Puget Energy (PSD) 10-Q 3 Nov 17 2017 Q3 Quarterly report Financial data

Document And Entity Information

Document And Entity Information	9 Months Ended
	Sep. 30, 2017shares
Entity Information [Line Items]
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 Common Stock, Shares Outstanding	200
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Subsidiaries [Member]
Entity Information [Line Items]
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 Common Stock, Shares Outstanding	85,903,791
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Operating revenue:
Electric	$ 537,543	$ 495,321	$ 1,736,335	$ 1,622,664
Natural gas	111,516	114,458	691,685	601,309
Other	11,318	8,499	29,356	25,170
Total operating revenue	660,377	618,278	2,457,376	2,249,143
Energy costs:
Purchased electricity	115,881	94,849	425,263	356,296
Electric generation fuel	66,584	70,503	152,057	165,627
Residential exchange	(14,246)	(15,577)	(52,814)	(49,093)
Purchased natural gas	32,224	34,041	248,208	205,418
Unrealized (gain) loss on derivative instruments, net	(23)	6,327	23,098	(57,218)
Utility operations and maintenance	141,003	138,265	438,622	422,273
Non-utility expense and other	7,319	4,708	18,658	15,520
Depreciation and amortization	120,829	110,022	355,538	328,809
Conservation amortization	25,395	21,800	85,847	77,551
Taxes other than income taxes	66,367	65,268	262,099	235,431
Total operating expenses	561,333	530,206	1,956,576	1,700,614
Operating income (loss)	99,044	88,072	500,800	548,529
Other income (deductions):
Other income	7,151	6,130	19,375	19,187
Other expense	(2,878)	(5,025)	(6,134)	(8,488)
Non-hedged interest rate swap (expense) income	0	563	28	(651)
Interest charges:
AFUDC	3,123	2,702	7,853	7,663
Interest expense	(88,780)	(89,297)	(265,771)	(266,786)
Income (loss) before income taxes	17,660	3,145	256,151	299,454
Income tax (benefit) expense	4,824	810	80,489	91,380
Net income (loss)	12,836	2,335	175,662	208,074
Subsidiaries [Member]
Operating revenue:
Electric	537,543	495,321	1,736,335	1,622,664
Natural gas	111,516	114,458	691,685	601,309
Other	11,318	8,815	29,356	25,487
Total operating revenue	660,377	618,594	2,457,376	2,249,460
Energy costs:
Purchased electricity	115,881	94,849	425,263	356,296
Electric generation fuel	66,584	70,503	152,057	165,627
Residential exchange	(14,246)	(15,577)	(52,814)	(49,093)
Purchased natural gas	32,224	34,041	248,208	205,418
Unrealized (gain) loss on derivative instruments, net	(23)	6,327	23,098	(57,218)
Utility operations and maintenance	141,003	138,265	438,622	422,273
Non-utility expense and other	9,994	8,620	27,857	26,474
Depreciation and amortization	120,829	110,022	355,538	328,809
Conservation amortization	25,395	21,800	85,847	77,551
Taxes other than income taxes	66,367	65,268	262,099	235,431
Total operating expenses	564,008	534,118	1,965,775	1,711,568
Operating income (loss)	96,369	84,476	491,601	537,892
Other income (deductions):
Other income	6,778	6,131	18,861	19,184
Other expense	(2,878)	(5,025)	(6,134)	(8,488)
Interest charges:
AFUDC	3,123	2,702	7,853	7,663
Interest expense	(59,868)	(60,914)	(180,320)	(182,336)
Income (loss) before income taxes	43,524	27,370	331,861	373,915
Income tax (benefit) expense	14,424	8,393	109,015	117,533
Net income (loss)	$ 29,100	$ 18,977	$ 222,846	$ 256,382

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Parent [Line Items]
Net income (loss)	$ 12,836	$ 2,335	$ 175,662	$ 208,074
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	(266)	(29)	400	(400)
Other comprehensive income (loss)	(266)	(29)	400	(400)
Comprehensive income (loss)	12,570	2,306	176,062	207,674
Subsidiaries [Member]
Parent [Line Items]
Net income (loss)	29,100	18,977	222,846	256,382
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	1,744	2,642	7,083	7,322
Amortization of treasury interest rate swaps to earnings, net of tax	79	79	237	237
Other comprehensive income (loss)	1,823	2,721	7,320	7,559
Comprehensive income (loss)	$ 30,923	$ 21,698	$ 230,166	$ 263,941

CONSOLIDATED STATEMENTS OF COM4

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Net unrealized gain (loss) from pension and postretirement plans, net of tax	$ (143)	$ (16)	$ 216	$ (216)
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax	0	0	0	0
Subsidiaries [Member]
Net unrealized gain (loss) from pension and postretirement plans, net of tax	939	1,422	3,813	3,942
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax	0	0	0	0
Amortization of treasury interest rate swaps to earnings, net of tax	$ 43	$ 43	$ 128	$ 128

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Utility plant (at original cost, including construction work in progress):
Electric plant	$ 7,918,877	$ 7,673,772
Natural gas plant	3,253,977	3,051,586
Common plant	738,409	594,994
Less: Accumulated depreciation and amortization	(2,409,508)	(2,161,796)
Net utility plant	9,501,755	9,158,556
Other property and investments:
Goodwill	1,656,513	1,656,513
Other property and investments	166,996	106,418
Total other property and investments	1,823,509	1,762,931
Current assets:
Cash and cash equivalents	6,768	28,878
Restricted cash	9,302	12,418
Accounts receivable, net of allowance for doubtful accounts	232,699	329,375
Unbilled revenue	126,252	234,053
Purchased gas adjustment receivable	0	2,785
Materials and supplies, at average cost	108,814	106,378
Fuel and gas inventory, at average cost	60,645	58,181
Unrealized gain on derivative instruments	16,605	54,341
Prepaid expense and other	35,655	43,046
Power contract acquisition adjustment gain	15,932	33,413
Total current assets	612,672	902,868
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	71,566	72,038
Power cost adjustment mechanism	4,540	4,531
Regulatory assets related to power contracts	19,998	22,613
Other regulatory assets	1,014,796	1,034,348
Derivative Asset, Noncurrent	2,877	8,738
Power contract acquisition adjustment gain	163,588	241,648
Other	65,138	58,109
Total other long-term and regulatory assets	1,342,503	1,442,025
Total assets	13,280,439	13,266,380
Capitalization:
Common stock	0	0
Additional paid-in capital	3,308,957	3,308,957
Earnings reinvested in the business	571,588	413,468
Accumulated other comprehensive income (loss), net of tax	(33,312)	(33,712)
Total common shareholder's equity	3,847,233	3,688,713
Long-term debt:
First mortgage bonds and senior notes	3,164,412	3,362,000
Pollution control bonds	161,860	161,860
Junior subordinated notes	250,000	250,000
Long-term debt	1,883,064	1,812,480
Debt discount, issuance costs and other	(224,336)	(234,679)
Total long-term debt	5,235,000	5,351,661
Total capitalization	9,082,233	9,040,374
Current liabilities:
Accounts payable	296,659	317,043
Short-term debt	139,000	245,763
Current maturities of long-term debt	200,000	2,412
Purchased gas adjustment liability	5,784	0
Accrued expenses:
Taxes	81,354	111,428
Salaries and wages	41,121	49,749
Interest	79,213	73,610
Unrealized loss on derivative instruments	49,820	44,310
Power contract acquisition adjustment loss	2,850	3,159
Other	81,486	71,996
Total current liabilities	977,287	919,470
Long-term and regulatory liabilities:
Deferred income taxes	1,652,573	1,570,931
Unrealized loss on derivative instruments	15,578	16,261
Regulatory liabilities	611,899	654,622
Regulatory liabilities related to power contracts	179,519	275,061
Power contract acquisition adjustment loss	17,148	19,454
Other deferred credits	744,202	770,207
Total long-term and regulatory liabilities	3,220,919	3,306,536
Commitments and contingencies (Note 8)
Total capitalization and liabilities	13,280,439	13,266,380
Subsidiaries [Member]
Utility plant (at original cost, including construction work in progress):
Electric plant	10,036,204	9,813,169
Natural gas plant	3,838,533	3,640,271
Common plant	776,116	632,718
Less: Accumulated depreciation and amortization	(5,149,098)	(4,927,602)
Net utility plant	9,501,755	9,158,556
Other property and investments:
Other property and investments	78,332	77,960
Total other property and investments	78,332	77,960
Current assets:
Cash and cash equivalents	5,939	28,481
Restricted cash	9,302	12,418
Accounts receivable, net of allowance for doubtful accounts	237,091	344,964
Unbilled revenue	126,252	234,053
Purchased gas adjustment receivable	0	2,785
Materials and supplies, at average cost	108,814	106,378
Fuel and gas inventory, at average cost	59,640	56,851
Unrealized gain on derivative instruments	16,605	54,341
Prepaid expense and other	35,655	43,046
Total current assets	599,298	883,317
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	71,057	71,517
Power cost adjustment mechanism	4,540	4,531
Other regulatory assets	1,014,804	1,034,352
Derivative Asset, Noncurrent	2,877	8,738
Other	65,138	58,109
Total other long-term and regulatory assets	1,158,416	1,177,247
Total assets	11,337,801	11,297,080
Capitalization:
Common stock	859	859
Additional paid-in capital	3,275,105	3,275,105
Earnings reinvested in the business	486,095	359,795
Accumulated other comprehensive income (loss), net of tax	(138,191)	(145,511)
Total common shareholder's equity	3,623,868	3,490,248
Long-term debt:
First mortgage bonds and senior notes	3,164,412	3,362,000
Pollution control bonds	161,860	161,860
Junior subordinated notes	250,000	250,000
Debt discount, issuance costs and other	(27,043)	(28,974)
Total long-term debt	3,549,229	3,744,886
Total capitalization	7,173,097	7,235,134
Current liabilities:
Accounts payable	296,659	317,043
Short-term debt	139,000	245,763
Current maturities of long-term debt	200,000	2,412
Purchased gas adjustment liability	5,784	0
Accrued expenses:
Taxes	81,354	111,428
Salaries and wages	41,121	49,749
Interest	56,254	48,087
Unrealized loss on derivative instruments	49,820	44,170
Other	81,486	71,996
Total current liabilities	951,478	890,648
Long-term and regulatory liabilities:
Deferred income taxes	1,844,886	1,732,390
Unrealized loss on derivative instruments	15,578	16,261
Regulatory liabilities	610,902	653,296
Other deferred credits	741,860	769,351
Total long-term and regulatory liabilities	3,213,226	3,171,298
Commitments and contingencies (Note 8)
Total capitalization and liabilities	$ 11,337,801	$ 11,297,080

