company’s estimated obligations for service contracts through the terms of its existing contracts. Service Contract Obligations (Dollars in Thousands) 2017 2018 2019 2020 2021 Thereafter Total Energy production service contracts $ 31,573 $ 31,970 $ 31,313 $ 50,656 $ 32,934 $ 204,687 $ 383,133 Automated meter reading system 18,175 18,693 18,718 20,191 20,939 116,811 213,527 Total $ 49,748 $ 50,663 $ 50,031 $ 70,847 $ 53,873 $ 321,498 $ 596,660 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) 2017 2018 2019 2020 2021 Thereafter Total Natural gas supply $ 320,238 $ 211,256 $ 230,109 $ 177,390 $ 107,621 $ — $ 1,046,614 Firm transportation service 156,290 154,155 149,277 140,672 128,049 467,266 1,195,709 Firm storage service 6,616 3,861 2,943 1,950 1,619 2,475 19,464 Total $ 483,144 $ 369,272 $ 382,329 $ 320,012 $ 237,289 $ 469,741 $ 2,261,787 These contracts have varying terms and may include escalation and termination provisions. (Dollars in Thousands) 2017 2018 2019 2020 2021 Thereafter Total Columbia River projects $ 73,733 $ 69,527 $ 58,921 $ 59,172 $ 56,396 $ 597,468 $ 915,217 Other utilities 10,499 1,257 888 — — — 12,644 Non-utility contracts 198,681 203,428 208,328 212,042 218,431 935,826 1,976,736 Total $ 282,913 $ 274,212 $ 268,137 $ 271,214 $ 274,827 $ 1,533,294 $ 2,904,597

Accumulated Other Comprehensi39

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 , respectively: Puget 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 interest rate swaps Changes in AOCI, net of tax (Dollars in Thousands) Total Balance at December 31, 2013 $ 48,514 $ (705 ) $ (94 ) $ 47,715 Other comprehensive income (loss) before reclassifications (84,301 ) — — (84,301 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax (923 ) 372 94 (457 ) Net current-period other comprehensive income (loss) (85,224 ) 372 94 (84,758 ) 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 ) 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, 2013 $ (87,405 ) $ (2,027 ) $ (6,307 ) $ (95,739 ) Other comprehensive income (loss) before reclassifications (84,955 ) — — (84,955 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 8,079 1,341 317 9,737 Net current-period other comprehensive income (loss) (76,876 ) 1,341 317 (75,218 ) 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 )
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	Details about the reclassifications out of AOCI (loss) for the years ended December 31, 2016 , 2015 and 2014 , 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) 2016 2015 2014 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) (525 ) (5,397 ) (519 ) Total before tax 1,413 (3,459 ) 1,419 Tax (expense) or benefit (495 ) 1,211 (496 ) Net of Tax 918 (2,248 ) 923 Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: Electric derivatives Purchased electricity — (512 ) (572 ) Tax (expense) or benefit — 179 200 Net of Tax — (333 ) (372 ) Net unrealized gain (loss) on interest rate swaps: Interest rate contracts Interest expense — — (144 ) Tax (expense) or benefit — — 50 Net of Tax — — (94 ) Total reclassification for the period Net of Tax $ 918 $ (2,581 ) $ 457 _______________ (a) These AOCI components are included in the computation of net periodic pension cost (see Note 12, "Retirement Benefits" 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) 2016 2015 2014 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,529 $ 1,526 $ 1,526 Amortization of net gain (loss) (a) (15,955 ) (22,268 ) (13,954 ) Total before tax (14,426 ) (20,742 ) (12,428 ) Tax (expense) or benefit 5,049 7,260 4,349 Net of tax (9,377 ) (13,482 ) (8,079 ) Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: Electric derivatives Purchased electricity — (1,055 ) (2,063 ) Tax (expense) or benefit — 369 722 Net of Tax — (686 ) (1,341 ) 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 $ (9,694 ) $ (14,485 ) $ (9,737 ) _______________ (a) These AOCI components are included in the computation of net periodic pension cost (see Note 12, "Retirement Benefits" for additional details).

Summary of Significant Accoun40

Summary of Significant Accounting Policies (Details) $ in Thousands	6 Months Ended	12 Months Ended
	Dec. 31, 2013USD ($)	Dec. 31, 2016USD ($)mi²unit	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jan. 01, 2015	Feb. 06, 2009USD ($)
Accounting Policies
Public Utilities, Allowance for Funds Used During Construction, Rate	7.77%
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	$ 44,302	$ 28,878	42,494	$ 37,527
Revenue Recognition
Excise taxes collected		235,300	234,200	$ 231,700
Allowance for Doubtful Accounts
Allowance for doubtful accounts		9,798	$ 9,756
Self Insurance [Abstract]
Public Utilities, Rate Case, Deferred Storm Costs Threshold		$ 8,000
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		9.70%	8.50%	8.50%
PUGET SOUND ENERGY, INC.
Accounting Policies
Area of service territory (sqmi) | mi²		6,000
Cash and Cash Equivalents
Cash and Cash Equivalents, at Carrying Value	$ 44,111	$ 28,481	$ 41,856	$ 37,466
Allowance for Doubtful Accounts
Allowance for doubtful accounts		$ 9,798	9,756
Maximum
Accounting Policies
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)					3.00%
Adjustments for New Accounting Pronouncement [Member]
Accounting Policies
Unamortized Debt Issuance Expense			38,400
Adjustments for New Accounting Pronouncement [Member] | PUGET SOUND ENERGY, INC.
Accounting Policies
Unamortized Debt Issuance Expense			$ 30,000

Summary of Significant Accoun41

Summary of Significant Accounting Policies - AFUDC (Details)	12 Months Ended
	Dec. 31, 2016
Regulatory Assets [Line Items]
Public Utilities, Property, Plant and Equipment, Non-project Electric Utility Plant, Estimated Useful Life Average	30 years

Regulation and Rates Schedule o

Regulation and Rates Schedule of Allowed Return on the Net Regulatory Assets and Liabilities (Details)	14 Months Ended
	Jun. 30, 2013
Regulated Operations [Abstract]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities	7.80%

Regulation and Rates Net regula

Regulation and Rates Net regulatory assets and liabilities (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets [Line Items]
Regulatory Assets		$ 176,800
PUGET SOUND ENERGY, INC. | Decoupling rate of return sharing [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities		(13,300)	$ (25,483)
PUGET SOUND ENERGY, INC. | Deferral and interest decoupling revenue [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities		(16,448)	0
PUGET SOUND ENERGY, INC. | Cost of removal
Regulatory Assets [Line Items]
Regulatory Liabilities	[1]	$ (369,300)	(347,472)
PUGET SOUND ENERGY, INC. | Treasury grants
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Max		42 years
Regulatory Liabilities		$ (133,709)	(157,102)
PUGET SOUND ENERGY, INC. | Deferred income tax charge
Regulatory Assets [Line Items]
Regulatory Liabilities	[2]	$ (93,616)	(93,616)
PUGET SOUND ENERGY, INC. | Decoupling over-collection
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		2 years
Regulatory Liabilities		$ (29,748)	(25,483)
PUGET SOUND ENERGY, INC. | PGA payable
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		1 year
Regulatory Liabilities		$ 0	(12,589)
PUGET SOUND ENERGY, INC. | Summit purchase option buy-out
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		3 years 10 months
Regulatory Liabilities		$ (6,038)	(7,612)
PUGET SOUND ENERGY, INC. | Treasury grant amortization deferral [Member]
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Max		3 years
Regulatory Liabilities		$ (3,920)	(6,058)
PUGET SOUND ENERGY, INC. | Purchased Gas Adjustment Deferral of Unrealized Gains on Derivatives [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	[3]	(7,517)	0
PUGET SOUND ENERGY, INC. | Lower Snake River interest due [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities		$ (4,189)	0
PUGET SOUND ENERGY, INC. | Various other regulatory liabilities
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Max		4 years
Regulatory Liabilities		$ (5,259)	(13,751)
PUGET SOUND ENERGY, INC. | Liabilities, Total
Regulatory Assets [Line Items]
Regulatory Liabilities		(653,296)	(663,683)
PUGET SOUND ENERGY, INC. | Net Regulatory Assets
Regulatory Assets [Line Items]
Net Regulatory Assets		459,889	307,819
PUGET SOUND ENERGY, INC. | Colstrip Regulatory Asset [Domain]
Regulatory Assets [Line Items]
Regulatory Assets	[3]	176,804	0
PUGET SOUND ENERGY, INC. | Storm Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 122,709	125,777
Net Regulatory Assets, Remaining Amortization Period, Max		2 years
PUGET SOUND ENERGY, INC. | Chelan PUD contract initiation
Regulatory Assets [Line Items]
Regulatory Assets		$ 105,140	112,228
Net Regulatory Assets, Remaining Amortization Period		14 years 10 months
PUGET SOUND ENERGY, INC. | Deferred decoupling revenue, gross [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 156,408	104,150
PUGET SOUND ENERGY, INC. | Other decoupling 24 month reserve [Member]
Regulatory Assets [Line Items]
Regulatory Assets		(20,847)	(9,980)
PUGET SOUND ENERGY, INC. | Deferred decoupling revenue, net [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 135,561	94,170
Net Regulatory Assets, Remaining Amortization Period		2 years
PUGET SOUND ENERGY, INC. | Lower Snake River
Regulatory Assets [Line Items]
Regulatory Assets		$ 74,862	79,599
Net Regulatory Assets, Remaining Amortization Period, Max		20 years 4 months
PUGET SOUND ENERGY, INC. | Deferred income tax charge
Regulatory Assets [Line Items]
Regulatory Assets	[3]	$ 71,517	72,694
PUGET SOUND ENERGY, INC. | Environmental remediation
Regulatory Assets [Line Items]
Regulatory Assets	[3]	74,557	66,887
PUGET SOUND ENERGY, INC. | Baker Dam Licensing Operating Maintenance Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 61,453	63,394
Net Regulatory Assets, Remaining Amortization Period		42 years
PUGET SOUND ENERGY, INC. | PGA deferral of unrealized losses on derivative instruments
Regulatory Assets [Line Items]
Regulatory Assets	[3]	$ 0	60,889
PUGET SOUND ENERGY, INC. | Deferred Washington Commission AFUDC
Regulatory Assets [Line Items]
Regulatory Assets		$ 51,404	52,197
Net Regulatory Assets, Remaining Amortization Period, Max		35 years
PUGET SOUND ENERGY, INC. | Unamortized loss on reacquired debt
Regulatory Assets [Line Items]
Regulatory Assets		$ 42,196	44,984
Net Regulatory Assets, Remaining Amortization Period, Max		30 years
PUGET SOUND ENERGY, INC. | Property tax tracker
Regulatory Assets [Line Items]
Regulatory Assets		$ 41,949	40,353
Net Regulatory Assets, Remaining Amortization Period		2 years
PUGET SOUND ENERGY, INC. | Energy Conservation Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 41,027	36,646
Net Regulatory Assets, Remaining Amortization Period, Max		2 years
PUGET SOUND ENERGY, INC. | White River relicensing and other costs
Regulatory Assets [Line Items]
Regulatory Assets		$ 21,627	23,054
Net Regulatory Assets, Remaining Amortization Period		15 years 10 months 24 days
PUGET SOUND ENERGY, INC. | Mint Farm ownership and operating costs
Regulatory Assets [Line Items]
Regulatory Assets		$ 16,319	18,320
Net Regulatory Assets, Remaining Amortization Period		8 years 4 months
PUGET SOUND ENERGY, INC. | Ferndale
Regulatory Assets [Line Items]
Regulatory Assets		$ 11,274	15,253
Net Regulatory Assets, Remaining Amortization Period		2 years 10 months
PUGET SOUND ENERGY, INC. | Electron Unrecovered Loss
Regulatory Assets [Line Items]
Regulatory Assets		$ 7,178	10,569
Net Regulatory Assets, Remaining Amortization Period		2 years
PUGET SOUND ENERGY, INC. | Snoqualmie Licensing Operating Maintenance Costs
Regulatory Assets [Line Items]
Regulatory Assets		$ 8,018	7,980
Net Regulatory Assets, Remaining Amortization Period		28 years
PUGET SOUND ENERGY, INC. | Colstrip common property
Regulatory Assets [Line Items]
Regulatory Assets	[3]	$ 5,334	6,049
PUGET SOUND ENERGY, INC. | Colstrip major maintenance [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 6,589	5,897
Net Regulatory Assets, Remaining Amortization Period		2 years
PUGET SOUND ENERGY, INC. | Investment in Bonneville Exchange power contract
Regulatory Assets [Line Items]
Regulatory Assets		$ 1,763	5,290
Net Regulatory Assets, Remaining Amortization Period		1 year
PUGET SOUND ENERGY, INC. | Snoqualmie
Regulatory Assets [Line Items]
Regulatory Assets		$ 3,251	5,024
Net Regulatory Assets, Remaining Amortization Period		1 year 9 months
PUGET SOUND ENERGY, INC. | PCA Mechanism [Member]
Regulatory Assets [Line Items]
Regulatory Assets	[3]	$ 4,531	0
PUGET SOUND ENERGY, INC. | PGA receivable [Domain]
Regulatory Assets [Line Items]
Regulatory Assets		$ 2,785	0
Net Regulatory Assets, Remaining Amortization Period		1 year
PUGET SOUND ENERGY, INC. | Various other regulatory assets
Regulatory Assets [Line Items]
Regulatory Assets		$ 25,337	24,248
PUGET SOUND ENERGY, INC. | Assets, Total
Regulatory Assets [Line Items]
Regulatory Assets		$ 1,113,185	971,502
Parent Company [Member] | Regulatory liabilities related to power contracts
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Max		36 years
Regulatory Liabilities		$ (275,061)	(325,788)
Parent Company [Member] | Various other regulatory liabilities
Regulatory Assets [Line Items]
Regulatory Liabilities		(1,326)	(1,347)
Parent Company [Member] | Liabilities, Total
Regulatory Assets [Line Items]
Regulatory Liabilities		(929,683)	(990,818)
Parent Company [Member] | Net Regulatory Assets
Regulatory Assets [Line Items]
Net Regulatory Assets		206,632	7,456
Parent Company [Member] | Various other regulatory assets
Regulatory Assets [Line Items]
Regulatory Assets		517	549
Parent Company [Member] | Requlatory Assets Related to Power Contracts
Regulatory Assets [Line Items]
Regulatory Assets		$ 22,613	26,223
Net Regulatory Assets, Remaining Amortization Period, Max		21 years
Parent Company [Member] | Assets, Total
Regulatory Assets [Line Items]
Regulatory Assets		$ 1,136,315	$ 998,274
[1]	The balance is dependent upon the cost of removal of underlying assets and the life of utility plant.
[2]	Amortization will begin once PTCs are utilized by PSE on its tax return.
[3]	Amortization periods vary depending on timing of underlying transactions or awaiting regulatory approval in a future Washington Commission rate proceeding.