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
ASSETS
Construction work in progress	$ 598,790	$ 420,278
Current assets:
Allowance for doubtful accounts	$ 6,088	$ 9,798
Common shareholder’s equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,000	1,000
Common stock, shares outstanding (in shares)	200	200
Subsidiaries [Member]
ASSETS
Construction work in progress	$ 598,790	$ 420,278
Current assets:
Allowance for doubtful accounts	$ 6,088	$ 9,798
Common shareholder’s equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	150,000,000	150,000,000
Common stock, shares outstanding (in shares)	85,903,791	85,903,791

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Operating activities:
Net income (loss)	$ 175,662	$ 208,074
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	355,538	328,809
Conservation amortization	85,847	77,551
Deferred income taxes and tax credits, net	81,899	90,828
Net unrealized (gain) loss on derivative instruments	22,957	(60,785)
AFUDC – equity	(11,266)	(10,769)
Funding of pension liability	(18,000)	(24,000)
Regulatory Assets	(83,370)	(138,096)
Other long-term assets and liabilities	8,275	30,766
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	204,477	175,627
Materials and supplies	(2,436)	(28,448)
Fuel and gas inventory	(2,789)	(3,222)
Prepayments and other	7,391	(29,352)
Purchased gas adjustment	8,569	(10,743)
Accounts payable	(31,027)	(22,874)
Taxes payable	(30,074)	(36,411)
Other	(2,983)	23,391
Net cash provided by (used in) operating activities	768,670	570,346
Investing activities:
Construction expenditures - excluding equity AFUDC	(761,968)	(507,703)
Restricted cash	3,116	(1,391)
Other	5,796	(1,781)
Net cash provided by (used in) investing activities	(753,056)	(510,875)
Financing activities:
Change in short-term debt, net	(106,763)	12,996
Dividends paid	(17,543)	(111,592)
Proceeds from long-term debt and bonds issued	70,583	0
Other	15,999	13,479
Net cash provided by (used in) financing activities	(37,724)	(85,117)
Net increase (decrease) in cash and cash equivalents	(22,110)	(25,646)
Cash and cash equivalents at beginning of period	28,878	42,494
Cash and cash equivalents at end of period	6,768	16,848
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	239,566	241,351
Cash payments (refunds) for income taxes	1,649	0
Accounts payable for capital expenditures eliminated from cash flows	87,456	58,278
Subsidiaries [Member]
Operating activities:
Net income (loss)	222,846	256,382
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	355,538	328,809
Conservation amortization	85,847	77,551
Deferred income taxes and tax credits, net	109,015	116,982
Net unrealized (gain) loss on derivative instruments	23,098	(57,218)
AFUDC – equity	(11,266)	(10,769)
Funding of pension liability	(18,000)	(24,000)
Regulatory Assets	(83,370)	(138,096)
Other long-term assets and liabilities	(15,734)	34,128
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	215,674	175,733
Materials and supplies	(2,436)	(28,448)
Fuel and gas inventory	(2,789)	(3,222)
Prepayments and other	7,391	(29,352)
Purchased gas adjustment	8,569	(10,743)
Accounts payable	(31,027)	(22,874)
Taxes payable	(30,074)	(36,411)
Other	(857)	22,035
Net cash provided by (used in) operating activities	832,425	650,487
Investing activities:
Construction expenditures - excluding equity AFUDC	(677,004)	(507,703)
Restricted cash	3,116	(1,391)
Other	6,233	2,519
Net cash provided by (used in) investing activities	(667,655)	(506,575)
Financing activities:
Change in short-term debt, net	(106,763)	12,996
Dividends paid	(96,546)	(195,865)
Other	15,997	13,510
Net cash provided by (used in) financing activities	(187,312)	(169,359)
Net increase (decrease) in cash and cash equivalents	(22,542)	(25,447)
Cash and cash equivalents at beginning of period	28,481	41,856
Cash and cash equivalents at end of period	5,939	16,409
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	160,426	162,091
Cash payments (refunds) for income taxes	3,058	0
Accounts payable for capital expenditures eliminated from cash flows	$ 87,456	$ 58,278

Summary of Consolidation Policy

Summary of Consolidation Policy	9 Months Ended
	Sep. 30, 2017
Accounting Policies [Abstract]
Summary of Consolidation Policy	Basis of Presentation Puget Energy is an energy services holding company that owns Puget Sound Energy (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, 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 the Tacoma LNG facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur under PSE and are allocated to Puget LNG are related party transactions by nature. As of September 30, 2017 , Puget LNG has incurred $86.5 million in construction work in progress and operating costs related to Puget LNG’s portion of the Tacoma LNG facility. In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company.” The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any 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. Tacoma LNG Facility The Tacoma LNG facility will provide peak-shaving services to PSE’s natural gas customers, and will provide LNG as fuel to transportation customers, particularly in the marine market. The Tacoma LNG facility is expected to be operational in 2019. Pursuant to the Washington Commission’s order, Puget LNG will be allocated approximately 57.0% of the capital and operating costs of the Tacoma LNG facility and PSE will be allocated the remaining 43.0% of the capital and operating costs. For Puget Energy, $86.4 million in construction work in progress related to Puget LNG’s portion of the Tacoma LNG facility is reported in the “Other property and investments” financial statement line item. For PSE, construction work in progress of $76.3 million related to PSE’s portion of the Tacoma LNG facility is reported in the “Utility plant - Natural gas plant” line item, as PSE is a regulated entity.

New Accounting Pronouncements

New Accounting Pronouncements	9 Months Ended
	Sep. 30, 2017
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements	New Accounting Pronouncements Revenue Recognition In May 2014, the FASB issued ASU No. 2014-09, " Revenue from Contracts with Customers (Topic 606) ". 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 Accounting Standards Update (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 early adopt ASU 2014-09 using the original effective date. The Company will adopt ASU 2014-09 during the first quarter of fiscal year 2018 by recognizing the cumulative effect of initially applying the new standard as an adjustment to the opening balance of retained earnings, effective January 1, 2018. In preparation for adoption of the standard, the Company has evaluated key accounting assessments related to the standard. As of the date of this report, the Company has not identified material differences in revenue recognition between current GAAP and ASU 2014-09 and as a result, the Company has not identified material cumulative adjustments necessary. The Company's primary revenue sources are from rate-regulated sales of electricity and natural gas to retail customers where revenue is recognized over time as delivered. The Company will include a change in the presentation of alternative revenue program revenue of the Company's consolidated statement of income as well as expanded disclosure around the disaggregation of revenue. Lease Accounting In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" . The FASB issued this ASU to increase transparency and comparability among organizations by recognizing right-of-use (ROU) lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. To meet that objective, the FASB is amending the FASB Accounting Standards Codification and creating Topic 842, Leases. ASU 2016-02 requires lessees to recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The income statement recognition is similar to existing lease accounting and is based on lease classification. Under the new guidance, lessor accounting is largely unchanged. This amendment is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Earlier adoption is permitted for all entities upon issuance. Reporting entities must apply a modified retrospective approach for the adoption of the new standard. The Company will adopt ASU 2016-02 during the first quarter of fiscal year 2019 and expects the adoption of the standard will result in recognition of right-of-use assets and liabilities that have not previously been recorded, which will have a material impact on the consolidated balance sheets. The Company is considering whether the new guidance will affect the accounting for purchase power agreements, easements and rights–of–way, utility pole attachments, and other utility industry–related arrangements. Statement of Cash Flows In August 2016, the FASB issued ASU 2016-15, " Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments ". The amendments in ASU 2016-15 provide guidance for eight specific cash flow issues that include (i) debt prepayment or debt extinguishment costs, (ii) settlement of zero-coupon debt instruments, (iii) contingent consideration payments made after a business combination, (iv) proceeds from the settlement of insurance claims, (v) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, (vi) distribution received from equity method investees, (vii) beneficial interest in securitization transactions, and (viii) separately identifiable cash flows and application of the predominance principle. This update is effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted for all entities upon issuance. The amendments in this update should be applied using a retrospective transition method to each period presented. The Company will adopt ASU 2016-15 during the first quarter of fiscal year 2018 and is in the process of evaluating the impact this standard will have on its consolidated statement of cash flows. In November 2016, the FASB issued ASU 2016-18, " Statement of Cash Flows (Topic 230): Restricted Cash ". The amendments in this update require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The new standard is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company will adopt ASU 2016-18 during the first quarter of fiscal year 2018 retrospectively to all periods presented and does not anticipate the new guidance will have a material impact on the consolidated statement of cash flows. Definition of a Business In January 2017, the FASB issued ASU 2017-01, " Business Combinations (Topic 805): Clarifying the Definition of a Business ". This ASU clarifies the definition of a business by providing a screen test to determine when a set of acquired assets is not a business. The test requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set of acquired assets is not a business. This test reduces the number of transactions that need to be further evaluated. This ASU affects all companies and other reporting organizations that must determine whether they have acquired or sold a business. The amendments are intended to help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This amendment is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company will adopt ASU 2017-01 during the first quarter of fiscal year 2018 and do not expect any impacts on the consolidated financial statements. Retirement Benefits In March 2017, the FASB issued ASU 2017-07, " Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost ". The amendments require that an employer report the service cost component in the same line items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost (which include interest costs, expected return on plan assets, amortization of prior service cost or credits and actuarial gains and losses) are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The line item used in the income statement to present the other components of net benefit cost must be disclosed. Additionally, the service cost component of net benefit cost is the only eligible cost for capitalization. This amendment is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. Early adoption is permitted as of the beginning of an annual period for which financial statements (interim or annual) have not been issued or made available for issuance. The Company will adopt ASU 2017-07 during the first quarter of fiscal year 2018. For the periods presented in the income statement, the Company’s non-service components for the nine months ended September 30, 2017, was a credit of $13.8 million for Puget Energy and $3.5 million for PSE. The non-service cost components are in an income position and will be presented in the other income section, upon adoption.

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	9 Months Ended
	Sep. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Accounting for Derivative Instruments and Hedging Activities	Accounting for Derivative Instruments and Hedging Activities PSE employs various energy portfolio optimization strategies but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the power cost adjustment (PCA). Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility of costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. PSE's 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 September 30, 2017 , the Company 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 September 30, 2017 At December 31, 2016 (Dollars in Thousands) Volumes Assets 1 Liabilities 2 Volumes Assets 1 Liabilities 2 Interest rate swap derivatives 3 $ — $ — $ — $450 million $ — $ 141 Electric portfolio derivatives * 11,656 39,622 * 36,460 41,329 Natural gas derivatives (MMBtus) 4 305.3 million 7,826 25,776 336.4 million 26,619 19,101 Total derivative contracts ** $ 19,482 $ 65,398 ** $ 63,079 $ 60,571 Current ** $ 16,605 $ 49,820 ** $ 54,341 $ 44,310 Long-term ** 2,877 15,578 ** 8,738 16,261 Total derivative contracts ** $ 19,482 $ 65,398 ** $ 63,079 $ 60,571 _______________ 1 Balance sheet locations: Current and Long-term Unrealized gain on derivative instruments. 2 Balance sheet locations: Current and Long-term Unrealized loss on derivative instruments. 3 Interest rate swap contracts are only held at Puget Energy, and matured January 2017. 4 All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the purchased gas adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 165.0 million One Million British Thermal Units (MMBtu) and purchased electricity of 2.6 million Megawatt Hours (MWhs) at September 30, 2017 , and 186.8 million MMBtus and 3.6 million MWhs at December 31, 2016 . ** 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 natural gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical natural gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as the right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount. For further details regarding the fair value of derivative instruments, see Note 4, "Fair Value Measurements" to the consolidated financial statements. 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 September 30, 2017 Gross Amount Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position (Dollars in Thousands) Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 19,482 $ — $ 19,482 $ (12,961 ) $ — $ 6,521 Liabilities: Energy derivative contracts 65,398 — 65,398 (12,961 ) (739 ) 51,698 Puget Energy and Puget Sound Energy At December 31, 2016 Gross Amount Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position (Dollars in Thousands) Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 63,079 $ — $ 63,079 $ (42,858 ) $ — $ 20,221 Liabilities: Energy derivative contracts 60,430 — 60,430 (42,858 ) — 17,572 Interest rate swaps 2 141 — 141 — — 141 _______________ 1 All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off. 2 Interest rate swap contracts are only held at Puget Energy, and matured January 2017. The following table presents the effect and locations of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income: Puget Energy and Three Months Ended September 30, Nine Months Ended (Dollars in Thousands) Location 2017 2016 2017 2016 Interest rate contracts 1 : Non-hedged interest rate swap (expense) income $ — $ 563 $ 28 $ (651 ) Interest expense — (349 ) — (349 ) Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 903 (8,873 ) (20,979 ) 41,957 Realized Electric generation fuel (6,753 ) (3,194 ) (14,773 ) (36,204 ) Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net (880 ) 2,546 (2,119 ) 15,261 Realized Purchased electricity (4,356 ) (1,282 ) (14,434 ) (16,077 ) Total gain (loss) recognized in income on derivatives $ (11,086 ) $ (10,589 ) $ (52,277 ) $ 3,937 _______________ 1 Interest rate swap contracts are only held at Puget Energy, and matured January 2017. The Company is exposed to credit risk primarily through buying and selling electricity and natural gas to serve its customers. Credit risk is the potential loss resulting from a counterparty's non-performance under an agreement. The Company manages credit risk with policies and procedures for, among other things, counterparty credit analysis, exposure measurement, and exposure monitoring and mitigation. The Company monitors counterparties for significant swings in credit default swap rates, credit rating changes by external rating agencies, ownership changes or financial distress. Where deemed appropriate, the Company may request collateral or other security from its counterparties to mitigate potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of September 30, 2017 , approximately 98.5% of the Company's energy portfolio exposure, excluding normal purchase normal sale (NPNS) transactions, was with counterparties that are rated at least investment grade by rating agencies and 1.5% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies. The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors in the determination of reserves, such as credit default swaps and bond spreads. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels. The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against the unrealized gain (loss) positions. As of September 30, 2017 , the Company was in a net liability position with the majority of its counterparties, so the default factors of counterparties did not have a significant impact on reserves for the period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. In March 2017, PSE began transacting power futures contracts on the Intercontinental Exchange (ICE) platform. Execution of these contracts on ICE requires the daily posting of margin calls as collateral through a futures and clearing agent. As of September 30, 2017 , PSE had cash posted as collateral of $1.4 million related to contracts executed on this platform. As additional contracts are executed on this exchange, the amount of collateral to be posted will increase, subject to PSE’s established limit. PSE also has a $1.0 million letter of credit posted as collateral as a condition of transacting on a physical energy exchange and clearing house in Canada. PSE did not trigger any collateral requirements with any of its counterparties during the nine months ended September 30, 2017 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 at September 30, 2017 : Puget Energy and Puget Sound Energy (Dollars in Thousands) At September 30, 2017 At December 31, 2016 Fair Value 1 Posted Contingent Fair Value 1 Posted Contingent Contingent Feature Liability Collateral Collateral Liability Collateral Collateral Credit rating 2 $ 6,113 $ — $ 6,113 $ 4,894 $ — $ 4,894 Requested credit for adequate assurance 27,214 — — 7,427 — — Forward value of contract 3 739 1,384 — 507 — — Total $ 34,066 $ 1,384 $ 6,113 $ 12,828 $ — $ 4,894 _______________ 1 Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable. 2 Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral. 3 Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements ASC 820 established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy categorizes the inputs into three levels with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority given to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows: Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Equity securities that are also classified as cash equivalents are considered Level 1 if there are unadjusted quoted prices in active markets for identical assets or liabilities. Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options. Level 3 - Pricing inputs include significant inputs that have little or no observability as of the reporting date. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves, contract terms and prices, credit-risk adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs as substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service. The Company considers its electric and natural gas contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes are classified as Level 3 in the fair value hierarchy. Management's assessment is based on the trading activity in real-time and forward electric and natural gas markets. Each quarter, the Company confirms the validity of pricing-service quoted prices used to value Level 2 commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter. Assets and Liabilities with Estimated Fair Value The carrying values of cash and cash equivalents, restricted cash, and short-term debt as reported on the balance sheet are reasonable estimates of their fair value due to the short term nature of these instruments and are classified as Level 1 in the fair value hierarchy. The carrying value of other investments totaling $49.4 million and $49.1 million at September 30, 2017 and December 31, 2016 , respectively, are included in "Other property and investments" on the balance sheet. These values are also reasonable estimates of their fair value and classified as Level 2 in the fair value hierarchy as they are valued based on market rates for similar transactions. The fair value of the junior subordinated and long-term notes was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows: Puget Energy At September 30, 2017 At December 31, 2016 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 246,232 $ 250,000 $ 210,261 Long-term debt (fixed-rate), net of discount 1 2 5,101,936 6,439,413 5,091,593 6,337,287 Long-term debt (variable-rate) 2 83,064 83,064 12,480 12,480 Total liabilities $ 5,435,000 $ 6,768,709 $ 5,354,073 $ 6,560,028 Puget Sound Energy At September 30, 2017 At December 31, 2016 (Dollars in Thousands) Level Carrying Fair Carrying Fair Liabilities: Junior subordinated notes 2 $ 250,000 $ 246,232 $ 250,000 $ 210,261 Long-term debt (fixed-rate), net of discount 2 2 3,499,229 4,465,126 3,497,298 4,360,783 Total liabilities $ 3,749,229 $ 4,711,358 $ 3,747,298 $ 4,571,044 _______________ 1 The carrying value includes debt issuances costs of $29.1 million and $33.0 million for September 30, 2017 and December 31, 2016 , respectively, which are not included in fair value. 2 The carrying value includes debt issuances costs of $25.3 million and $27.2 million for September 30, 2017 and December 31, 2016 , respectively, which are not included in fair value. Assets and Liabilities Measured at Fair Value on a Recurring Basis The following table presents the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis: Puget Energy and Fair Value Fair Value Puget Sound Energy At September 30, 2017 At December 31, 2016 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 7,106 $ 4,550 $ 11,656 $ 30,666 $ 5,794 $ 36,460 Natural gas derivative instruments 3,794 4,032 7,826 23,316 3,303 26,619 Total assets $ 10,900 $ 8,582 $ 19,482 $ 53,982 $ 9,097 $ 63,079 Liabilities: Interest rate derivative instruments 1 $ — $ — $ — $ 141 $ — $ 141 Electric derivative instruments 36,482 3,140 39,622 36,507 4,822 41,329 Natural gas derivative instruments 23,998 1,778 25,776 16,423 2,678 19,101 Total liabilities $ 60,480 $ 4,918 $ 65,398 $ 53,071 $ 7,500 $ 60,571 _______________ 1 Interest rate derivative instruments are only held at Puget Energy, and matured January 2017. The following table presents the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy and Puget Sound Energy Three Months Ended September 30, (Dollars in Thousands) 2017 2016 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ 643 $ 1,456 $ 2,099 $ (3,062 ) $ (484 ) $ (3,546 ) Changes during period: Realized and unrealized energy derivatives: Included in earnings 1 2,458 — 2,458 574 — 574 Included in regulatory assets / liabilities — 2,133 2,133 — (212 ) (212 ) Settlements (1,783 ) (1,301 ) (3,084 ) 93 84 177 Transferred into Level 3 (1,668 ) — (1,668 ) (727 ) — (727 ) Transferred out of Level 3 1,760 (34 ) 1,726 2,532 (331 ) 2,201 Balance at end of period $ 1,410 $ 2,254 $ 3,664 $ (590 ) $ (943 ) $ (1,533 ) ______________ 1 Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $0.9 million for the three months ended September 30, 2017 and 2016 . The following table presents the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy and Puget Sound Energy Nine Months Ended (Dollars in Thousands) 2017 2016 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ 972 $ 625 $ 1,597 $ (7,345 ) $ (2,383 ) $ (9,728 ) Changes during period: Realized and unrealized energy derivatives: Included in earnings 1 3,503 — 3,503 3,228 — 3,228 Included in regulatory assets / liabilities — 5,715 5,715 — 2,869 2,869 Settlements (5,622 ) (4,605 ) (10,227 ) (461 ) (1,731 ) (2,192 ) Transferred into Level 3 523 (553 ) (30 ) (2,807 ) — (2,807 ) Transferred out of Level 3 2,034 1,072 3,106 6,795 302 7,097 Balance at end of period $ 1,410 $ 2,254 $ 3,664 $ (590 ) $ (943 ) $ (1,533 ) ______________ 1 Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $1.9 million and $4.0 million for the nine months ended September 30, 2017 and 2016 , respectively. Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company's consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company's consolidated statements of income. In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company's commodity contracts extend beyond what is considered observable, as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month and reported in the Level 3 Roll-Forward tables. The Company did not have any transfers between Level 1 and Level 2 during the reported periods. The Company does periodically transact at locations or market price points that are illiquid or for which no prices are available from the independent pricing service. In such circumstances, the Company uses a more liquid price point and performs a 15-month regression against the illiquid locations to serve as a proxy for forward market prices. Such transactions are classified as Level 3. The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs. The only significant unobservable input into the fair value measurement of the Company's Level 3 assets and liabilities is the forward price for electric and natural gas contracts. The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of September 30, 2017 : Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 4,550 $ 3,140 Discounted cash flow Power prices (per MWh) $ 8.54 $ 28.98 $ 17.99 Natural gas $ 4,032 $ 1,778 Discounted cash flow Natural gas prices (per MMBtu) $ 0.38 $ 3.09 $ 2.75 _______________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 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 (per MWh) $ 11.86 $ 33.52 $ 27.61 Natural gas $ 3,303 $ 2,678 Discounted cash flow Natural gas prices (per MMBtu) $ 2.00 $ 3.24 $ 2.42 _______________ 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 September 30, 2017 and 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 $1.7 million and $0.2 million , respectively. Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis Puget Energy records the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle. ASC 360 requires long-lived assets to be tested for 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. As of September 30, 2017 , Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets. The Wells Hydro contract was determined to be impaired due to a decrease in forward prices for this contract of 3.5% from June 30, 2017 , causing an impairment of $1.0 million . As of March 31, 2017 , due to significant decreases in forward power prices of 14.1% for years 2017-2022, and 24.4% for years 2023-2035 from December 31, 2016 , impairments totaling $80.3 million were recorded to the Company's intangible asset contracts. The following table presents the impairments recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability: Puget Energy (Dollars in Thousands) Valuation Date Contract Name Carrying Value Fair Value Write Down September 30, 2017 Wells Hydro $ 10,621 $ 9,609 $ 1,012 March 31, 2017 Wells Hydro $ 14,879 $ 13,067 $ 1,812 Rocky Reach 235,331 159,818 75,513 Priest Rapids RP 5,665 2,657 3,008 Total year-to-date impairments $ 81,345 The valuations were measured using a discounted cash flow, income-based valuation methodology. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates classified as Level 3 within the fair value hierarchy. A less significant input is the discount rate reflective of PSE's cost of capital used in the valuation. The following table presents the significant unobservable inputs used in estimating the impaired long-term power purchase contracts' fair value: Puget Energy Valuation Date Unobservable Input Low High Average September 30, 2017 Wells Hydro Power prices (per MWh) $14.06 $26.86 $22.24 Power contract costs per quarter (in thousands) 4,126 4,126 4,126 March 31, 2017 Wells Hydro Power prices (per MWh) $8.76 $26.70 $20.86 Power contract costs per quarter (in thousands) 3,965 4,223 4,051 Rocky Reach Power prices (per MWh) $8.53 $48.21 $27.69 Power contract costs per quarter (in thousands) 5,827 6,780 6,150 Priest Rapids RP Power prices (per MWh) $13.70 $29.38 $23.14 Power contract costs per year (in thousands) 620 4,022 2,306