Regulation and Rates Rate Adjus

Regulation and Rates Rate Adjustments (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended				14 Months Ended
	Sep. 30, 2014	Mar. 31, 2013	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jun. 30, 2013	Dec. 13, 2017	May 01, 2017	Dec. 01, 2016	Nov. 01, 2016	May 01, 2016	Oct. 31, 2015	Jun. 01, 2015	May 01, 2015	Jan. 01, 2015	Dec. 01, 2014	Nov. 01, 2014	May 01, 2014	Jun. 25, 2013	Mar. 30, 2013	May 14, 2012
Regulation and Rates [Line Items]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities							7.80%
Treasury grant payment received				$ 0	$ 0	$ (107,876)
Public Utilities, Rate Case, Approved Effective Common Equity in Capital Structure																						48.00%
Public Utilities, Rate Case, Approved Effective Return on Equity																						9.80%
Purchased Gas Adjustment (PGA) | Gas
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)											$ (4,100)		$ (185,900)					$ 23,300
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)											(0.40%)		(17.40%)					2.50%
Cost recovery mechanism [Member] | Gas
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)											$ 5,600		$ 5,300					$ 2,300
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)											0.60%		0.50%					0.20%
Property tax tracker | Gas
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)												$ 3,500		$ (2,300)					$ 5,600
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)												0.40%		(0.20%)					0.60%
Property tax tracker | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)												$ 5,700			$ 6,500				$ 11,000
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)												0.30%			0.30%				0.50%
Decoupling Mechanism [Member] | Gas
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)												$ 25,400			$ 22,000				$ (1,000)
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)												2.80%			2.10%	2.20%			(0.10%)
Decoupling Mechanism [Member] | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)												$ 20,800			$ 53,800				$ 10,600
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)												1.00%			2.60%	3.00%			0.50%
Power Cost Only Rate Case (PCORC) | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)										$ (37,300)							$ (19,400)
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)										(1.70%)							(0.90%)
Energy Conservation Costs [Member] | Gas
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)												$ 2,900			$ 2,300
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)												0.30%			0.20%
Energy Conservation Costs [Member] | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)												$ (11,700)			$ 4,200				$ 12,200
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)												(0.50%)			0.20%				0.60%
Jefferson County Public Utility District
Regulation and Rates [Line Items]
Property, Plant and Equipment, Net																					$ 46,700
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		$ 60,000
PUGET SOUND ENERGY, INC.
Regulation and Rates [Line Items]
American Recovery and Reinvestment Tax Act of 2009, Total Grant Pass Through Amount				(57,300)	(55,200)	(58,500)
Treasury grant payment received				$ 0	$ 0	$ (107,876)
American Recovery and Reinvestment Tax Act of 2009, Grant, Overall Average Rate Reduction				(0.20%)	(0.20%)	(0.30%)
PUGET SOUND ENERGY, INC. | Decoupling Mechanism [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)															$ (12,000)
PUGET SOUND ENERGY, INC. | Decoupling Mechanism [Member] | Gas
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)				$ 2,100	$ 9,200	$ 0
PUGET SOUND ENERGY, INC. | Decoupling Mechanism [Member] | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)				11,200	16,300	3,400
PUGET SOUND ENERGY, INC. | Jefferson County Public Utility District
Regulation and Rates [Line Items]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal	$ 7,500
Customers | Jefferson County Public Utility District
Regulation and Rates [Line Items]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal	$ 52,700
Deferral Trigger [Member] [Member]
Regulation and Rates [Line Items]
Annual Power Cost Variability, Amount				$ 20,000																$ 30,000
Maximum
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)																3.00%
Maximum | Decoupling Mechanism [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)																3.00%
Deferred Revenue [Domain] | PUGET SOUND ENERGY, INC. | Decoupling Mechanism [Member] | Gas
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)					28,700	8,200
Deferred Revenue [Domain] | PUGET SOUND ENERGY, INC. | Decoupling Mechanism [Member] | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)					$ 0	$ 1,900
Scenario, Forecast [Member] | Energy Conservation Costs [Member] | Gas
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)												$ (1,000)
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)												(0.10%)
Scenario, Forecast [Member] | Energy Conservation Costs [Member] | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)									$ 16,500
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)									0.70%
Scenario, Forecast [Member] | PUGET SOUND ENERGY, INC.
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			6.69%
American Recovery and Reinvestment Tax Act of 2009, Total Grant Pass Through Amount			$ (51,700)
Public Utilities, Rate Case, Approved Effective Common Equity in Capital Structure								48.50%
Public Utilities, Rate Case, Approved Effective Return on Equity								9.80%
American Recovery and Reinvestment Tax Act of 2009, Grant, Overall Average Rate Reduction			0.30%
Scenario, Forecast [Member] | PUGET SOUND ENERGY, INC. | General Rate Case [Member] | Gas
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Overall Rate Impact Increase (Decrease)								$ (22,300)
Public Utilities, Rate Case, Approved Overall Effective Annual Rate Percentage Increase (Decrease)								(2.40%)
Scenario, Forecast [Member] | PUGET SOUND ENERGY, INC. | General Rate Case [Member] | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Overall Rate Impact Increase (Decrease)								$ 86,300
Public Utilities, Rate Case, Approved Overall Effective Annual Rate Percentage Increase (Decrease)								4.10%
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				21 years

Regulation and Rates (Details)

Regulation and Rates (Details) - USD ($)

3 Months Ended

12 Months Ended

14 Months Ended

Sep. 30, 2014

Mar. 31, 2013

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Jun. 30, 2013

Dec. 13, 2017

May 01, 2017

Dec. 01, 2016

Nov. 01, 2016

May 01, 2016

Oct. 31, 2015

Sep. 30, 2015

Jun. 01, 2015

May 01, 2015

Jan. 01, 2015

Dec. 01, 2014

Nov. 01, 2014

May 01, 2014

Jun. 25, 2013

Mar. 30, 2013

May 14, 2012

Regulation and Rates [Line Items]

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

7.80%

Public Utilities, Rate Case, Approved Effective Common Equity in Capital Structure

48.00%

Public Utilities, Rate Case, Deferred Storm Costs Threshold

$ 8,000,000

Accrual for Environmental Loss Contingencies

24,900,000

Public Utilities, Rate Case, Approved Effective Return on Equity

9.80%

Electric [Member]

Regulation and Rates [Line Items]

Environmental Remediation Expense

6,200,000

Environmental Expense and Liabilities

13,800,000

$ 14,000,000

$ 13,400,000

Gas

Regulation and Rates [Line Items]

Environmental Remediation Expense

38,000,000

Environmental Expense and Liabilities

60,700,000

52,900,000

$ 52,600,000

PUGET SOUND ENERGY, INC.

Regulation and Rates [Line Items]

Regulatory Liabilities Reclassified from Accumulated Depreciation

369,300,000

347,500,000

Storm Damage Costs Incurred During Period

22,000,000

33,600,000

Storm Damage Costs Deferred During Period

$ 12,400,000

$ 22,400,000

American Recovery and Reinvestment Tax Act of 2009, Grant, Overall Average Rate Reduction

0.20%

0.20%

0.30%

American Recovery and Reinvestment Tax Act of 2009, Total Grant Pass Through Amount

$ (57,300,000)

$ (55,200,000)

$ (58,500,000)

Range 1 [Member] | Company's share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Percentage

100.00%

Range 1 [Member] | Customers share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Percentage

0.00%

Range 2 [Member] | Company's share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Percentage

50.00%

Range 2 [Member] | Customers share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Percentage

50.00%

Range 3 [Member] | Company's share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Percentage

10.00%

Range 3 [Member] | Customers share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Percentage

90.00%

Range 4 [Member] | Company's share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Percentage

5.00%

Range 4 [Member] | Customers share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Percentage

95.00%

Under Recovery [Member] | Range 1 [Member] | Company's share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Percentage

100.00%

Under Recovery [Member] | Range 1 [Member] | Customers share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Percentage

0.00%

Under Recovery [Member] | Range 2 [Member] | Company's share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Percentage

50.00%

Under Recovery [Member] | Range 2 [Member] | Customers share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Percentage

50.00%

Under Recovery [Member] | Range 3 [Member] | Company's share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Percentage

10.00%

Under Recovery [Member] | Range 3 [Member] | Customers share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Percentage

90.00%

Over Recovery [Member] | Company's share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Amount

1,000,000

8,700,000

Over Recovery [Member] | Customers share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Amount

0

0

Over Recovery [Member] | Range 1 [Member] | Company's share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Percentage

100.00%

Over Recovery [Member] | Range 1 [Member] | Customers share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Percentage

0.00%

Over Recovery [Member] | Range 2 [Member] | Company's share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Percentage

35.00%

Over Recovery [Member] | Range 2 [Member] | Customers share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Percentage

65.00%

Over Recovery [Member] | Range 3 [Member] | Company's share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Percentage

10.00%

Over Recovery [Member] | Range 3 [Member] | Customers share [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Percentage

90.00%

Decoupling Mechanism [Member] | Electric [Member]

Regulation and Rates [Line Items]

Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)

1.00%

2.60%

3.00%

0.50%

Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)

$ 20,800,000

$ 53,800,000

$ 10,600,000

Decoupling Mechanism [Member] | Gas

Regulation and Rates [Line Items]

Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)

2.80%

2.10%

2.20%

(0.10%)

Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)

$ 25,400,000

$ 22,000,000

$ (1,000,000)

Decoupling Mechanism [Member] | PUGET SOUND ENERGY, INC.

Regulation and Rates [Line Items]

Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)

$ (12,000,000)

Decoupling Mechanism [Member] | PUGET SOUND ENERGY, INC. | Electric [Member]

Regulation and Rates [Line Items]

Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)

11,200,000

16,300,000

3,400,000

Decoupling Mechanism [Member] | PUGET SOUND ENERGY, INC. | Gas

Regulation and Rates [Line Items]

Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)

2,100,000

9,200,000

0

Purchased Gas Adjustment (PGA) | Gas

Regulation and Rates [Line Items]

Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)

(0.40%)

(17.40%)

2.50%

Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)

$ (4,100,000)

$ (185,900,000)

$ 23,300,000

Cost recovery mechanism [Member] | Gas

Regulation and Rates [Line Items]

Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)

0.60%

0.50%

0.20%

Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)

$ 5,600,000

$ 5,300,000

$ 2,300,000

Energy Conservation Costs [Member] | Electric [Member]

Regulation and Rates [Line Items]

Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)

(0.50%)

0.20%

0.60%

Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)

$ (11,700,000)

$ 4,200,000

$ 12,200,000

Energy Conservation Costs [Member] | Gas

Regulation and Rates [Line Items]

Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)

0.30%

0.20%

Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)

$ 2,900,000

$ 2,300,000

Property tax tracker | Electric [Member]

Regulation and Rates [Line Items]

Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)

0.30%

0.30%

0.50%

Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)

$ 5,700,000

$ 6,500,000

$ 11,000,000

Property tax tracker | Gas

Regulation and Rates [Line Items]

Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)

0.40%

(0.20%)

0.60%

Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)

$ 3,500,000

$ (2,300,000)

$ 5,600,000

Power Cost Only Rate Case (PCORC) | Electric [Member]

Regulation and Rates [Line Items]

Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)

(1.70%)

(0.90%)

Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)

$ (37,300,000)

$ (19,400,000)

Scenario, Forecast [Member] | PUGET SOUND ENERGY, INC.

Regulation and Rates [Line Items]

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

7.74%

Public Utilities, Rate Case, Approved Effective Common Equity in Capital Structure

48.50%

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

6.69%

American Recovery and Reinvestment Tax Act of 2009, Grant, Overall Average Rate Reduction

(0.30%)

American Recovery and Reinvestment Tax Act of 2009, Total Grant Pass Through Amount

$ (51,700,000)

Public Utilities, Rate Case, Approved Effective Return on Equity

9.80%

Scenario, Forecast [Member] | Energy Conservation Costs [Member] | Electric [Member]

Regulation and Rates [Line Items]

Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)

0.70%

Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)

$ 16,500,000

Scenario, Forecast [Member] | Energy Conservation Costs [Member] | Gas

Regulation and Rates [Line Items]

Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)

(0.10%)

Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)

$ (1,000,000)

Jefferson County Public Utility District

Regulation and Rates [Line Items]

Property, Plant and Equipment, Net

$ 46,700,000

Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal

$ 60,000,000

Jefferson County Public Utility District | PUGET SOUND ENERGY, INC.

Regulation and Rates [Line Items]

Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal

$ 7,500,000

Jefferson County Public Utility District | Customers

Regulation and Rates [Line Items]

Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal

$ 52,700,000

Maximum

Regulation and Rates [Line Items]

Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)

3.00%

Maximum | Decoupling Mechanism [Member]

Regulation and Rates [Line Items]

Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)

3.00%

Deferred Revenue [Domain] | Decoupling Mechanism [Member] | PUGET SOUND ENERGY, INC. | Electric [Member]

Regulation and Rates [Line Items]

Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)

0

1,900,000

Deferred Revenue [Domain] | Decoupling Mechanism [Member] | PUGET SOUND ENERGY, INC. | Gas

Regulation and Rates [Line Items]

Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)

$ 28,700,000

$ 8,200,000

Deferral Trigger [Member] [Member]

Regulation and Rates [Line Items]

Annual Power Cost Variability, Amount

$ 20,000,000

$ 30,000,000

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

36 years

Treasury grants | PUGET SOUND ENERGY, INC.

Regulation and Rates [Line Items]

Net Regulatory Assets, Remaining Amortization Period, Min

3 years

Net Regulatory Assets, Remaining Amortization Period, Max

42 years

Chelan PUD contract initiation | PUGET SOUND ENERGY, INC.

Regulation and Rates [Line Items]

Net Regulatory Assets, Remaining Amortization Period

14 years 10 months

Ferndale | PUGET SOUND ENERGY, INC.

Regulation and Rates [Line Items]

Net Regulatory Assets, Remaining Amortization Period

2 years 10 months

Deferred decoupling revenue, net [Member] | PUGET SOUND ENERGY, INC.

Regulation and Rates [Line Items]

Net Regulatory Assets, Remaining Amortization Period

2 years

Energy Conservation Costs [Member] | PUGET SOUND ENERGY, INC.

Regulation and Rates [Line Items]

Net Regulatory Assets, Remaining Amortization Period, Min

1 year

Net Regulatory Assets, Remaining Amortization Period, Max

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

21 years

Lower Snake River | PUGET SOUND ENERGY, INC.

Regulation and Rates [Line Items]

Net Regulatory Assets, Remaining Amortization Period, Min

1 year

Net Regulatory Assets, Remaining Amortization Period, Max

20 years 4 months

Storm Costs [Member] | PUGET SOUND ENERGY, INC.

Regulation and Rates [Line Items]

Net Regulatory Assets, Remaining Amortization Period, Min

1 year

Net Regulatory Assets, Remaining Amortization Period, Max

2 years

Unamortized loss on reacquired debt | PUGET SOUND ENERGY, INC.

Regulation and Rates [Line Items]

Net Regulatory Assets, Remaining Amortization Period, Min

1 year

Net Regulatory Assets, Remaining Amortization Period, Max

30 years

Lower Snake River interest due [Member] | PUGET SOUND ENERGY, INC.

Regulation and Rates [Line Items]

Net Regulatory Assets, Remaining Amortization Period

2 years

Dividend Payment Restrictions (

Dividend Payment Restrictions (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Parent [Line Items]
Retained Earnings, Unappropriated	$ 532.9
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio, Threshold For Dividend Payment	2
EBITDA Interest Expense Ratio	3.5
EBITDA to Interest Expense Denominator	1
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End	1
PUGET SOUND ENERGY, INC.
Parent [Line Items]
Dividends, Common Equity Ratio, Threshold For Dividend Payment	44.00%
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio, Threshold For Dividend Payment	3
Dividends, Common Equity Ratio at Period End	47.90%
EBITDA Interest Expense Ratio	5.2
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, 2016	Sep. 30, 2016	Mar. 31, 2016	Dec. 31, 2015
Public Utility, Property, Plant and Equipment
Asset Retirement Obligations, Noncurrent			$ 45,700
Decommissioning Liability, Noncurrent			$ 37,000	$ 19,700
Accumulated amortization of capital leases		$ 600			$ 32,300
Utility Plant
Distribution plant		5,287,542			5,007,077
Production plant		3,007,546			3,028,481
Transmission plant		1,307,687			1,236,823
General plant		541,424			491,845
Intangible plant (including capitalized software)		347,697			305,705
Plant acquisition adjustment		242,826			242,826
Underground storage		30,695			28,914
Liquefied natural gas storage		12,628			12,628
Plant held for future use		52,484			55,890
Recoverable cushion gas		8,655			8,655
Public Utilities, Property, Plant and Equipment, Other Property, Plant and Equipment		159,345			65,892
Public Utilities, Property, Plant and Equipment Grant		(99,100)			(102,379)
Capital leases, net of accumulated amortization	[1]	645			378
Less: Accumulated depreciation and amortization		(2,161,796)			(1,878,868)
Subtotal		8,738,278			8,503,867
Construction work in progress		420,278			408,795
Net utility plant		$ 9,158,556			8,912,662
Minimum
Public Utility, Property, Plant and Equipment
Distribution plant, Estimated Useful Life		10 years
Production plant, Estimated Useful Life		25 years
Transmission plant, Estimated Useful Life		45 years
General plant, Estimated Useful Life		5 years
Intangible plant (including capitalized software), Estimated Useful Life		3 years
Plant acquisition adjustment, Estimated Useful Life		7 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]	1 year
Maximum
Public Utility, Property, Plant and Equipment
Distribution plant, Estimated Useful Life		50 years
Production plant, Estimated Useful Life		125 years
Transmission plant, Estimated Useful Life		65 years
General plant, Estimated Useful Life		35 years
Intangible plant (including capitalized software), Estimated Useful Life		50 years
Plant acquisition adjustment, Estimated Useful Life		30 years
Underground storage, Estimated Useful Life		60 years
Liquefied natural gas storage, Estimated Useful Life		45 years
Public Utilities, Property, Plant and Equipment, Plant Not Classified, Estimated Useful Life		100 years
Capital leases, net of accumulated amortization, Estimated Useful Life	[1]	5 years
PUGET SOUND ENERGY, INC.
Utility Plant
Distribution plant		$ 6,922,176			6,657,597
Production plant		3,910,129			3,950,231
Transmission plant		1,420,334			1,351,216
General plant		611,237			563,850
Intangible plant (including capitalized software)		338,327			294,380
Plant acquisition adjustment		282,792			282,792
Underground storage		44,206			42,545
Liquefied natural gas storage		14,498			14,498
Plant held for future use		52,636			56,042
Recoverable cushion gas		8,655			8,655
Public Utilities, Property, Plant and Equipment, Other Property, Plant and Equipment		159,345			65,892
Public Utilities, Property, Plant and Equipment Grant		(99,100)			(102,379)
Capital leases, net of accumulated amortization	[1]	645			378
Less: Accumulated depreciation and amortization		(4,927,602)			(4,681,830)
Subtotal		8,738,278			8,503,867
Construction work in progress		420,278			408,795
Net utility plant		$ 9,158,556			$ 8,912,662
[1]	Accumulated amortization of capital leases at Puget Energy and PSE was $0.6 million in 2016 and $32.3 million in 2015.

Utility Plant - Jointly Owned U

Utility Plant - Jointly Owned Utility Plant (Details) $ in Thousands	Dec. 31, 2016USD ($)
Colstrip Units 1 & 2
Jointly Owned Utility Plant Interests
Company’s Ownership Share	50.00%
Plant in Service at Cost	$ 70,717
Accumulated Depreciation	$ (22,284)
Colstrip Units 3 & 4
Jointly Owned Utility Plant Interests
Company’s Ownership Share	25.00%
Plant in Service at Cost	$ 307,383
Accumulated Depreciation	(40,343)
Colstrip Units 1 – 4 Common Facilities
Jointly Owned Utility Plant Interests
Plant in Service at Cost	83
Accumulated Depreciation	$ (27)
Frederickson 1
Jointly Owned Utility Plant Interests
Company’s Ownership Share	49.85%
Plant in Service at Cost	$ 61,780
Accumulated Depreciation	$ (9,779)
Jackson Prairie [Member]
Jointly Owned Utility Plant Interests
Company’s Ownership Share	33.34%
Plant in Service at Cost	$ 30,021
Accumulated Depreciation	(5,544)
PUGET SOUND ENERGY, INC. | Colstrip Units 1 & 2
Jointly Owned Utility Plant Interests
Plant in Service at Cost	204,334
Accumulated Depreciation	(155,902)
PUGET SOUND ENERGY, INC. | Colstrip Units 3 & 4
Jointly Owned Utility Plant Interests
Plant in Service at Cost	575,902
Accumulated Depreciation	(308,861)
PUGET SOUND ENERGY, INC. | Colstrip Units 1 – 4 Common Facilities
Jointly Owned Utility Plant Interests
Plant in Service at Cost	252
Accumulated Depreciation	(196)
PUGET SOUND ENERGY, INC. | Frederickson 1
Jointly Owned Utility Plant Interests
Plant in Service at Cost	70,729
Accumulated Depreciation	(18,728)
PUGET SOUND ENERGY, INC. | Jackson Prairie [Member]
Jointly Owned Utility Plant Interests
Plant in Service at Cost	44,206
Accumulated Depreciation	$ (19,730)

Utility Plant - Asset Retiremen

Utility Plant - Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of period	$ 85,028	$ 48,909
New asset retirement obligation recognized in the period	0	34,534
Liability adjustment in the period	(411)	(3,628)
Revisions in estimated cash flows	113,081	3,403
Accretion expense	2,647	1,810
Asset retirement obligation at end of period	$ 200,345	$ 85,028