Retirement Benefits

Retirement Benefits	9 Months Ended
	Sep. 30, 2017
Retirement Benefits [Abstract]
Retirement Benefits	Retirement Benefits PSE has a defined benefit pension plan (Qualified Pension Benefits) covering the largest portion of PSE employees. Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates. Starting January 1, 2014, all non-represented and United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry (UA) represented employees, along with International Brotherhood of Electrical Workers (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 access to group medical care coverage and legacy life insurance benefits (Other Benefits) for certain retired employees. These benefits are provided principally through an insurance company. The group medical 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 net periodic benefit cost for the three and nine months ended September 30, 2017 and 2016 : Puget Energy Qualified SERP Other Three Months Ended September 30, (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Components of net periodic benefit cost: Service cost $ 5,020 $ 4,976 $ 228 $ 271 $ 18 $ 21 Interest cost 7,093 7,064 571 581 125 88 Expected return on plan assets (11,945 ) (11,589 ) — — (115 ) (112 ) Amortization of prior service cost (495 ) (495 ) 11 11 — — Amortization of net loss (gain) — — 269 228 (101 ) (233 ) Net periodic benefit cost $ (327 ) $ (44 ) $ 1,079 $ 1,091 $ (73 ) $ (236 ) Puget Energy Qualified SERP Other Nine Months Ended (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Components of net periodic benefit cost: Service cost $ 15,060 $ 14,185 $ 685 $ 814 $ 54 $ 70 Interest cost 21,279 21,516 1,714 1,744 375 399 Expected return on plan assets (35,837 ) (34,964 ) — — (346 ) (334 ) Amortization of prior service cost (1,485 ) (1,485 ) 33 32 — — Amortization of net loss (gain) — — 807 683 (302 ) (289 ) Net periodic benefit cost $ (983 ) $ (748 ) $ 3,239 $ 3,273 $ (219 ) $ (154 ) Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Three Months Ended September 30, (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Components of net periodic benefit cost: Service cost $ 5,020 $ 4,976 $ 228 $ 271 $ 18 $ 21 Interest cost 7,093 7,064 571 581 125 88 Expected return on plan assets (11,965 ) (11,638 ) — — (115 ) (112 ) Amortization of prior service cost (393 ) (393 ) 11 11 — — Amortization of net loss (gain) 3,262 3,963 392 333 (160 ) (295 ) Net periodic benefit cost $ 3,017 $ 3,972 $ 1,202 $ 1,196 $ (132 ) $ (298 ) Puget Sound Energy Qualified SERP Other Nine Months Ended (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Components of net periodic benefit cost: Service cost $ 15,060 $ 14,185 $ 685 $ 814 $ 54 $ 70 Interest cost 21,279 21,516 1,714 1,744 375 399 Expected return on plan assets (35,896 ) (35,110 ) — — (346 ) (334 ) Amortization of prior service cost (1,180 ) (1,180 ) 33 33 — — Amortization of net loss (gain) 9,786 11,443 1,175 997 (480 ) (474 ) Net periodic benefit cost $ 9,049 $ 10,854 $ 3,607 $ 3,588 $ (397 ) $ (339 ) The following table summarizes the Company’s change in benefit obligation for the periods ended September 30, 2017 and December 31, 2016 : Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Nine Months Ended Year Nine Months Ended Year Nine Months Ended Year (Dollars in Thousands) September 30, December 31, September 30, December 31, September 30, December 31, Change in benefit obligation: Benefit obligation at beginning of period $ 652,607 $ 643,088 $ 51,734 $ 51,279 $ 11,194 $ 13,946 Service cost 15,060 18,913 685 1,085 54 93 Interest cost 21,279 28,689 1,714 2,325 375 533 Actuarial loss (gain) (253 ) 1,545 — 106 373 (2,262 ) Benefits paid (31,344 ) (38,730 ) (1,428 ) (3,061 ) (857 ) (1,264 ) Medicare part D subsidy received — — — — 100 148 Administrative Expense — (898 ) — — — — Benefit obligation at end of period $ 657,349 $ 652,607 $ 52,705 $ 51,734 $ 11,239 $ 11,194 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. During the three months ended September 30, 2017 , the Company made no contributions to fund the qualified pension plan, as the aggregate funding for the year has already been reached for the year ending December 31, 2017 . During the three months ended September 30, 2017 , the Company contributed $0.5 million and $0.1 million to fund the SERP and other postretirement plan, respectively. During the nine months ended September 30, 2017 , the Company contributed $18.0 million , $1.4 million and $0.2 million to fund the qualified pension plan, SERP and other postretirement plan, respectively.