Long-Term Debt (Schedule of Lon

Long-Term Debt (Schedule of Long-Term Debt Instruments) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Mar. 31, 2016
Debt Instrument [Line Items]
Current borrowing capacity of line of credit		$ 800,000
Proceeds from long-term debt and bonds issued		12,481	$ 825,000	$ 299,000
Total PSE long-term debt		5,588,752
Long Term Debt, Reconciliation, Fair Value Adjustment		(199,436)	(207,977)
Long-term Line of Credit, Noncurrent		12,480	0
Unamortized discount on senior notes		(6,269)	(8,867)
Net PSE long-term debt		$ 5,354,073	5,327,518
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
PUGET SOUND ENERGY, INC.
Debt Instrument [Line Items]
Current borrowing capacity of line of credit		1,000,000
Proceeds from long-term debt and bonds issued		0	425,000	$ 0
Total PSE long-term debt		3,776,272
Unamortized discount on senior notes		(28,974)	(31,910)
Net PSE long-term debt		$ 3,747,298	3,744,362
PUGET SOUND ENERGY, INC. | Senior Notes and First Mortgage Bonds | 5.500% Secured Promissory Note Due 2017
Debt Instrument [Line Items]
Stated interest rate percent		5.50%
Total PSE long-term debt	[1]	$ 2,412	2,412
PUGET SOUND ENERGY, INC. | 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
PUGET SOUND ENERGY, INC. | 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
PUGET SOUND ENERGY, INC. | 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
PUGET SOUND ENERGY, INC. | 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
PUGET SOUND ENERGY, INC. | 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
PUGET SOUND ENERGY, INC. | Senior Secured Note | 6.750% Series Due 2016
Debt Instrument [Line Items]
Stated interest rate percent					6.75%
Total PSE long-term debt					$ 250,000
PUGET SOUND ENERGY, INC. | Senior Secured Note | 6.740% Series Due 2018
Debt Instrument [Line Items]
Stated interest rate percent		6.74%
Total PSE long-term debt		$ 200,000	200,000
PUGET SOUND ENERGY, INC. | 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
PUGET SOUND ENERGY, INC. | 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
PUGET SOUND ENERGY, INC. | 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
PUGET SOUND ENERGY, INC. | 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
PUGET SOUND ENERGY, INC. | 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
PUGET SOUND ENERGY, INC. | 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
PUGET SOUND ENERGY, INC. | 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
PUGET SOUND ENERGY, INC. | 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
PUGET SOUND ENERGY, INC. | 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
PUGET SOUND ENERGY, INC. | 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
PUGET SOUND ENERGY, INC. | 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
PUGET SOUND ENERGY, INC. | 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
PUGET SOUND ENERGY, INC. | Senior Secured Note | 3.650% Senior Secured Note Due 2025 [Member]
Debt Instrument [Line Items]
Total PSE long-term debt		$ 400,000
[1]	Accumulated amortization of capital leases at Puget Energy and PSE was $0.6 million in 2016 and $32.3 million in 2015.

Long-Term Debt (Narrative) (Det

Long-Term Debt (Narrative) (Details) - USD ($)	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015	May 12, 2015	Feb. 10, 2012
Debt Instrument [Line Items]
Long-term debt	$ 5,588,752,000
Current borrowing capacity of line of credit	800,000,000
Maximum borrowing capacity	1,300,000,000
Senior Secured Note | 3.650% Senior Secured Note Due 2025 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 400,000,000		$ 400,000,000
Stated interest rate percent	3.65%
Revolving Credit Facility
Debt Instrument [Line Items]
Current borrowing capacity of line of credit					$ 800,000,000
PUGET SOUND ENERGY, INC.
Debt Instrument [Line Items]
Long-term debt	$ 3,776,272,000
Current borrowing capacity of line of credit	1,000,000,000
Maximum borrowing capacity	1,500,000,000
PUGET SOUND ENERGY, INC. | Senior Secured Note | 4.300% Series Due 2045
Debt Instrument [Line Items]
Long-term debt	$ 425,000,000		425,000,000
Stated interest rate percent	4.30%
PUGET SOUND ENERGY, INC. | Senior Secured Note | 5.197% Series Due 2015
Debt Instrument [Line Items]
Long-term debt			$ 150,000,000
Stated interest rate percent	5.197%
PUGET SOUND ENERGY, INC. | Senior Secured Note | 6.750% Series Due 2016
Debt Instrument [Line Items]
Long-term debt		$ 250,000,000
Stated interest rate percent		6.75%
PUGET SOUND ENERGY, INC. | Senior Secured Note | 3.650% Senior Secured Note Due 2025 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 400,000,000
PUGET SOUND ENERGY, INC. | Senior Notes [Member]
Debt Instrument [Line Items]
Stated interest rate percent				3.65%

Long-Term Debt (Schedule of Mat

Long-Term Debt (Schedule of Maturities of Long-Term Debt) (Details) $ in Thousands	Dec. 31, 2016USD ($)
Maturities of Long-term Debt [Abstract]
2,016	$ 2,412
2,017	212,480
2,018	0
2,019	450,000
2,020	500,000
Thereafter	4,423,860
Total long-term debt	5,588,752
PUGET SOUND ENERGY, INC.
Maturities of Long-term Debt [Abstract]
2,016	2,412
2,017	200,000
2,018	0
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	12,480
2,018	0
2,019	450,000
2,020	500,000
Thereafter	850,000
Total long-term debt	$ 1,812,480

Liquidity Facilities and Othe53

Liquidity Facilities and Other Financing Arrangements (Details) - USD ($)	Feb. 10, 2012	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Short-term Debt [Line Items]
Short-term debt		$ 245,763,000	$ 159,004,000
Current borrowing capacity of line of credit		800,000,000
Maximum borrowing capacity		1,300,000,000
Long-term Line of Credit, Noncurrent		12,480,000	0
Energy Hedging Activities [Member]
Short-term Debt [Line Items]
Current borrowing capacity of line of credit		350,000,000
Senior secured credit facility
Short-term Debt [Line Items]
Short-term debt		$ 0		$ 0
Revolving Credit Facility
Short-term Debt [Line Items]
Current borrowing capacity of line of credit	$ 800,000,000
Basis spread on variable rate (percent)		1.75%
Commitment fee percentage for line of credit	0.275%
PUGET SOUND ENERGY, INC.
Short-term Debt [Line Items]
Short-term debt		$ 245,763,000	$ 159,004,000	$ 159,000,000
Weighted-average interest rate on short-term debt (percent)		3.21%		4.24%
Current borrowing capacity of line of credit		$ 1,000,000,000
Current same-day borrowing capacity		75,000,000
Maximum borrowing capacity		$ 1,500,000,000
Maximum capitalization percentage		65.00%
Derivative, Basis Spread on Variable Rate		1.75%
Line of Credit, Unused Capacity, Commitment Fee Percentage		0.275%
PUGET SOUND ENERGY, INC. | Working Capital Needs
Short-term Debt [Line Items]
Current borrowing capacity of line of credit		$ 650,000,000
PUGET SOUND ENERGY, INC. | Energy Hedging Activities [Member]
Short-term Debt [Line Items]
Outstanding amount for line of credit		1,000,000
Current borrowing capacity of line of credit		350,000,000
PUGET SOUND ENERGY, INC. | Letter of Credit | Working Capital Needs
Short-term Debt [Line Items]
Outstanding amount for line of credit		245,800,000
Current borrowing capacity of line of credit		3,500,000
PUGET SOUND ENERGY, INC. | 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
Parent Company [Member]
Short-term Debt [Line Items]
Long-term Line of Credit, Noncurrent		$ 12,500,000

Leases (Schedule of Operating L

Leases (Schedule of Operating Lease Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
PUGET SOUND ENERGY, INC.
Operating Leases, Rent Expense, Net [Abstract]
Operating lease expense net of sublease receipts	$ 31,786	$ 27,843	$ 30,737

Leases (Schedule of Future Mini

Leases (Schedule of Future Minimum Lease Payments for Non-cancellable Leases) (Details) - PUGET SOUND ENERGY, INC. $ in Thousands	Dec. 31, 2016USD ($)
Operating
2,014	$ 22,212
2,015	19,834
2,016	18,078
2,017	16,507
2,018	8,137
Thereafter	102,393
Total minimum lease payments	187,161
Capital
2,014	296
2,015	296
2,016	74
2,017	0
2,018	0
Thereafter	0
Total minimum lease payments	$ 666

Accounting for Derivative Ins56

Accounting for Derivative Instruments and Hedging Activities (Narrative) (Details) $ in Thousands	Dec. 31, 2016USD ($)Contracts	Dec. 31, 2015USD ($)
Electric Portfolio
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	$ 0	$ 0
Parent Company [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Number of interest rate derivatives held | Contracts	2
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	93.10%
External Credit Rating, Non Investment Grade [Member] | Electric Portfolio
Derivative [Line Items]
Percentage of derivatives with credit risk exposure	6.90%

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, 2016USD ($)MWhMMBTUContracts		Dec. 31, 2015USD ($)MWhMMBTU
Derivative [Line Items]
Assets, Current		$ 54,341		$ 24,418
Assets, Long-term		8,738		5,225
Liabilities, Current		44,310		136,173
Liabilities, Long-term		16,261		48,073
Parent Company [Member]
Derivative [Line Items]
Liabilities, Current		141		4,753
Liabilities, Long-term		0		297
PUGET SOUND ENERGY, INC.
Derivative [Line Items]
Assets, Current		54,341		24,418
Assets, Long-term		8,738		5,225
Liabilities, Current		44,170		131,420
Liabilities, Long-term		$ 16,261		47,776
Interest Rate Swap [Member] | Parent Company [Member]
Derivative [Line Items]
Number of interest rate derivatives held | Contracts		2
Commodity Contract
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	[1]	$ 63,079		29,643
Total derivative assets		63,079		29,643
Total derivative liabilities		60,430		179,196
Derivative Asset, Collateral, Obligation to Return Cash, Offset		0		0
Derivative, Collateral, Obligation to Return Securities		(42,858)		(23,998)
Derivative, Collateral, Obligation to Return Cash		0		0
Derivative Asset, Fair Value, Amount Offset Against Collateral		20,221		5,645
Derivative Liability, Fair Value, Gross Liability	[1]	60,430		179,196
Derivative Liability, Collateral, Right to Reclaim Cash, Offset		0	[2]	0
Derivative, Collateral, Right to Reclaim Securities		(42,858)		(23,998)
Derivative, Collateral, Right to Reclaim Cash		0		0
Derivative Liability, Fair Value, Amount Offset Against Collateral		17,572		155,198
Interest Rate Contract
Derivative [Line Items]
Total derivative liabilities	[2]	141		5,050
Derivative Liability, Fair Value, Gross Liability	[1],[2]	141		5,050
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	[2]			0
Derivative, Collateral, Right to Reclaim Securities	[2]	0		0
Derivative, Collateral, Right to Reclaim Cash	[2]	0		0
Derivative Liability, Fair Value, Amount Offset Against Collateral	[2]	141		5,050
Not Designated as Hedging Instrument
Derivative [Line Items]
Total derivative assets	[3]	63,079		29,643
Total derivative liabilities	[4]	60,571		184,246
Not Designated as Hedging Instrument | Parent Company [Member]
Derivative [Line Items]
Assets, Current	[3]	54,341		24,418
Assets, Long-term	[3]	8,738		5,225
Liabilities, Current	[4]	44,310		136,173
Liabilities, Long-term	[4]	16,261		48,073
Not Designated as Hedging Instrument | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	[5]	450,000		450,000
Total derivative assets	[3],[5]	0		0
Total derivative liabilities	[4],[5]	$ 141		$ 5,050
Not Designated as Hedging Instrument | Electric Generation Fuel
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU		186.8		202.1
Not Designated as Hedging Instrument | Purchased Electricity
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MWh		3.6		0.1
Not Designated as Hedging Instrument | Electric Portfolio
Derivative [Line Items]
Total derivative assets	[3]	$ 36,460		$ 23,443
Total derivative liabilities	[4]	41,329		112,106
Not Designated as Hedging Instrument | Natural Gas Portfolio
Derivative [Line Items]
Total derivative assets	[3],[6]	26,619		6,200
Total derivative liabilities	[4],[6]	$ 19,101		$ 67,090
Not Designated as Hedging Instrument | Gas Derivatives
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	[6]	336.4		369.5
[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.
[3]	Balance sheet location: Current and Long-term Unrealized gain on derivative instruments.
[4]	Balance sheet location: Current and Long-term Unrealized loss on derivative instruments.
[5]	Interest rate swap contracts are only held at Puget Energy.
[6]	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, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		$ (83,795)	$ (13,233)	$ 84,146
PUGET SOUND ENERGY, INC.
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		(83,795)	(12,688)	85,636
Not Designated as Hedging Instrument
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		(21,079)	73,788	85,262
Not Designated as Hedging Instrument | Other Income (Deductions) | Interest Expense
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		1,062	3,796	3,915
Not Designated as Hedging Instrument | Interest Rate Contract | Interest Expense
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		0	(560)	(500)
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		(62,318)	9,315	42,334
Not Designated as Hedging Instrument | Commodity Contract | Electric Generation Fuel
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		39,656	44,648	(6,511)
Not Designated as Hedging Instrument | Commodity Contract | Purchased Electricity
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		21,998	39,137	4,212
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]	(21,477)	(22,548)	41,812
Not Designated as Hedging Instrument | PUGET SOUND ENERGY, INC.
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		(22,141)	71,097	83,337
Not Designated as Hedging Instrument | PUGET SOUND ENERGY, INC. | Energy Related Derivative [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		(62,318)	9,315	42,334
Not Designated as Hedging Instrument | PUGET SOUND ENERGY, INC. | Commodity Contract | Electric Generation Fuel
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		39,656	44,648	(6,511)
Not Designated as Hedging Instrument | PUGET SOUND ENERGY, INC. | Commodity Contract | Purchased Electricity
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		21,998	39,137	4,212
Not Designated as Hedging Instrument | PUGET SOUND ENERGY, INC. | Electric [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	[1]	$ (21,477)	$ (22,003)	$ 43,302
[1]	Differences between Puget Energy and PSE for the twelve months ended December 31, 2015 and 2014 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, 2016	Dec. 31, 2015	Dec. 31, 2014
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	$ (512)	$ (572)

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		$ 83,795	$ 13,233	$ (84,146)
Derivative contracts classified as financing activities due to merger		0	(8,045)	(16,349)
Other Comprehensive Income Reclassification Of Net Unrealized Gain Loss On Interest Rate Swaps During Period Net Of Tax		0	0	(94)
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		21,079	(73,788)	(85,262)
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		62,318	(9,315)	(42,334)
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	560	500
Not Designated as Hedging Instrument | Commodity contracts: | Electric Generation Fuel
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		(39,656)	(44,648)	6,511
Not Designated as Hedging Instrument | Commodity contracts: | Purchased Electricity
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		(21,998)	(39,137)	(4,212)
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]	21,477	22,548	(41,812)
PUGET SOUND ENERGY, INC.
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		83,795	12,688	(85,636)
PUGET SOUND ENERGY, INC. | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		22,141	(71,097)	(83,337)
PUGET SOUND ENERGY, INC. | 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		62,318	(9,315)	(42,334)
PUGET SOUND ENERGY, INC. | Not Designated as Hedging Instrument | Commodity contracts: | Electric Generation Fuel
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		(39,656)	(44,648)	6,511
PUGET SOUND ENERGY, INC. | Not Designated as Hedging Instrument | Commodity contracts: | Purchased Electricity
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives		(21,998)	(39,137)	(4,212)
PUGET SOUND ENERGY, INC. | 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]	$ 21,477	$ 22,003	$ (43,302)
[1]	Differences between Puget Energy and PSE for the twelve months ended December 31, 2015 and 2014 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, 2016	Dec. 31, 2015
Electric Portfolio
Derivative [Line Items]
Fair Value Liability	[1]	$ 12,828	$ 91,190
Collateral Already Posted, Aggregate Fair Value		0	0
Contingent Collateral		4,894	24,187
Credit Rating | Natural Gas Portfolio
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value		1,000
Forward Value of Contract [Member] | Electric Portfolio
Derivative [Line Items]
Fair Value Liability	[1],[2]	507	0
Collateral Already Posted, Aggregate Fair Value	[2]	0	0
Contingent Collateral	[2]	0	0
Requested Credit for Adequate Assurance | Electric Portfolio
Derivative [Line Items]
Fair Value Liability	[1]	7,427	67,003
Collateral Already Posted, Aggregate Fair Value		0	0
Contingent Collateral		0	0
Credit Rating | Electric Portfolio
Derivative [Line Items]
Fair Value Liability	[1],[3]	4,894	24,187
Collateral Already Posted, Aggregate Fair Value	[3]	0	0
Contingent Collateral	[3]	$ 4,894	$ 24,187
[1]	Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable.
[2]	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.

Fair Value Measurements - Asset

Fair Value Measurements - Assets and Liabilities Measured on Recurring Basis (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Interest Rate Contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities	[1]	$ 141	$ 5,050
Fair Value, Measurements, Recurring | Parent Company [Member] | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		141	5,050
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		141	5,050
Fair Value, Measurements, Recurring | Parent Company [Member] | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		0	0
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	[2]	5,794
Derivative Liabilities	[2]	4,822
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	[2]	3,303
Derivative Liabilities	[2]	2,678
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
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		141	5,050
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		141	5,050
Fair Value, Measurements, Recurring | PUGET SOUND ENERGY, INC. | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		53,982	15,247
Derivative Liabilities		52,930	155,072
Fair Value, Measurements, Recurring | PUGET SOUND ENERGY, INC. | Level 2 | Electric Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		30,666	10,709
Derivative Liabilities		36,507	92,027
Fair Value, Measurements, Recurring | PUGET SOUND ENERGY, INC. | Level 2 | Natural Gas Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		23,316	4,538
Derivative Liabilities		16,423	63,045
Fair Value, Measurements, Recurring | PUGET SOUND ENERGY, INC. | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		9,097	14,396
Derivative Liabilities		7,500	24,124
Fair Value, Measurements, Recurring | PUGET SOUND ENERGY, INC. | Level 3 | Electric Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets			12,734
Derivative Liabilities			20,079
Fair Value, Measurements, Recurring | PUGET SOUND ENERGY, INC. | Level 3 | Natural Gas Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets			1,662
Derivative Liabilities			4,045
Fair Value, Measurements, Recurring | PUGET SOUND ENERGY, INC. | Total
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		63,079	29,643
Derivative Liabilities		60,430	179,196
Fair Value, Measurements, Recurring | PUGET SOUND ENERGY, INC. | Total | Electric Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		36,460	23,443
Derivative Liabilities		41,329	112,106
Fair Value, Measurements, Recurring | PUGET SOUND ENERGY, INC. | Total | Natural Gas Portfolio
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		26,619	6,200
Derivative Liabilities		19,101	67,090
Carrying Amount | Parent Company [Member] | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Notes receivable and other		$ 49,100	$ 52,800
[1]	Interest Rate Swap Contracts are only held at Puget Energy.
[2]	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, 2016	Dec. 31, 2015
PUGET SOUND ENERGY, INC. | 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		$ 3,747,298	$ 3,744,362
PUGET SOUND ENERGY, INC. | 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		27,200	30,000
Junior subordinated notes		250,000	250,000
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[1]	3,497,298	3,494,362
PUGET SOUND ENERGY, INC. | 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		4,571,044	4,540,617
PUGET SOUND ENERGY, INC. | Total | Income Approach Valuation Technique | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Junior subordinated notes		210,261	211,173
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[1]	4,360,783	4,329,444
Parent Company [Member] | Carrying Amount | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Notes Receivable, Fair Value Disclosure		49,100	52,800
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		5,354,073	5,327,518
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		33,000	38,400
Junior subordinated notes		250,000	250,000
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[2]	5,091,593	5,077,518
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure		12,480	0
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		6,560,028	6,520,004
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		210,261	211,173
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[2]	6,337,287	6,308,831
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure		$ 12,480	$ 0
[1]	2 The carrying value includes debt issuances costs of $27.2 million and $30.0 million for December 31, 2016 and 2015, respectively, which are not included in fair value.
[2]	1 The carrying value includes debt issuances costs of $33.0 million and $38.4 million for December 31, 2016 and 2015, 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, 2016USD ($)$ / MWh	Sep. 30, 2016USD ($)$ / MWh	Dec. 31, 2016USD ($)$ / MWh	Dec. 31, 2015USD ($)$ / MWh	Dec. 31, 2014USD ($)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		$ (9,728,000)	$ (9,728,000)	$ (9,728,000)	$ (14,102,000)	$ (15,782,000)
Included in earnings	[1]			4,007,000	(6,432,000)	(5,537,000)
Included in regulatory assets / liabilities				4,312,000	3,695,000	1,630,000
Settlements	[2]			(3,808,000)	(2,983,000)	(498,000)
Transferred into Level 3				(3,021,000)	(787,000)	4,570,000
Transferred out of Level 3				9,835,000	10,881,000	1,515,000
Balance at end of period				1,597,000	(9,728,000)	(14,102,000)
Electric Portfolio
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		(7,345,000)	(7,345,000)	(7,345,000)	(12,062,000)	(15,421,000)
Included in earnings	[1]			4,007,000	(6,432,000)	(5,537,000)
Included in regulatory assets / liabilities				0	0	0
Settlements	[2]			(1,129,000)	902,000	1,036,000
Transferred into Level 3				(3,021,000)	(787,000)	5,155,000
Transferred out of Level 3				8,460,000	11,034,000	2,705,000
Balance at end of period				972,000	(7,345,000)	(12,062,000)
Unrealized gain (loss) on derivative instruments, net				2,000,000	(7,400,000)	(9,600,000)
Natural Gas Portfolio
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		$ (2,383,000)	$ (2,383,000)	(2,383,000)	(2,040,000)	(361,000)
Included in earnings	[1]			0	0	0
Included in regulatory assets / liabilities				4,312,000	3,695,000	1,630,000
Settlements	[2]			(2,679,000)	(3,885,000)	(1,534,000)
Transferred into Level 3				0	0	(585,000)
Transferred out of Level 3				1,375,000	(153,000)	(1,190,000)
Balance at end of period				$ 625,000	$ (2,383,000)	$ (2,040,000)
Income Approach Valuation Technique | Minimum
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh		0	0		0
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair Value Inputs, Power Contract Costs		$ 4,100	$ 618		$ 4,100
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				11.86
Income Approach Valuation Technique | Maximum
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh		25.96	58.96		27.25
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair Value Inputs, Power Contract Costs		$ 4,659	$ 4,633		$ 4,659
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				33.52
Income Approach Valuation Technique | Weighted Average
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh		0	0		0
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair Value Inputs, Power Contract Costs		$ 4,452	$ 2,472		$ 4,417
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				27.61
[1]	Income Statement location: 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 $2.0 million, $(7.4) million and $(9.6) million for the years ended December 31, 2016, 2015 and 2014, 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
		Mar. 31, 2016USD ($)$ / MWh	Sep. 30, 2016USD ($)$ / MWh	Dec. 31, 2016USD ($)$ / MMBTU$ / MWh	Dec. 31, 2015USD ($)$ / MWh
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		$ 5,360,000
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				$ 200,000
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		0	0		0
Fair Value Inputs, Power Contract Costs		$ 4,100	$ 618		$ 4,100
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		25.96	58.96		27.25
Fair Value Inputs, Power Contract Costs		$ 4,659	$ 4,633		$ 4,659
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		0	0		0
Fair Value Inputs, Power Contract Costs		$ 4,452	$ 2,472		$ 4,417
Parent Company [Member] | Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities				0	0
Commodity Contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets				63,079,000	29,643,000
Derivative liabilities				$ 60,430,000	179,196,000
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				2
Natural Gas Portfolio | Income Approach Valuation Technique | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU				3.24
Natural Gas Portfolio | Income Approach Valuation Technique | Weighted Average
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Price Per Millions of BTU | $ / MMBTU				2.42
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]
Derivative assets	[1]			$ 3,303,000
Derivative liabilities	[1]			$ 2,678,000
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				11.86
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				33.52
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				27.61
Electric Portfolio | Parent Company [Member] | Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	[1]			$ 5,794,000
Derivative liabilities	[1]			$ 4,822,000
Wells Project
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite-Lived Intangible Assets, Net		25,193,000			32,988,000
Priest Rapids Development
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Finite-Lived Intangible Assets, Net			18,969,000
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		$ 27,628,000
[1]	The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