Regulation and Rates

Regulation and Rates	9 Months Ended
	Sep. 30, 2017
Regulation and Rates [Abstract]
Regulation and Rates	Regulation and Rates 2013 Expedited Rate Filing, Decoupling and Centralia Decision On June 25, 2013, the Washington Commission issued final orders resolving the amended decoupling petition, the expedited rate filing (ERF) 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 to 7.77% which updated 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 K-Factor (rate plan) 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 January 13, 2017, as discussed below. In the rate plan, increases are subject to a cap of 3.0% of the total revenue for customers. General Rate Case Filing On January 13, 2017, PSE filed its GRC with the Washington Commission which proposed a weighted cost of capital of 7.74% , or 6.69% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.8% . The requested combined electric tariff changes were a net increase of $86.3 million , or 4.1% , annually. The requested combined natural gas tariff changes were a net decrease of $22.3 million , or 2.4% , annually. 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 filed a supplemental filing in the GRC on April 3, 2017, which among other things provided updates to power costs. The requested combined electric tariff changes based on the updated supplemental filing would result in a net increase of $67.9 million , or 3.2% , annually. The requested combined natural gas tariff changes based on the updated supplemental filing would result in a net decrease of $29.3 million , or 3.2% , annually. PSE’s GRC filing included the required plan for Colstrip Units 1 and 2 closures, see Item 3, "Legal Proceedings" in the Company's Annual Report on the Form 10-K for the year ended December 31, 2016. The filing also requested that electric energy supply fixed costs be included in PSE’s decoupling mechanism. 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 cost recovery mechanism (CRM), similar to its existing natural gas CRM, which would allow PSE to obtain accelerated cost recovery on specified electric reliability projects. On September 15, 2017, ten of the eleven parties, including PSE, filed a settlement agreement with the Washington Commission. The settlement agreement, if accepted by the Washington Commission, would resolve all but four of the contested issues between the settling parties. The settlement agreement provides for a weighted cost of capital of 7.6% or 6.55% after-tax, and a capital structure of 48.5% in common equity with a return on equity of 9.5% . The settlement also recommends a combined electric tariff change that would result in a net increase of $20.2 million , or 0.9% and a combined natural gas tariff change that would result in a net decrease of $35.5 million , or 3.8% . The contested issues are PSE’s proposed electric CRM, the majority of decoupling issues, certain portions of electric rate spread/rate design issues and the entire natural gas rate spread/rate design-related issues. Hearings were held on August 30, 2017 regarding the contested issues and on September 29, 2017 regarding the multi-party settlement. 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 most residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues will be recovered on a per customer basis regardless of actual consumption levels. Currently, PSE's energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. PSE has requested that the electric energy supply fixed costs be included in the decoupling mechanism in its pending GRC as is discussed above. Under the current mechanism, the revenue recorded under the decoupling mechanisms is affected by customer growth and not actual consumption. One opposing party in PSE’s pending GRC is advocating that PSE's decoupling mechanism be changed so that the revenue per customer PSE is allowed to recover under the mechanism is set at the number of customers which exist in a given test year rather than to provide for the change in customers after the test year which PSE's existing decoupling mechanism currently allows. Other parties have advocated for certain customer groups to be excluded from the decoupling mechanisms. 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 in May following the calendar year end. The decoupling mechanism will end on December 31, 2017, unless the requested continuation of the mechanism is approved in PSE's 2017 GRC. PSE's decoupling mechanism 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) 1 Electric: May 1, 2017 2.0% $41.9 May 1, 2016 1.0 20.8 Natural Gas: May 1, 2017 2.4% $22.4 May 1, 2016 2.8 25.4 _______________ 1 The increase in revenue is net of reductions from excess earnings of $11.9 million for electric and $2.2 million for natural gas in 2017, and $11.9 million for electric and $5.5 million for natural gas in 2016. 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 for natural gas with no impacts to electric: Effective Date Accrued Through Deferrals not Included in Annual Rate Increases (Dollars in Millions) Natural Gas: 2016 $47.4 2015 28.7 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 Institute of Electrical and Electronics Engineers outage criteria for a system average interruption duration index. For the nine months ended September 30, 2017 and 2016 , PSE incurred $21.1 million and $15.6 million , respectively, in storm-related electric transmission and distribution system restoration costs, of which $12.4 million was deferred to a regulatory asset in 2017 and $6.5 million in 2016 . 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 applies the following graduated scale: Company's Share Customers' Share Annual Power Cost Variability Over Under Over Under Over or Under Collected by up to $17 million 100% 100% —% —% Over or Under Collected by between $17 million - $40 million 35 50 65 50 Over or Under Collected beyond $40 + million 10 10 90 90 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, depreciation, transmission expense and revenues on specific transmission assets; and (iii) hydroelectric, 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. For the nine months ended September 30, 2017 , PSE under recovered its power costs by $8.9 million of which no amount was apportioned to customers. This compares to an over recovery of power costs of $1.4 million for the nine months ended September 30, 2016 of which no amounts were apportioned to customers. Although load increased in 2017 compared to 2016 that increase was offset by a decrease in the total baseline rate and an increase in costs. Additionally, the year over year change was due to the 2017 mechanism where fixed production costs, other costs and adjustments are no longer included. The mechanism is now comparing variable PCA costs using the variable costs portion of the baseline rate. The fixed costs will become part of the decoupling mechanism, assuming the decoupling mechanism continues after its review in the GRC, but until then the revenue variance associated with the fixed production costs are being deferred using the fixed cost portion of the baseline rate. Electric Conservation Rider The electric conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January and to true-up for actual compared to forecast conservation expenditures from the prior year as well as actual load being different than the forecasted load set in rates. The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates: Effective Date Average Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2017 0.7% $16.5 May 1, 2016 (0.5) (11.7) Electric Property Tax Tracker Mechanism The purpose of the property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism removes property taxes from general rates and includes those costs for recovery in an adjusting tariff rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes paid. The tracker will be adjusted on May 1 each year based on that year's assessed property taxes and true-ups to the rate from the prior year. The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding expected 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 (0.04)% $(0.9) May 1, 2016 0.3 5.7 Federal Incentive Tracker Tariff The federal incentive tracker tariff passes through to customers the benefits associated with realized treasury grants and production tax credits. The filing results in a credit back to customers for pass-back of treasury grant amortization and pass-through of interest and any related true-ups. The filing is adjusted annually for new federal benefits, actual versus forecast interest and to true-up for actual load being different than the forecasted load set in rates. The following table sets forth the federal incentive tracker tariff revenue requirement proposed, as originally filed, by PSE and/or approved by the Washington Commission and the corresponding expected annual 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, 2018, proposed 0.2% $(48.2) January 1, 2017 0.3 (51.7) January 1, 2016 (0.2) (57.3) Residential Exchange Benefit The residential exchange program passes through the residential exchange program benefits that PSE will be receiving from the Bonneville Power Administration (BPA) between October 1, 2017 and September 30, 2019. Rates change bi-annually on October 1. The following table sets forth residential exchange benefit adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Total credit to be passed back to eligible customers (Dollars in Millions) October 1, 2017 (0.6)% $(80.8) October 1, 2015 2.4 (76.4) Power Cost Update Compliance Filing The power cost update compliance filing is an update to a limited-scope proceeding to periodically reset power cost rates. In addition to providing the opportunity to reset all power costs, the PCORC proceeding also provides for timely review of new resource acquisition costs and inclusion of such costs in rates at the time the new resource goes into service. To achieve this objective, the Washington Commission has used an expedited six-month PCORC decision timeline rather than the statutory 11-month timeline for a GRC. On September 30, 2016, PSE filed with the Washington Commission an update to power costs under Schedule 95, which was consistent with the Washington Commission’s Order No. 04 in the 2014 PCORC, and required under the joint petition filed March 9, 2016, seeking to postpone the filing of PSE’s GRC. The following table sets forth the updated compliance filing rate adjustment that became effective on December 1, 2016, by operation of law and the corresponding expected annual impact on PSE's revenue based on the effective date: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) December 1, 2016 (1.7)% $(37.3) Natural Gas Regulation and Rates Natural Gas Conservation Rider The natural gas conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January and to true-up for actual versus forecast conservation expenditures from the prior year as well as actual load being different than the forecasted load set in rates. The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding expected 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 (0.1)% $(1.0) May 1, 2016 0.3 2.9 Natural Gas Property Tax Tracker Mechanism The purpose of the property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism removes property taxes from general rates and includes those costs for recovery in an adjusting tariff rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes paid. The tracker will be adjusted on May 1 each year based on that year's assessed property taxes. The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates: Effective Date Average Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2017 (0.1)% $(1.1) May 1, 2016 0.4 3.5 Natural Gas Cost Recovery Mechanism The purpose of the CRM is to recover capital costs related to projects included in PSE's pipe replacement program plan on file with the Washington Commission with the intended effect of enhancing the safety of the natural gas distribution system. The following table sets forth CRM rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates: Effective Date Average Increase (Decrease) in Revenue (Dollars in Millions) November 1, 2017 0.5% $4.9 November 1, 2016 0.6 5.6 Purchased Gas Adjustment PSE has a PGA mechanism that allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or payable, any natural gas supply and transportation costs that exceed or fall short of this expected natural gas cost amount in PGA mechanism rates, including accrued interest. PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable and payable balances. A receivable or payable balance in the PGA mechanism reflects an under recovery or over recovery, respectively, of natural gas cost through the PGA mechanism. The following table sets forth the PGA rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective date: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) November 1, 2017 (3.3)% $(30.8) November 1, 2016 (0.4) (4.1)

Asset Retirement Obligation

Asset Retirement Obligation	9 Months Ended
	Sep. 30, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	Asset Retirement Obligations The Company has recorded liabilities for steam generation sites, combustion turbine generation sites, wind generation sites, distribution and transmission poles, and natural gas mains where disposal is governed by ASC 410 “Asset Retirement and Environmental Obligations" (ARO). On April 17, 2015, the U.S. Environmental Protection Agency (EPA) published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCR) under the Resource Conservation and Recovery Act, Subtitle D. The CCR ruling requires the Company to perform an extensive study on the effects of coal ash on the environment and public health. The rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments. The CCR rule and two new 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. The changes were reviewed by the Company and the plant operator in 2015 and 2016. PSE had previously recognized a legal obligation in 2003 under EPA rules to dispose of coal ash material at Colstrip. Due to the updated Colstrip information, additional disposal costs were added to the ARO. On September 6, 2016, PSE entered into two new agreements requiring the Company to close the Colstrip 1 and 2 plants on or before July 1, 2022 and to incur additional costs, such as, monitoring, water treatment, forced evaporation and post-closure care for all Colstrip Units. As a result, in 2016 the Company increased the Colstrip ARO ending liability by $45.7 million for Colstrip Units 1 and 2 and $37.0 million for Colstrip Units 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. The Company will continue to gather additional data and coordinate with the plant operator to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, the Company will update the ARO obligation for these changes, which could be material. For the nine months ended September 30, 2017 the Company reviewed the estimated remediation costs at Colstrip and reduced the Colstrip ARO liability by $5.5 million for Colstrip Units 1 and 2 and $12.7 million for Colstrip Units 3 and 4. In addition, the Company recorded a new Tacoma LNG facility ARO liability of $1.5 million for PSE and $1.4 million for Puget LNG in September 2017. The following table describes the changes to the Company’s ARO for the nine months ended September 30, 2017 : Puget Energy and Puget Sound Energy (Dollars in Thousands) Changes in ARO Balance at December 31, 2016 $ 200,345 New asset retirement obligation recognized in the period 1 2,881 Liability adjustments (1,035 ) Revisions in estimated cash flows (18,462 ) Accretion expense 4,126 Balance at September 30, 2017 $ 187,855 _______________ 1 New asset retirement obligations include $1.4 million ARO for Puget LNG only held at Puget Energy.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	(8) Commitment and Contingencies Colstrip PSE has a 50% ownership interest in Colstrip Units 1 and 2 and a 25% interest in Colstrip Units 3 and 4. On March 6, 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. On July 12, 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station, which was approved by the court on September 6, 2016. As part of the settlement that was signed by all Colstrip owners, Colstrip 1 and 2 owners, PSE and Talen Energy, agreed to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana by no later than July 1, 2022. 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 utility plant asset to a regulatory asset, which represents the expected NBV at retirement of Colstrip Units 1 and 2, based on the expected shutdown date of July 1, 2022 as of December 31, 2016 . Due to a re-estimate of Colstrip Units 1 and 2 ARO costs, the regulatory asset account was reduced to $175.0 million as of September 30, 2017 . 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 ARO for Colstrip Units 1 and 2, the full scope of decommissioning activities and costs may vary from the estimates that are available at this time. Greenwood On March 9, 2016, a natural gas explosion occurred in the Greenwood neighborhood of Seattle, WA, damaging multiple structures. The Washington Commission Staff completed its investigation of the incident and filed a complaint on September 20, 2016, seeking up to $3.2 million in fines from PSE. As of September 30, 2016, PSE accrued $3.2 million for the fine. On March 28, 2017, pipeline safety regulators and PSE reached a settlement in response to the complaint. As part of the agreement, PSE agreed to pay a penalty of $2.8 million , of which $1.3 million was suspended on condition that PSE complete a comprehensive inspection and remediation program. On June 19, 2017, the Washington Commission approved the settlement without conditions and adopted the reduced penalty of $2.8 million , of which $1.3 million was suspended. On June 30, 2017, PSE paid the $1.5 million penalty it had accrued previously to a liability reserve account for property damage claims. However, litigation is still pending regarding damage and personal injury claims. Other Commitments and Contingencies The Company is also involved in litigation relating to claims arising out of its operations in the normal course of business. The Company recorded reserves of $0.6 million and $0.7 million relating to these claims as of September 30, 2017 and December 31, 2016 , respectively. In addition to the contractual obligations and consolidated commercial commitments disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2016 , during the nine months ended September 30, 2017 , the Company entered into new power supply and service contracts with estimated payment obligations totaling $729.5 million through 2028.