Employee Investment Plans (Deta

Employee Investment Plans (Details) - PUGET SOUND ENERGY, INC. $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Defined Contribution Plan
Employer matching contribution, percent	1.00%	4.00%
Employer discretionary contribution amount		$ 17.2	$ 16.1	$ 14.9
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Qualified Pension Benefits
Change in benefit obligation:
Benefit obligation at beginning of period	$ 643,088	$ 690,194
Service cost	18,913	21,287	$ 17,437
Interest cost	28,689	28,088	28,039
Actuarial loss (gain)	1,545	(55,665)
Benefits paid	(38,730)	(39,963)
Medicare part D subsidy received	0	0
Defined Benefit Plan, Expected Administration Expenses	(898)	(853)
Benefit obligation at end of period	652,607	643,088	690,194
Change in plan assets:
Fair value of plan assets at beginning of period	598,865	626,173
Actual return on plan assets	37,022	(4,489)
Employer contribution	24,000	18,000
Benefits paid	(38,730)	(39,963)
Defined Benefit Plan, Administration Expenses	(897)	(856)
Fair value of plan assets at end of period	620,260	598,865	626,173
Funded status at end of period	(32,347)	(44,223)
Supplemental Employee Retirement Plan [Member]
Change in benefit obligation:
Benefit obligation at beginning of period	51,279	55,855
Service cost	1,085	1,108	1,042
Interest cost	2,325	2,281	2,310
Actuarial loss (gain)	106	(4,430)
Benefits paid	(3,061)	(3,535)
Medicare part D subsidy received	0	0
Defined Benefit Plan, Expected Administration Expenses	0	0
Benefit obligation at end of period	51,734	51,279	55,855
Change in plan assets:
Fair value of plan assets at beginning of period	0	0
Actual return on plan assets	0	0
Employer contribution	3,061	3,535
Benefits paid	(3,061)	(3,535)
Defined Benefit Plan, Administration Expenses	0	0
Fair value of plan assets at end of period	0	0	0
Funded status at end of period	(51,734)	(51,279)
Other Benefits
Change in benefit obligation:
Benefit obligation at beginning of period	13,946	15,688
Service cost	93	112	112
Interest cost	533	621	684
Actuarial loss (gain)	(2,262)	(1,416)
Benefits paid	(1,264)	(1,354)
Medicare part D subsidy received	148	295
Defined Benefit Plan, Expected Administration Expenses	0	0
Benefit obligation at end of period	11,194	13,946	15,688
Change in plan assets:
Fair value of plan assets at beginning of period	7,203	8,360
Actual return on plan assets	926	(378)
Employer contribution	335	575
Benefits paid	(1,264)	(1,354)
Defined Benefit Plan, Administration Expenses	0	0
Fair value of plan assets at end of period	7,200	7,203	8,360
Funded status at end of period	(3,994)	(6,743)
PUGET SOUND ENERGY, INC. | Qualified Pension Benefits
Change in benefit obligation:
Service cost	18,913	21,287	17,437
Interest cost	28,689	28,088	28,039
PUGET SOUND ENERGY, INC. | Supplemental Employee Retirement Plan [Member]
Change in benefit obligation:
Service cost	1,085	1,108	1,042
Interest cost	2,325	2,281	2,310
PUGET SOUND ENERGY, INC. | Other Benefits
Change in benefit obligation:
Service cost	93	112	112
Interest cost	533	621	$ 684
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	598,865
Fair value of plan assets at end of period	621,886	598,865
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	7,203
Fair value of plan assets at end of period	7,262	7,203
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	(7,544)
Fair value of plan assets at end of period	$ (9,894)	$ (7,544)

Retirement Benefits - Amounts R

Retirement Benefits - Amounts Recognized (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Qualified Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation	$ 652,607	$ 643,088	$ 690,194
Defined Benefit Plan, Accumulated Benefit Obligation	641,855	635,599
Defined Benefit Plan, Fair Value of Plan Assets	620,260	598,865	626,173
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets	0	0
Current liabilities	0	0
Noncurrent liabilities	(32,347)	(44,223)
Net assets (liabilities)	(32,347)	(44,223)
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	11,141	(6,136)
Amortization of net (loss) gain	0	(3,887)
Amortization of prior service cost (credit)	1,980	1,980
Total change in other comprehensive income for year	13,121	(8,043)
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation	51,734	51,279	55,855
Defined Benefit Plan, Accumulated Benefit Obligation	47,639	46,978
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	(1,911)	(2,545)
Noncurrent liabilities	(49,823)	(48,734)
Net assets (liabilities)	(51,734)	(51,279)
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	106	(4,430)
Amortization of net (loss) gain	(910)	(1,641)
Amortization of prior service cost (credit)	(42)	(42)
Total change in other comprehensive income for year	(846)	(6,113)
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation	11,194	13,946	15,688
Defined Benefit Plan, Accumulated Benefit Obligation	11,092	13,828
Defined Benefit Plan, Fair Value of Plan Assets	7,200	7,203	$ 8,360
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets	0	0
Current liabilities	(325)	(353)
Noncurrent liabilities	(3,669)	(6,390)
Net assets (liabilities)	(3,994)	(6,743)
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	(2,742)	(508)
Amortization of net (loss) gain	385	131
Amortization of prior service cost (credit)	0	0
Total change in other comprehensive income for year	(2,357)	(377)
Parent Company [Member] | Qualified Pension Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)	56,588	45,447
Prior service cost (credit)	(9,822)	(11,802)
Total	46,766	33,645
Parent Company [Member] | Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)	9,043	9,848
Prior service cost (credit)	246	288
Total	9,289	10,136
Parent Company [Member] | Other Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)	(4,190)	(1,834)
Prior service cost (credit)	0	0
Total	(4,190)	(1,834)
PUGET SOUND ENERGY, INC. | Qualified Pension Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)	217,143	221,064
Prior service cost (credit)	(7,806)	(9,379)
Total	209,337	211,685
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	11,336	(5,711)
Amortization of net (loss) gain	(15,257)	(20,556)
Amortization of prior service cost (credit)	1,573	1,573
Total change in other comprehensive income for year	(2,348)	(24,694)
PUGET SOUND ENERGY, INC. | Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)	11,978	13,202
Prior service cost (credit)	251	295
Total	12,229	13,497
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	106	(4,430)
Amortization of net (loss) gain	(1,330)	(2,120)
Amortization of prior service cost (credit)	(44)	(44)
Total change in other comprehensive income for year	(1,268)	(6,594)
PUGET SOUND ENERGY, INC. | Other Benefits
Defined Benefit Plan, Amounts Recognized in Accumulated Other Comprehensive Income Consist of: [Abstract]
Net loss (gain)	(5,994)	3,834
Prior service cost (credit)	0	0
Total	(5,994)	3,834
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	(2,742)	(508)
Amortization of net (loss) gain	631	407
Amortization of prior service cost (credit)	0	(3)
Total change in other comprehensive income for year	$ (2,111)	$ (104)

Retirement Benefits - Net Perio

Retirement Benefits - Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Qualified Pension Benefits
Components of net periodic benefit cost:
Service cost	$ 18,913	$ 21,287	$ 17,437
Interest cost	28,689	28,088	28,039
Expected return on plan assets	(46,619)	(45,038)	(42,464)
Amortization of prior service cost (credit)	(1,980)	(1,980)	(1,980)
Amortization of net loss (gain)	0	3,887	0
Net periodic benefit cost	(997)	6,244	1,032
Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	1,085	1,108	1,042
Interest cost	2,325	2,281	2,310
Expected return on plan assets	0	0	0
Amortization of prior service cost (credit)	42	42	42
Amortization of net loss (gain)	911	1,641	913
Net periodic benefit cost	4,363	5,072	4,307
Other Benefits
Components of net periodic benefit cost:
Service cost	93	112	112
Interest cost	533	621	684
Expected return on plan assets	(446)	(531)	(535)
Amortization of prior service cost (credit)	0	0	0
Amortization of net loss (gain)	(386)	(130)	(393)
Net periodic benefit cost	(206)	72	(132)
PUGET SOUND ENERGY, INC. | Qualified Pension Benefits
Components of net periodic benefit cost:
Service cost	18,913	21,287	17,437
Interest cost	28,689	28,088	28,039
Expected return on plan assets	(46,814)	(45,462)	(43,252)
Amortization of prior service cost (credit)	(1,573)	(1,573)	(1,573)
Amortization of net loss (gain)	15,257	20,555	13,195
Net periodic benefit cost	14,472	22,895	13,846
PUGET SOUND ENERGY, INC. | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	1,085	1,108	1,042
Interest cost	2,325	2,281	2,310
Expected return on plan assets	0	0	0
Amortization of prior service cost (credit)	44	44	44
Amortization of net loss (gain)	1,330	2,120	1,461
Net periodic benefit cost	4,784	5,553	4,857
PUGET SOUND ENERGY, INC. | Other Benefits
Components of net periodic benefit cost:
Service cost	93	112	112
Interest cost	533	621	684
Expected return on plan assets	(446)	(531)	(535)
Amortization of prior service cost (credit)	0	3	3
Amortization of net loss (gain)	(632)	(406)	(702)
Net periodic benefit cost	$ (452)	$ (201)	$ (438)

Retirement Benefits - Assumptio

Retirement Benefits - Assumptions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Assumed Health Care Cost Trend Rates
Medical inflation rate assumed for next fiscal year	8.80%
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates
1% Increase, Effect on post-retirement benefit obligation	$ 38	$ 52
1% Decrease, Effect on post-retirement benefit obligation	(35)	(42)
1% Increase, Effect on service and interest cost components	2	2
1% Decrease, Effect on service and interest cost components	$ (2)	$ (2)
defined benefit plan health care cost trend rate assumed for next two years	4.30%
Qualified Pension Benefits
Benefit Obligation Assumptions
Discount rate	4.50%	4.65%	4.25%
Rate of compensation increase	4.50%	4.50%	4.50%
Medical trend rate	0.00%	0.00%	0.00%
Benefit Cost Assumptions
Discount rate	4.65%	4.25%	5.10%
Return on plan assets	7.75%	7.75%	7.75%
Rate of compensation increase	4.50%	4.50%	4.50%
Medical trend rate	0.00%	0.00%	0.00%
Supplemental Employee Retirement Plan [Member]
Benefit Obligation Assumptions
Discount rate	4.50%	4.65%	4.25%
Rate of compensation increase	4.50%	4.50%	4.50%
Medical trend rate	0.00%	0.00%	0.00%
Benefit Cost Assumptions
Discount rate	4.65%	4.25%	5.10%
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%
Other Benefits
Benefit Obligation Assumptions
Discount rate	4.50%	4.65%	4.25%
Rate of compensation increase	4.50%	4.50%	4.50%
Medical trend rate	8.80%	7.20%	5.70%
Benefit Cost Assumptions
Discount rate	4.65%	4.25%	5.10%
Return on plan assets	6.75%	7.00%	7.00%
Rate of compensation increase	4.50%	4.50%	4.50%
Medical trend rate	5.30%	7.20%	6.70%

Retirement Benefits - Future Be

Retirement Benefits - Future Benefit Payments (Details) $ in Thousands	Dec. 31, 2016USD ($)
Qualified Pension Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,016	$ 41,400
2,017	42,500
2,018	43,600
2,019	44,600
2,020	45,200
2021-2025	240,800
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,016	1,911
2,017	5,278
2,018	5,666
2,019	4,454
2,020	1,724
2021-2025	34,043
Other Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,016	928
2,017	893
2,018	863
2,019	829
2,020	787
2021-2025	3,873
2016, without Medicare Part D subsidy	1,256
2017, without Medicare Part D subsidy	1,239
2018, without Medicare Part D subsidy	1,216
2019, without Medicare Part D subsidy	1,191
2020, without Medicare Part D subsidy	1,158
2021-2025, without Medicare Part D subsidy	$ 5,294

Retirement Benefits - Plan Asse

Retirement Benefits - Plan Asset Allocation (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Qualified Pension Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 620,260	$ 598,865	$ 626,173
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		0.00%
Target Allocation		9.00%
Target Allocation, Maximum		15.00%
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		10.00%
Target Allocation		25.00%
Target Allocation, Maximum		30.00%
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		25.00%
Target Allocation		31.00%
Target Allocation, Maximum		40.00%
Fixed income
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum		15.00%
Target Allocation		25.00%
Target Allocation, Maximum		30.00%
Real estate
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum		0.00%
Target Allocation		0.00%
Target Allocation, Maximum		10.00%
Absolute return
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations Range Minimum		5.00%
Target Allocation		10.00%
Target Allocation, Maximum		15.00%
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		0.00%
Target Allocation		0.00%
Target Allocation, Maximum		5.00%
Fair Value, Measurements, Recurring | Qualified Pension Benefits | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 621,886	598,865
Fair Value, Measurements, Recurring | Equities: | Qualified Pension Benefits | Level 1
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		354,221	324,321
Fair Value, Measurements, Recurring | Equities: | Qualified Pension Benefits | Level 2
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		54,740	58,425
Fair Value, Measurements, Recurring | Equities: | Qualified Pension Benefits | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		408,961	382,746
Fair Value, Measurements, Recurring | Fair Value Measurement [Domain] | Qualified Pension Benefits | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		222,819	223,663
Fair Value, Measurements, Recurring | Mutual Funds | Qualified Pension Benefits | Level 1
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[1]	181,212	169,165
Fair Value, Measurements, Recurring | Mutual Funds | Qualified Pension Benefits | 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 | Qualified Pension Benefits | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[1]	181,212	169,165
Fair Value, Measurements, Recurring | Common Stock | Qualified Pension Benefits | Level 1
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		154,255	146,321
Fair Value, Measurements, Recurring | Common Stock | Qualified Pension Benefits | 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 | Qualified Pension Benefits | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		154,255	146,321
Fair Value, Measurements, Recurring | US Treasury and Government [Member] | Qualified Pension Benefits | Level 1
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		18,754	8,835
Fair Value, Measurements, Recurring | US Treasury and Government [Member] | Qualified Pension Benefits | Level 2
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		16,197	14,268
Fair Value, Measurements, Recurring | US Treasury and Government [Member] | Qualified Pension Benefits | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		34,951	23,103
Fair Value, Measurements, Recurring | Corporate Bond Securities [Member] | Qualified Pension Benefits | 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] | Qualified Pension Benefits | Level 2
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		38,543	44,157
Fair Value, Measurements, Recurring | Corporate Bond Securities [Member] | Qualified Pension Benefits | Total
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 38,543	$ 44,157
[1]	December 31, 2016.

Retirement Benefits - Fair Valu

Retirement Benefits - Fair Value Level 3 Rollforward (Details) - Qualified Pension Benefits - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Change in plan assets:
Fair value of plan assets at beginning of period	$ 598,865	$ 626,173
Fair value of plan assets at end of period	$ 620,260	$ 598,865

Retirement Benefits - Textuals

Retirement Benefits - Textuals (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2016
PUGET SOUND ENERGY, INC.
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent	1.00%	4.00%
PUGET SOUND ENERGY, INC. | 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)		$ (13.7)
Pension and Other Postretirement Benefit Plans, Net Prior Service Cost or Credit, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year		(1.6)
PUGET SOUND ENERGY, INC. | Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Net Gain (Loss)		(1.6)
PUGET SOUND ENERGY, INC. | Qualified Pension Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Estimated Future Employer Contributions in Current Fiscal Year		18
PUGET SOUND ENERGY, INC. | Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Estimated Future Employer Contributions in Current Fiscal Year		1.9
PUGET SOUND ENERGY, INC. | Other Benefits
Defined Benefit Plan and Other Postretirement Benefit Plans Table Text Block [Line Items]
Estimated Future Employer Contributions in Current Fiscal Year		$ 0.3

Retirement Benefits Accumulated

Retirement Benefits Accumulated Benefit Obligation (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Qualified Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation		$ 652,607	$ 643,088	$ 690,194
Defined Benefit Plan, Accumulated Benefit Obligation		641,855	635,599
Defined Benefit Plan, Fair Value of Plan Assets		620,260	598,865	626,173
Supplemental Employee Retirement Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation		51,734	51,279	55,855
Defined Benefit Plan, Accumulated Benefit Obligation		47,639	46,978
Defined Benefit Plan, Fair Value of Plan Assets		0	0	0
Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation		11,194	13,946	15,688
Defined Benefit Plan, Accumulated Benefit Obligation		11,092	13,828
Defined Benefit Plan, Fair Value of Plan Assets		7,200	7,203	$ 8,360
Fair Value, Measurements, Recurring | Level 1 | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		7,182	7,135
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]	181,212	169,165
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]	7,182	7,135
Fair Value, Measurements, Recurring | Level 1 | Cash and cash equivalents | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[3]	0	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		621,886	598,865
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		7,262	7,203
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]	181,212	169,165
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]	7,182	7,135
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member] | Cash and cash equivalents | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[3]	80	68
Fair Value, Measurements, Recurring | Level 2 | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		80	68
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 | Other Pension Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[3]	$ 80	$ 68
[1]	December 31, 2016.
[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, 2016.
[3]	The investment consists of a money market fund (at level 1) and a collective trust fund (at level 2). The money market fund is valued at the net asset value per share of $1.00 per unit as of December 31, 2016. The collective trust fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or short-term in nature.

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosures [Line Items]
Current Federal Tax Expense (Benefit)	$ 0	$ 0	$ 0
Current State and Local Tax Expense (Benefit)	20	0	0
Federal	140,315	91,968	57,152
State	(131)	(192)	(167)
Total income tax expense	140,204	91,776	56,985
PUGET SOUND ENERGY, INC.
Income Tax Disclosures [Line Items]
Current Federal Tax Expense (Benefit)	0	0	0
Current State and Local Tax Expense (Benefit)	20	0	0
Federal	175,327	125,900	89,342
State	0	0	0
Total income tax expense	$ 175,347	$ 125,900	$ 89,342

Income Taxes - Income Tax Recon

Income Taxes - Income Tax Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosures [Line Items]
Federal statutory rate	35.00%
Income Tax Reconciliation [Abstract]
Income taxes at the statutory rate	$ 158,586	$ 116,534	$ 80,087
Production tax credit1	(12,925)	(19,470)	(23,073)
Utility plant differences	3,966	5,671	7,090
Income Tax Reconciliation, Treasury Grant	(9,788)	(8,807)	(8,808)
Other - net	365	(2,152)	1,689
Total income tax expense	$ 140,204	$ 91,776	$ 56,985
Effective tax rate	30.90%	27.60%	24.90%
PUGET SOUND ENERGY, INC.
Income Tax Reconciliation [Abstract]
Income taxes at the statutory rate	$ 194,572	$ 150,531	$ 114,084
Production tax credit1	(12,925)	(19,470)	(23,073)
Utility plant differences	3,966	5,671	7,090
Income Tax Reconciliation, Treasury Grant	(9,788)	(8,807)	(8,808)
Other - net	(478)	(2,025)	49
Total income tax expense	$ 175,347	$ 125,900	$ 89,342
Effective tax rate	31.50%	29.30%	27.40%

Income Taxes - Deferred Income

Income Taxes - Deferred Income Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Deferred Tax Liabilities, Gross
Utility plant and equipment	$ 1,880,782	$ 1,788,078
Regulatory asset for income taxes	72,038	73,231
Fair value of debt instruments	67,444	70,260
Deferred Tax Liabilities, Pension and Other Compensation	77,230	77,230
Other, net deferred tax liabilities	119,050	84,397
Subtotal deferred tax liabilities	2,216,544	2,093,196
Deferred Tax Assets, Gross
Net operating loss carryforward	(352,827)	(384,338)
Production tax credit carryforward	(190,999)	(178,075)
Regulatory liability on production tax credit	(101,787)	(94,828)
Subtotal deferred tax assets	(645,613)	(657,241)
Total net deferred tax liabilities	1,570,931	1,435,955
PUGET SOUND ENERGY, INC.
Deferred Tax Liabilities, Gross
Utility plant and equipment	1,880,782	1,788,078
Regulatory asset for income taxes	71,517	72,694
Other, net deferred tax liabilities	113,938	80,351
Subtotal deferred tax liabilities	2,066,237	1,941,123
Deferred Tax Assets, Gross
Net operating loss carryforward	(41,061)	(111,604)
Production tax credit carryforward	(190,999)	(178,075)
Regulatory liability on production tax credit	(101,787)	(94,828)
Subtotal deferred tax assets	(333,847)	(384,507)
Total net deferred tax liabilities	$ 1,732,390	$ 1,556,616

Income Taxes - Balance Sheet Lo

Income Taxes - Balance Sheet Location (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosures [Line Items]
Non-current deferred taxes	$ 1,570,931	$ 1,435,955
Total net deferred tax liabilities	1,570,931	1,435,955
PUGET SOUND ENERGY, INC.
Income Tax Disclosures [Line Items]
Non-current deferred taxes	1,732,390	1,556,616
Total net deferred tax liabilities	$ 1,732,390	$ 1,556,616

Litigation (Details)

Litigation (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Loss Contingencies [Line Items]
Regulatory Assets	$ 176.8
Loss Contingency, Estimate of Possible Loss	3.2
Loss Contingency, Accrual, Current	3.2
Pending Litigation
Loss Contingencies [Line Items]
Litigation claims accrual	$ 0.7	$ 0.3
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%

Commitments and Contingencies81

Commitments and Contingencies (Details) $ in Thousands, MWh in Millions	12 Months Ended
	Dec. 31, 2016USD ($)MWhContracts$ / kWhMW	Dec. 31, 2015USD ($)MWh	Dec. 31, 2014USD ($)MWh
Long-term Purchase Commitment [Line Items]
Long-term Line of Credit, Noncurrent	$ 12,480	$ 0
Percentage of Company's energy output (percent)	13.70%
Average cost of Company's energy output (US$ per kWh) | $ / kWh	0
Number of Public Utility Districts with long term purchase agreements | Contracts	3
Contract expenses	$ 77,667	$ 72,833	$ 69,661
Megawatt Capacity | MW	749
Estimated 2017 Costs	$ 79,427
2017 Debt Service Costs	29,348
Interest included in 2017 Debt Service Costs	13,985
Debt Outstanding	224,828
Payment Obligations for Power Purchases
2,014	282,913
2,015	274,212
2,016	268,137
2,017	271,214
2,018	274,827
Thereafter	1,533,294
Total	$ 2,904,597
Total energy obtained during period under purchased power contracts (MWh) | MWh	13	11.2	12.1
Cost incurred during period to provide energy under purchased power contracts	$ 402,500	$ 373,800	$ 401,400
Daily take obligation under long-term service contract (percent)	100.00%
Daily delivery obligation under long-term service contract (percent)	100.00%
Natural Gas Portfolio [Member]
Payment Obligations for Power Purchases
2,014	$ 320,238
2,015	211,256
2,016	230,109
2,017	177,390
2,018	107,621
Thereafter	0
Total	1,046,614
Columbia River projects
Payment Obligations for Power Purchases
2,014	73,733
2,015	69,527
2,016	58,921
2,017	59,172
2,018	56,396
Thereafter	597,468
Total	915,217
Other utilities
Payment Obligations for Power Purchases
2,014	10,499
2,015	1,257
2,016	888
2,017	0
2,018	0
Thereafter	0
Total	12,644
Non-utility contracts
Payment Obligations for Power Purchases
2,014	198,681
2,015	203,428
2,016	208,328
2,017	212,042
2,018	218,431
Thereafter	935,826
Total	1,976,736
Short-term energy supply contracts
Payment Obligations for Power Purchases
2,014	45,700
2,015	10,500
2,016	3,900
Firm transportation service
Payment Obligations for Power Purchases
2,014	156,290
2,015	154,155
2,016	149,277
2,017	140,672
2,018	128,049
Thereafter	467,266
Total	1,195,709
Firm Storage and Peaking Service [Member]
Payment Obligations for Power Purchases
2,014	6,616
2,015	3,861
2,016	2,943
2,017	1,950
2,018	1,619
Thereafter	2,475
Total	19,464
Long-term Purchase Commitment, Demand Charges	120,200
Firm natural gas supply
Payment Obligations for Power Purchases
2,014	483,144
2,015	369,272
2,016	382,329
2,017	320,012
2,018	237,289
Thereafter	469,741
Total	2,261,787
Combustion turbines
Payment Obligations for Power Purchases
Long-term Purchase Commitment, Demand Charges	43,200
Energy production service contracts
Payment Obligations for Power Purchases
2,014	31,573
2,015	31,970
2,016	31,313
2,017	50,656
2,018	32,934
Thereafter	204,687
Total	383,133
Automated meter reading system
Payment Obligations for Power Purchases
2,014	18,175
2,015	18,693
2,016	18,718
2,017	20,191
2,018	20,939
Thereafter	116,811
Total	213,527
Service contract obligations
Payment Obligations for Power Purchases
2,014	49,748
2,015	50,663
2,016	50,031
2,017	70,847
2,018	53,873
Thereafter	321,498
Total	$ 596,660
Minimum | Combustion turbines
Payment Obligations for Power Purchases
Remaining terms under contract	less than one year
Maximum | Combustion turbines
Payment Obligations for Power Purchases
Remaining terms under contract	28
Rock Island Project
Long-term Purchase Commitment [Line Items]
Percent of Output	25.00%
Megawatt Capacity | MW	156
Estimated 2017 Costs	$ 28,886
2017 Debt Service Costs	10,430
Interest included in 2017 Debt Service Costs	5,638
Debt Outstanding	$ 88,518
Rocky Reach Project
Long-term Purchase Commitment [Line Items]
Percent of Output	25.00%
Megawatt Capacity | MW	325
Estimated 2017 Costs	$ 28,376
2017 Debt Service Costs	7,574
Interest included in 2017 Debt Service Costs	2,854
Debt Outstanding	$ 44,305
Wells Project
Long-term Purchase Commitment [Line Items]
Percent of Output	29.90%
Megawatt Capacity | MW	251
Estimated 2017 Costs	$ 16,547
2017 Debt Service Costs	8,004
Interest included in 2017 Debt Service Costs	2,153
Debt Outstanding	$ 54,847
Priest Rapids Development
Long-term Purchase Commitment [Line Items]
Percent of Output	0.60%
Megawatt Capacity | MW	8
Estimated 2017 Costs	$ 2,809
2017 Debt Service Costs	1,670
Interest included in 2017 Debt Service Costs	1,670
Debt Outstanding	$ 18,579
Wanapum Development
Long-term Purchase Commitment [Line Items]
Percent of Output	0.60%
Megawatt Capacity | MW	9
Estimated 2017 Costs	$ 2,809
2017 Debt Service Costs	1,670
Interest included in 2017 Debt Service Costs	1,670
Debt Outstanding	$ 18,579