Summary of Consolidation Poli16

Summary of Consolidation Policy (Policies)	9 Months Ended
	Sep. 30, 2017
Accounting Policies [Abstract]
Significant Accounting Policies	Summary of Consolidation Policy Basis of Presentation Puget Energy is an energy services holding company that owns Puget Sound Energy (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy also has a wholly-owned non-regulated subsidiary, 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 the Tacoma LNG facility, currently under construction. PSE and Puget LNG are considered related parties with similar ownership by Puget Energy. Therefore, capital and operating costs that occur under PSE and are allocated to Puget LNG are related party transactions by nature. As of September 30, 2017 , Puget LNG has incurred $86.5 million in construction work in progress and operating costs related to Puget LNG’s portion of the Tacoma LNG facility. In 2009, Puget Holdings, LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiaries. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company.” The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any 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. Tacoma LNG Facility The Tacoma LNG facility will provide peak-shaving services to PSE’s natural gas customers, and will provide LNG as fuel to transportation customers, particularly in the marine market. The Tacoma LNG facility is expected to be operational in 2019. Pursuant to the Washington Commission’s order, Puget LNG will be allocated approximately 57.0% of the capital and operating costs of the Tacoma LNG facility and PSE will be allocated the remaining 43.0% of the capital and operating costs. For Puget Energy, $86.4 million in construction work in progress related to Puget LNG’s portion of the Tacoma LNG facility is reported in the “Other property and investments” financial statement line item. For PSE, construction work in progress of $76.3 million related to PSE’s portion of the Tacoma LNG facility is reported in the “Utility plant - Natural gas plant” line item, as PSE is a regulated entity.

Accounting for Derivative Ins17

Accounting for Derivative Instruments and Hedging Activities (Tables)	9 Months Ended
	Sep. 30, 2017
Derivative [Line Items]
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 September 30, 2017 At December 31, 2016 (Dollars in Thousands) Volumes Assets 1 Liabilities 2 Volumes Assets 1 Liabilities 2 Interest rate swap derivatives 3 $ — $ — $ — $450 million $ — $ 141 Electric portfolio derivatives * 11,656 39,622 * 36,460 41,329 Natural gas derivatives (MMBtus) 4 305.3 million 7,826 25,776 336.4 million 26,619 19,101 Total derivative contracts ** $ 19,482 $ 65,398 ** $ 63,079 $ 60,571 Current ** $ 16,605 $ 49,820 ** $ 54,341 $ 44,310 Long-term ** 2,877 15,578 ** 8,738 16,261 Total derivative contracts ** $ 19,482 $ 65,398 ** $ 63,079 $ 60,571 _______________ 1 Balance sheet locations: Current and Long-term Unrealized gain on derivative instruments. 2 Balance sheet locations: Current and Long-term Unrealized loss on derivative instruments. 3 Interest rate swap contracts are only held at Puget Energy, and matured January 2017. 4 All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the purchased gas adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 165.0 million One Million British Thermal Units (MMBtu) and purchased electricity of 2.6 million Megawatt Hours (MWhs) at September 30, 2017 , and 186.8 million MMBtus and 3.6 million MWhs at December 31, 2016 . ** Not meaningful and/or applicable.
Offsetting Assets and Liabilities	The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities: Puget Energy and Puget Sound Energy At September 30, 2017 Gross Amount Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position (Dollars in Thousands) Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 19,482 $ — $ 19,482 $ (12,961 ) $ — $ 6,521 Liabilities: Energy derivative contracts 65,398 — 65,398 (12,961 ) (739 ) 51,698 Puget Energy and Puget Sound Energy At December 31, 2016 Gross Amount Recognized in the Statement of Financial Position 1 Gross Amounts Offset in the Statement of Financial Position Net of Amounts Presented in the Statement of Financial Position Gross Amounts Not Offset in the Statement of Financial Position (Dollars in Thousands) Commodity Contracts Cash Collateral Received/Posted Net Amount Assets: Energy derivative contracts $ 63,079 $ — $ 63,079 $ (42,858 ) $ — $ 20,221 Liabilities: Energy derivative contracts 60,430 — 60,430 (42,858 ) — 17,572 Interest rate swaps 2 141 — 141 — — 141 _______________ 1 All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off. 2 Interest rate swap contracts are only held at Puget Energy
Schedule of Credit Risk Related Contingent Features	The table below presents the fair value of the overall contractual contingent liability positions for the Company's derivative activity at September 30, 2017 : Puget Energy and Puget Sound Energy (Dollars in Thousands) At September 30, 2017 At December 31, 2016 Fair Value 1 Posted Contingent Fair Value 1 Posted Contingent Contingent Feature Liability Collateral Collateral Liability Collateral Collateral Credit rating 2 $ 6,113 $ — $ 6,113 $ 4,894 $ — $ 4,894 Requested credit for adequate assurance 27,214 — — 7,427 — — Forward value of contract 3 739 1,384 — 507 — — Total $ 34,066 $ 1,384 $ 6,113 $ 12,828 $ — $ 4,894 _______________ 1 Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable. 2 Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral. 3 Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.
Parent Company [Member]
Derivative [Line Items]
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance	The following table presents the effect and locations of the realized and unrealized gains (losses) of the Company's derivatives recorded on the statements of income: Puget Energy and Three Months Ended September 30, Nine Months Ended (Dollars in Thousands) Location 2017 2016 2017 2016 Interest rate contracts 1 : Non-hedged interest rate swap (expense) income $ — $ 563 $ 28 $ (651 ) Interest expense — (349 ) — (349 ) Gas for Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net 903 (8,873 ) (20,979 ) 41,957 Realized Electric generation fuel (6,753 ) (3,194 ) (14,773 ) (36,204 ) Power Derivatives: Unrealized Unrealized gain (loss) on derivative instruments, net (880 ) 2,546 (2,119 ) 15,261 Realized Purchased electricity (4,356 ) (1,282 ) (14,434 ) (16,077 ) Total gain (loss) recognized in income on derivatives $ (11,086 ) $ (10,589 ) $ (52,277 ) $ 3,937

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Schedule of Impaired Intangible Assets	impairments totaling $80.3 million were recorded to the Company's intangible asset contracts. The following table presents the impairments recorded to the Company's intangible asset contracts, with corresponding reductions to the regulatory liability: Puget Energy (Dollars in Thousands) Valuation Date Contract Name Carrying Value Fair Value Write Down September 30, 2017 Wells Hydro $ 10,621 $ 9,609 $ 1,012 March 31, 2017 Wells Hydro $ 14,879 $ 13,067 $ 1,812 Rocky Reach 235,331 159,818 75,513 Priest Rapids RP 5,665 2,657 3,008 Total year-to-date impairments $ 81,345
Fair Value Inputs, Liabilities, Quantitative Information	The fair value of the junior subordinated and long-term notes was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company's credit spreads as inputs, interpolating to the maturity date of each issue. The carrying values and estimated fair values were as follows: Puget Energy At September 30, 2017 At December 31, 2016 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 246,232 $ 250,000 $ 210,261 Long-term debt (fixed-rate), net of discount 1 2 5,101,936 6,439,413 5,091,593 6,337,287 Long-term debt (variable-rate) 2 83,064 83,064 12,480 12,480 Total liabilities $ 5,435,000 $ 6,768,709 $ 5,354,073 $ 6,560,028 Puget Sound Energy At September 30, 2017 At December 31, 2016 (Dollars in Thousands) Level Carrying Fair Carrying Fair Liabilities: Junior subordinated notes 2 $ 250,000 $ 246,232 $ 250,000 $ 210,261 Long-term debt (fixed-rate), net of discount 2 2 3,499,229 4,465,126 3,497,298 4,360,783 Total liabilities $ 3,749,229 $ 4,711,358 $ 3,747,298 $ 4,571,044 _______________ 1 The carrying value includes debt issuances costs of $29.1 million and $33.0 million for September 30, 2017 and December 31, 2016 , respectively, which are not included in fair value. 2 The carrying value includes debt issuances costs of $25.3 million and $27.2 million for September 30, 2017 and December 31, 2016 , respectively, which are not included in fair value.
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation	Puget Energy and Puget Sound Energy Three Months Ended September 30, (Dollars in Thousands) 2017 2016 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ 643 $ 1,456 $ 2,099 $ (3,062 ) $ (484 ) $ (3,546 ) Changes during period: Realized and unrealized energy derivatives: Included in earnings 1 2,458 — 2,458 574 — 574 Included in regulatory assets / liabilities — 2,133 2,133 — (212 ) (212 ) Settlements (1,783 ) (1,301 ) (3,084 ) 93 84 177 Transferred into Level 3 (1,668 ) — (1,668 ) (727 ) — (727 ) Transferred out of Level 3 1,760 (34 ) 1,726 2,532 (331 ) 2,201 Balance at end of period $ 1,410 $ 2,254 $ 3,664 $ (590 ) $ (943 ) $ (1,533 ) ______________ 1 Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $0.9 million for the three months ended September 30, 2017 and 2016 . The following table presents the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy and Puget Sound Energy Nine Months Ended (Dollars in Thousands) 2017 2016 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ 972 $ 625 $ 1,597 $ (7,345 ) $ (2,383 ) $ (9,728 ) Changes during period: Realized and unrealized energy derivatives: Included in earnings 1 3,503 — 3,503 3,228 — 3,228 Included in regulatory assets / liabilities — 5,715 5,715 — 2,869 2,869 Settlements (5,622 ) (4,605 ) (10,227 ) (461 ) (1,731 ) (2,192 ) Transferred into Level 3 523 (553 ) (30 ) (2,807 ) — (2,807 ) Transferred out of Level 3 2,034 1,072 3,106 6,795 302 7,097 Balance at end of period $ 1,410 $ 2,254 $ 3,664 $ (590 ) $ (943 ) $ (1,533 ) ______________ 1 Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Amounts include unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $1.9 million and $4.0 million for the nine months ended September 30, 2017 and 2016 , respectively.
Fair Value Inputs, Assets and Liabilities, Quantitative Information	The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of September 30, 2017 : Puget Energy and Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 4,550 $ 3,140 Discounted cash flow Power prices (per MWh) $ 8.54 $ 28.98 $ 17.99 Natural gas $ 4,032 $ 1,778 Discounted cash flow Natural gas prices (per MMBtu) $ 0.38 $ 3.09 $ 2.75 _______________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 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 (per MWh) $ 11.86 $ 33.52 $ 27.61 Natural gas $ 3,303 $ 2,678 Discounted cash flow Natural gas prices (per MMBtu) $ 2.00 $ 3.24 $ 2.42 _______________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. The following table presents the significant unobservable inputs used in estimating the impaired long-term power purchase contracts' fair value: Puget Energy Valuation Date Unobservable Input Low High Average September 30, 2017 Wells Hydro Power prices (per MWh) $14.06 $26.86 $22.24 Power contract costs per quarter (in thousands) 4,126 4,126 4,126 March 31, 2017 Wells Hydro Power prices (per MWh) $8.76 $26.70 $20.86 Power contract costs per quarter (in thousands) 3,965 4,223 4,051 Rocky Reach Power prices (per MWh) $8.53 $48.21 $27.69 Power contract costs per quarter (in thousands) 5,827 6,780 6,150 Priest Rapids RP Power prices (per MWh) $13.70 $29.38 $23.14 Power contract costs per year (in thousands) 620 4,022 2,306
Parent Company [Member]
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 table presents the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis:
Subsidiaries [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	Puget Energy and Fair Value Fair Value Puget Sound Energy At September 30, 2017 At December 31, 2016 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 7,106 $ 4,550 $ 11,656 $ 30,666 $ 5,794 $ 36,460 Natural gas derivative instruments 3,794 4,032 7,826 23,316 3,303 26,619 Total assets $ 10,900 $ 8,582 $ 19,482 $ 53,982 $ 9,097 $ 63,079 Liabilities: Interest rate derivative instruments 1 $ — $ — $ — $ 141 $ — $ 141 Electric derivative instruments 36,482 3,140 39,622 36,507 4,822 41,329 Natural gas derivative instruments 23,998 1,778 25,776 16,423 2,678 19,101 Total liabilities $ 60,480 $ 4,918 $ 65,398 $ 53,071 $ 7,500 $ 60,571

Retirement Benefits (Tables)

Retirement Benefits (Tables)	9 Months Ended
	Sep. 30, 2017
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Schedule of Changes in Projected Benefit Obligations	The following table summarizes the Company’s change in benefit obligation for the periods ended September 30, 2017 and December 31, 2016 : Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Nine Months Ended Year Nine Months Ended Year Nine Months Ended Year (Dollars in Thousands) September 30, December 31, September 30, December 31, September 30, December 31, Change in benefit obligation: Benefit obligation at beginning of period $ 652,607 $ 643,088 $ 51,734 $ 51,279 $ 11,194 $ 13,946 Service cost 15,060 18,913 685 1,085 54 93 Interest cost 21,279 28,689 1,714 2,325 375 533 Actuarial loss (gain) (253 ) 1,545 — 106 373 (2,262 ) Benefits paid (31,344 ) (38,730 ) (1,428 ) (3,061 ) (857 ) (1,264 ) Medicare part D subsidy received — — — — 100 148 Administrative Expense — (898 ) — — — — Benefit obligation at end of period $ 657,349 $ 652,607 $ 52,705 $ 51,734 $ 11,239 $ 11,194
Parent Company [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Schedule of Net Benefit Costs	The following tables summarize the Company’s net periodic benefit cost for the three and nine months ended September 30, 2017 and 2016 : Puget Energy Qualified SERP Other Three Months Ended September 30, (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Components of net periodic benefit cost: Service cost $ 5,020 $ 4,976 $ 228 $ 271 $ 18 $ 21 Interest cost 7,093 7,064 571 581 125 88 Expected return on plan assets (11,945 ) (11,589 ) — — (115 ) (112 ) Amortization of prior service cost (495 ) (495 ) 11 11 — — Amortization of net loss (gain) — — 269 228 (101 ) (233 ) Net periodic benefit cost $ (327 ) $ (44 ) $ 1,079 $ 1,091 $ (73 ) $ (236 ) Puget Energy Qualified SERP Other Nine Months Ended (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Components of net periodic benefit cost: Service cost $ 15,060 $ 14,185 $ 685 $ 814 $ 54 $ 70 Interest cost 21,279 21,516 1,714 1,744 375 399 Expected return on plan assets (35,837 ) (34,964 ) — — (346 ) (334 ) Amortization of prior service cost (1,485 ) (1,485 ) 33 32 — — Amortization of net loss (gain) — — 807 683 (302 ) (289 ) Net periodic benefit cost $ (983 ) $ (748 ) $ 3,239 $ 3,273 $ (219 ) $ (154 )
Subsidiaries [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Schedule of Net Benefit Costs	Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Three Months Ended September 30, (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Components of net periodic benefit cost: Service cost $ 5,020 $ 4,976 $ 228 $ 271 $ 18 $ 21 Interest cost 7,093 7,064 571 581 125 88 Expected return on plan assets (11,965 ) (11,638 ) — — (115 ) (112 ) Amortization of prior service cost (393 ) (393 ) 11 11 — — Amortization of net loss (gain) 3,262 3,963 392 333 (160 ) (295 ) Net periodic benefit cost $ 3,017 $ 3,972 $ 1,202 $ 1,196 $ (132 ) $ (298 ) Puget Sound Energy Qualified SERP Other Nine Months Ended (Dollars in Thousands) 2017 2016 2017 2016 2017 2016 Components of net periodic benefit cost: Service cost $ 15,060 $ 14,185 $ 685 $ 814 $ 54 $ 70 Interest cost 21,279 21,516 1,714 1,744 375 399 Expected return on plan assets (35,896 ) (35,110 ) — — (346 ) (334 ) Amortization of prior service cost (1,180 ) (1,180 ) 33 33 — — Amortization of net loss (gain) 9,786 11,443 1,175 997 (480 ) (474 ) Net periodic benefit cost $ 9,049 $ 10,854 $ 3,607 $ 3,588 $ (397 ) $ (339 )

Regulation and Rates Public Ut

Regulation and Rates Public Utilities, Regulatory Proceeding (Tables) - Subsidiaries [Member]	9 Months Ended
	Sep. 30, 2017
Decoupling Mechanism [Member]
Regulation and Rates [Line Items]
Schedule of Deferrals Not Included in Rate Increases	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 for natural gas with no impacts to electric: Effective Date Accrued Through Deferrals not Included in Annual Rate Increases (Dollars in Millions) Natural Gas: 2016 $47.4 2015 28.7
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) 1 Electric: May 1, 2017 2.0% $41.9 May 1, 2016 1.0 20.8 Natural Gas: May 1, 2017 2.4% $22.4 May 1, 2016 2.8 25.4 _______________ 1 The increase in revenue is net of reductions from excess earnings of $11.9 million for electric and $2.2 million for natural gas in 2017, and $11.9 million for electric and $5.5 million for natural gas in 2016.
PCA Mechanism [Member] | Electric [Member]
Regulation and Rates [Line Items]
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments	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 applies the following graduated scale: Company's Share Customers' Share Annual Power Cost Variability Over Under Over Under Over or Under Collected by up to $17 million 100% 100% —% —% Over or Under Collected by between $17 million - $40 million 35 50 65 50 Over or Under Collected beyond $40 + million 10 10 90 90 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
Property tax tracker [Member] [Domain] | Natural Gas [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 expected annual impact on PSE’s revenue based on the effective dates: Effective Date Average Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2017 (0.1)% $(1.1) May 1, 2016 0.4 3.5
Property tax tracker [Member] [Domain] | 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 expected 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 (0.04)% $(0.9) May 1, 2016 0.3 5.7
Conservation Rider [Member] | Natural Gas [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 expected 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 (0.1)% $(1.0) May 1, 2016 0.3 2.9
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 expected annual impact on PSE’s revenue based on the effective dates: Effective Date Average Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2017 0.7% $16.5 May 1, 2016 (0.5) (11.7)
Treasury Grants [Member] | Electric [Member]
Regulation and Rates [Line Items]
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments	The following table sets forth the federal incentive tracker tariff revenue requirement proposed, as originally filed, by PSE and/or approved by the Washington Commission and the corresponding expected annual 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, 2018, proposed 0.2% $(48.2) January 1, 2017 0.3 (51.7) January 1, 2016 (0.2) (57.3)
Residential Exchange Benefit [Member] | Electric [Member]
Regulation and Rates [Line Items]
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments	The following table sets forth residential exchange benefit adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Total credit to be passed back to eligible customers (Dollars in Millions) October 1, 2017 (0.6)% $(80.8) October 1, 2015 2.4 (76.4)
Power Cost Only Rate Case (PCORC) [Member] | Electric [Member]
Regulation and Rates [Line Items]
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments	The following table sets forth the updated compliance filing rate adjustment that became effective on December 1, 2016, by operation of law and the corresponding expected annual impact on PSE's revenue based on the effective date: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) December 1, 2016 (1.7)% $(37.3)
Cost recovery mechanism [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments	The following table sets forth CRM rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective dates: Effective Date Average Increase (Decrease) in Revenue (Dollars in Millions) November 1, 2017 0.5% $4.9 November 1, 2016 0.6 5.6
Purchased Gas Adjustment (PGA) [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments	The following table sets forth the PGA rate adjustments approved by the Washington Commission and the corresponding expected annual impact on PSE’s revenue based on the effective date: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) November 1, 2017 (3.3)% $(30.8) November 1, 2016 (0.4) (4.1)