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Related Party Transaction, Due from (to) Related Party	$ 300	$ 1,000
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction	1,000	1,810
PUGET SOUND ENERGY, INC.
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction	$ 23,300	$ 20,300

Segment Information (Details)

Segment Information (Details)	12 Months Ended
	Dec. 31, 2016mi²segment
Segment Reporting Information [Line Items]
Number of operating segments | segment	1
PUGET SOUND ENERGY, INC.
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	$ (27,266)
Accumulated other comprehensive income (loss), net of tax	(33,712)	$ (27,266)
PUGET SOUND ENERGY, INC.
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(149,550)
Accumulated other comprehensive income (loss), net of tax	(145,511)	(149,550)
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	(27,266)	(36,710)	$ 48,514
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(5,528)	7,196	(84,301)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(918)	2,248	(923)
Other Comprehensive Income (Loss), Net of Tax	(6,446)	9,444	(85,224)
Accumulated other comprehensive income (loss), net of tax	(33,712)	(27,266)	(36,710)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | PUGET SOUND ENERGY, INC.
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(143,877)	(164,281)	(87,405)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(5,655)	6,922	(84,955)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	9,377	13,482	8,079
Other Comprehensive Income (Loss), Net of Tax	3,722	20,404	(76,876)
Accumulated other comprehensive income (loss), net of tax	(140,155)	(143,877)	(164,281)
Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(27,266)	(37,043)	47,715
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(5,528)	7,196	(84,301)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(918)	2,581	(457)
Other Comprehensive Income (Loss), Net of Tax	(6,446)	9,777	(84,758)
Accumulated other comprehensive income (loss), net of tax	(33,712)	(27,266)	(37,043)
Comprehensive Income [Member] | PUGET SOUND ENERGY, INC.
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(149,550)	(170,957)	(95,739)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(5,655)	6,922	(84,955)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	9,694	14,485	9,737
Other Comprehensive Income (Loss), Net of Tax	4,039	21,407	(75,218)
Accumulated other comprehensive income (loss), net of tax	(145,511)	(149,550)	(170,957)
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	(333)	(705)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0	333	372
Other Comprehensive Income (Loss), Net of Tax	0	333	372
Accumulated other comprehensive income (loss), net of tax	0	0	(333)
Energy Related Derivative [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member] | PUGET SOUND ENERGY, INC.
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	0	(686)	(2,027)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0	686	1,341
Other Comprehensive Income (Loss), Net of Tax	0	686	1,341
Accumulated other comprehensive income (loss), net of tax	0	0	(686)
Interest Rate Swap [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	(94)
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	94
Other Comprehensive Income (Loss), Net of Tax	0	0	94
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] | PUGET SOUND ENERGY, INC.
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss), net of tax	(5,673)	(5,990)	(6,307)
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	$ (5,356)	$ (5,673)	$ (5,990)

Accumulated Other Comprehensi85

Accumulated Other Comprehensive Income (Loss) Reclassifications Out of Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification of net unrealized loss on energy derivative instruments during the period, tax		$ 0	$ (179)	$ (200)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0	(333)	(372)
PUGET SOUND ENERGY, INC.
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification of net unrealized loss on energy derivative instruments during the period, tax		0	(369)	(722)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0	(686)	(1,341)
Reclassification out of Accumulated Other Comprehensive Income | Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Comprehensive income (loss)		918	(2,581)	457
Reclassification out of Accumulated Other Comprehensive Income | PUGET SOUND ENERGY, INC.
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Comprehensive income (loss)		(9,694)	(14,485)	(9,737)
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]	(525)	(5,397)	(519)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax		1,413	(3,459)	1,419
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Tax		(495)	1,211	(496)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax		918	(2,248)	923
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Noncontrolling Interest [Member] | Energy Related Derivative [Member] | PUGET SOUND ENERGY, INC.
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax		0	(1,055)	(2,063)
Reclassification of net unrealized loss on energy derivative instruments during the period, tax		0	369	722
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0	(686)	(1,341)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Noncontrolling Interest [Member] | Interest Rate Swap [Member] | PUGET SOUND ENERGY, INC.
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] | PUGET SOUND ENERGY, INC.
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Amortization of prior service cost	[2]	1,529	1,526	1,526
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax	[2]	(15,955)	(22,268)	(13,954)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax		(14,426)	(20,742)	(12,428)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Tax		5,049	7,260	4,349
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax		(9,377)	(13,482)	(8,079)
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	(512)	(572)
Reclassification of net unrealized loss on energy derivative instruments during the period, tax		0	179	200
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0	(333)	(372)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Interest Rate Swap [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	(144)
Reclassification of net unrealized loss on energy derivative instruments during the period, tax		0	0	50
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		$ 0	$ 0	$ (94)
[1]	These AOCI components are included in the computation of net periodic pension cost (see Note 12, "Retirement Benefits" for additional details).
[2]	These AOCI components are included in the computation of net periodic pension cost (see Note 12, "Retirement Benefits" for additional details).

SUPPLEMENTAL QUARTERLY FINANCIA

SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information [Line Items]
Operating revenues									$ 3,164,301	$ 3,092,700	$ 3,113,171
Operating income									785,384	671,925	577,851
Net income (loss)									312,899	241,179	171,835
Parent Company [Member]
Quarterly Financial Information [Line Items]
Operating revenues	$ 915,157	$ 618,278	$ 668,169	$ 962,697	$ 901,791	$ 605,733	$ 658,341	$ 926,835
Operating income	236,854	88,072	175,634	284,824	230,030	69,888	126,772	245,235
Net income (loss)	104,825	2,335	64,553	141,186	107,815	(7,928)	25,616	115,676	312,899	241,179	171,835
PUGET SOUND ENERGY, INC.
Quarterly Financial Information [Line Items]
Operating revenues	915,158	618,594	668,169	962,697	902,161	605,913	658,341	926,843	3,164,618	3,093,258	3,116,123
Operating income	237,101	84,476	171,991	281,425	226,446	66,036	122,753	240,903	774,993	656,138	568,693
Net income (loss)	$ 124,199	$ 18,977	$ 80,900	$ 156,505	$ 122,514	$ 9,876	$ 42,699	$ 129,100	$ 380,581	$ 304,189	$ 236,614

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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Condensed Financial Statements, Captions [Line Items]
Non-utility expense and other									$ (27,151)	$ (10,818)	$ (13,109)
Non-hedged interest rate swap expense									(1,062)	(3,796)	(3,915)
Interest expense									(355,139)	(356,696)	(367,308)
Income taxes									(140,204)	(91,776)	(56,985)
Net income (loss)									312,899	241,179	171,835
Comprehensive income (loss)									306,453	250,956	87,077
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Non-utility expense and other									(5,252)	(1,617)	(5,390)
Equity In Net Income (Loss) Of Subsidiaries									385,838	309,603	240,102
Non-hedged interest rate swap expense									(1,062)	(3,796)	(3,915)
Interest income									2	63	185
Interest expense									(104,600)	(100,114)	(93,382)
Income taxes									37,973	37,040	34,235
Net income (loss)	$ 104,825	$ 2,335	$ 64,553	$ 141,186	$ 107,815	$ (7,928)	$ 25,616	$ 115,676	312,899	241,179	171,835
Comprehensive income (loss)									$ 306,453	$ 250,956	$ 87,077

SCHEDULE I CONDENSED FINANCIA88

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PUGET ENERGY - Condensed Balance Sheets (Details) - USD ($) $ in Thousands		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		28,878	42,494	$ 37,527	$ 44,302
Total current assets		902,868	807,579
Long-term assets:
Other		58,109	58,513
Total assets		13,266,380	12,814,254
Capitalization and liabilities:
Common equity		3,688,713	3,531,225	3,543,328	3,679,679
Long-term debt		1,812,480	1,800,000
Total capitalization		9,040,374	8,858,743
Current liabilities:
Accounts payable		317,043	259,353
Interest		73,610	73,378
Deferred income taxes		1,570,931	1,435,955
Unrealized loss on derivative instruments		44,310	136,173
Total current liabilities		919,470	851,286
Long-term liabilities:
Unrealized loss on derivative instruments		16,261	48,073
Total capitalization and liabilities		13,266,380	12,814,254
Parent Company [Member]
Assets:
Investments in subsidiaries		3,571,550	3,415,571
Other property and investments:
Goodwill		1,656,513	1,656,513
Current assets:
Cash and Cash Equivalents, at Carrying Value		397	639	$ 62	$ 191
Receivables from affiliates	[1]	213	203
Total current assets		610	842
Long-term assets:
Deferred income taxes		309,812	272,487
Other		521	537
Total long-term assets		310,333	273,024
Total assets		5,539,006	5,345,950
Capitalization and liabilities:
Common equity		3,688,713	3,531,225
Long-term debt		1,808,828	1,783,898
Total capitalization		5,497,541	5,315,123
Current liabilities:
Accounts payable		15,801	171
Interest		25,523	25,606
Unrealized loss on derivative instruments		141	4,753
Total current liabilities		41,465	30,530
Long-term liabilities:
Unrealized loss on derivative instruments		0	297
Total long-term liabilities		0	297
Total capitalization and liabilities		$ 5,539,006	$ 5,345,950
[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, 2016	Dec. 31, 2015	Dec. 31, 2014
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Net cash provided by (used in) operating activities	$ 729,290	$ 648,722	$ 701,782
Investing activities:
Other	(1,921)	754	(4,512)
Net cash provided by (used in) investing activities	(712,834)	(561,557)	(395,162)
Financing activities:
Dividends paid	(148,965)	(263,059)	(223,428)
Proceeds from long-term debt and bonds issued	12,481	825,000	299,000
Issuance/redemption of term-loan and other long-term debt	0	(711,000)	(299,000)
Net cash provided by (used in) financing activities	(30,072)	(82,198)	(313,395)
Net increase (decrease) in cash and cash equivalents	(13,616)	4,967	(6,775)
Cash and cash equivalents at beginning of period	42,494	37,527	44,302
Cash and cash equivalents at end of period	28,878	42,494	37,527
Parent Company [Member]
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Net cash provided by (used in) operating activities	145,719	171,576	225,459
Investing activities:
Adjustments to Additional Paid in Capital, Other	0	(28,900)	0
(Increase) decrease in loan to subsidiary	0	28,933	665
Other	(6,078)	(5,632)	(2,829)
Net cash provided by (used in) investing activities	(6,078)	(5,599)	(2,164)
Financing activities:
Dividends paid	(148,965)	(263,059)	(223,428)
Proceeds from long-term debt and bonds issued	0	400,000	0
Issuance/redemption of term-loan and other long-term debt	12,480	(299,000)	0
Issue costs and others	(3,398)	(3,341)	4
Net cash provided by (used in) financing activities	(139,883)	(165,400)	(223,424)
Net increase (decrease) in cash and cash equivalents	(242)	577	(129)
Cash and cash equivalents at beginning of period	639	62	191
Cash and cash equivalents at end of period	$ 397	$ 639	$ 62

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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net income									$ 312,899	$ 241,179	$ 171,835
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									306,453	250,956	87,077
Net Cash Provided by (Used in) Operating Activities									729,290	648,722	701,782
Net Cash Provided by (Used in) Investing Activities									(712,834)	(561,557)	(395,162)
Parent Company [Member]
Net income	$ 104,825	$ 2,335	$ 64,553	$ 141,186	$ 107,815	$ (7,928)	$ 25,616	$ 115,676	312,899	241,179	171,835
Goodwill, Purchase Accounting Adjustments									5,200	5,400	3,500
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									306,453	250,956	87,077
Net Cash Provided by (Used in) Operating Activities									145,719	171,576	225,459
Net Cash Provided by (Used in) Investing Activities									(6,078)	(5,599)	(2,164)
PUGET SOUND ENERGY, INC.
Net income	$ 124,199	$ 18,977	$ 80,900	$ 156,505	$ 122,514	$ 9,876	$ 42,699	$ 129,100	380,581	304,189	236,614
Comprehensive Income (Loss), Net of Tax, Attributable to Parent									384,620	325,596	161,396
Net Cash Provided by (Used in) Operating Activities									818,916	738,781	782,727
Net Cash Provided by (Used in) Investing Activities									$ (681,425)	$ (555,925)	$ (392,333)

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance At Beginning of Period	$ 9,756	$ 7,472	$ 7,385
Additions Charged to Costs and Expenses	24,389	20,732	27,228
Deductions	24,347	18,448	27,141
Balance At End Of Period	$ 9,798	$ 9,756	$ 7,472