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	9 Months Ended
	Sep. 30, 2017
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations	The following table describes the changes to the Company’s ARO for the nine months ended September 30, 2017 : Puget Energy and Puget Sound Energy (Dollars in Thousands) Changes in ARO Balance at December 31, 2016 $ 200,345 New asset retirement obligation recognized in the period 1 2,881 Liability adjustments (1,035 ) Revisions in estimated cash flows (18,462 ) Accretion expense 4,126 Balance at September 30, 2017 $ 187,855 _______________ 1 New asset retirement obligations include $1.4 million ARO for Puget LNG only held at Puget Energy.

Summary of Consolidation Poli22

Summary of Consolidation Policy (Details) $ in Millions	Sep. 30, 2017USD ($)mi²
Subsidiaries [Member]
Summary of Consolidation Policy
Area of Service Territory (in sqmi) | mi²	6,000
Subsidiaries [Member] | Tacoma LNG [Member]
Summary of Consolidation Policy
Jointly Owned Non-Utility Plant Share	43.00%
Construction in Progress, Gross	$ 76.3
Puget LNG [Member]
Summary of Consolidation Policy
Construction in Progress and O&M Expenses	$ 86.5
Jointly Owned Non-Utility Plant Share	57.00%
Construction in Progress, Gross	$ 86.4

New Accounting Pronouncements R

New Accounting Pronouncements Retirement Benefits ASU (Details) - Pension Plan [Member] $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Other Cost (Credit)	$ 13.8
Subsidiaries [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Other Cost (Credit)	$ 3.5

Accounting for Derivative Ins24

Accounting for Derivative Instruments and Hedging Activities Derivative Activity and Notional Amounts (Details) MWh in Millions, MMBTU in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)MWhMMBTU	Dec. 31, 2016USD ($)MWhMMBTU
Interest Rate Swap [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional Amount | $	$ 0	$ 450
Natural Gas Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary	305.3	336.4
Electric generation fuel [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary	165	186.8
Purchased Electricity [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary | MWh	2.6	3.6
Subsidiaries [Member]
Derivative [Line Items]
Hedging strategy number of years extended	3 years

Accounting for Derivative Ins25

Accounting for Derivative Instruments and Hedging Activities Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Derivative [Line Items]
Unrealized gain on derivative instruments	$ 16,605	$ 54,341
Derivative Liability, Current	49,820	44,310
Assets, Long-term	2,877	8,738
Unrealized loss on derivative instruments	15,578	16,261
Subsidiaries [Member]
Derivative [Line Items]
Unrealized gain on derivative instruments	16,605	54,341
Derivative Liability, Current	49,820	44,170
Assets, Long-term	2,877	8,738
Unrealized loss on derivative instruments	15,578	16,261
Commodity Contract [Member]
Derivative [Line Items]
Assets	19,482	63,079
Derivative Liability	65,398	60,430
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Assets	19,482	63,079
Derivative Liability	65,398	60,571
Not Designated as Hedging Instrument [Member] | Parent Company [Member]
Derivative [Line Items]
Unrealized gain on derivative instruments	16,605	54,341
Derivative Liability, Current	49,820	44,310
Assets, Long-term	2,877	8,738
Unrealized loss on derivative instruments	15,578	16,261
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	0	450,000
Assets	0	0
Derivative Liability	0	141
Not Designated as Hedging Instrument [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Assets	11,656	36,460
Derivative Liability	39,622	41,329
Not Designated as Hedging Instrument [Member] | Natural Gas Portfolio [Member]
Derivative [Line Items]
Assets	7,826	26,619
Derivative Liability	$ 25,776	$ 19,101

Accounting for Derivative Ins26

Accounting for Derivative Instruments and Hedging Activities Net Amount of Derivatives Reported in the Statement of Financial Position (Details) $ in Thousands, MMBTU in Millions		Sep. 30, 2017USD ($)MMBTU	Dec. 31, 2016USD ($)MMBTU
Liabilities:
Derivative Asset, Current		$ 16,605	$ 54,341
Derivative Liability, Current		49,820	44,310
Derivative Asset, Noncurrent		2,877	8,738
Derivative Liability, Noncurrent		15,578	16,261
Commodity Contract [Member]
Assets:
Gross Amount Recognized in the Statement of Financial Position	[1]	19,482	63,079
Gross Amounts Offset in the Statement of Financial Position		0	0
Net of Amounts Presented in the Statement of Financial Position		19,482	63,079
Commodity Contracts		(12,961)	(42,858)
Cash Collateral Received		0	0
Net Amount		6,521	20,221
Liabilities:
Gross Amount Recognized in the Statement of Financial Position	[1]	65,398	60,430
Gross Amounts Offset in the Statement of Financial Position		0	0
Net of Amounts Presented in the Statement of Financial Position		65,398	60,430
Commodity Contracts		(12,961)	(42,858)
Cash Collateral Posted		(739)	0
Net Amount		51,698	17,572
Interest Rate Contract [Member]
Liabilities:
Gross Amount Recognized in the Statement of Financial Position	[1],[2]		141
Gross Amounts Offset in the Statement of Financial Position	[2]		0
Net of Amounts Presented in the Statement of Financial Position			141
Commodity Contracts	[2]		0
Cash Collateral Posted	[2]		0
Net Amount			141
Subsidiaries [Member]
Liabilities:
Derivative Asset, Current		16,605	54,341
Derivative Liability, Current		49,820	44,170
Derivative Asset, Noncurrent		2,877	8,738
Derivative Liability, Noncurrent		15,578	16,261
Not Designated as Hedging Instrument [Member]
Assets:
Net of Amounts Presented in the Statement of Financial Position		19,482	63,079
Liabilities:
Net of Amounts Presented in the Statement of Financial Position		65,398	60,571
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount		0	450,000
Assets:
Net of Amounts Presented in the Statement of Financial Position		0	0
Liabilities:
Net of Amounts Presented in the Statement of Financial Position		0	141
Not Designated as Hedging Instrument [Member] | Electric Portfolio [Member]
Assets:
Net of Amounts Presented in the Statement of Financial Position		11,656	36,460
Liabilities:
Net of Amounts Presented in the Statement of Financial Position		$ 39,622	$ 41,329
Not Designated as Hedging Instrument [Member] | Natural Gas Derivatives [Member]
Liabilities:
Derivative, Nonmonetary Notional Amount | MMBTU		305.3	336.4
Not Designated as Hedging Instrument [Member] | Natural Gas Portfolio [Member]
Assets:
Net of Amounts Presented in the Statement of Financial Position		$ 7,826	$ 26,619
Liabilities:
Net of Amounts Presented in the Statement of Financial Position		25,776	19,101
Not Designated as Hedging Instrument [Member] | Parent Company [Member]
Liabilities:
Derivative Asset, Current		16,605	54,341
Derivative Liability, Current		49,820	44,310
Derivative Asset, Noncurrent		2,877	8,738
Derivative Liability, Noncurrent		$ 15,578	$ 16,261
[1]	1 All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off.
[2]	2 Interest rate swap contracts are only held at Puget Energy

Accounting for Derivative Ins27

Accounting for Derivative Instruments and Hedging Activities Recognized in Statement of Income (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	$ (23)	$ 6,327	$ 23,098	$ (57,218)
Subsidiaries [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(23)	6,327	23,098	(57,218)
Not Designated as Hedging Instrument [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	11,086	10,589	52,277	(3,937)
Not Designated as Hedging Instrument [Member] | Other Income (Deductions) [Member] | Interest Expense [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	0	(563)	(28)	651
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	0	349	0	349
Not Designated as Hedging Instrument [Member] | Electric generation fuel [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	(903)	8,873	20,979	(41,957)
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Electric generation fuel [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	6,753	3,194	14,773	36,204
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Purchased Electricity [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	4,356	1,282	14,434	16,077
Not Designated as Hedging Instrument [Member] | Electric [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	$ 880	$ (2,546)	$ 2,119	$ (15,261)

Accounting for Derivative Ins28

Accounting for Derivative Instruments and Hedging Activities Contractual Contingent Liability (Details) - USD ($) $ in Thousands		Sep. 30, 2017	Dec. 31, 2016
External Credit Rating, Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage		98.50%
External Credit Rating, Non Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage		1.50%
Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	[1]	$ 34,066	$ 12,828
Posted Collateral		1,384	0
Additional Collateral, Aggregate Fair Value		6,113	4,894
Credit Rating [Member]
Derivative [Line Items]
Posted Collateral	[2]	1,400
Credit Rating [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	[1],[2]	6,113	4,894
Posted Collateral	[2]	0	0
Additional Collateral, Aggregate Fair Value	[2]	6,113	4,894
Credit Rating [Member] | Natural Gas Portfolio [Member]
Derivative [Line Items]
Posted Collateral	[2]	1,000
Requested Credit for Adequate Assurance [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	[1]	27,214	7,427
Posted Collateral		0	0
Additional Collateral, Aggregate Fair Value		0	0
Forward Value of Contract [Member] | Electric Portfolio [Member]
Derivative [Line Items]
Fair Value Liability	[1],[3]	739	507
Posted Collateral	[3]	1,384	0
Additional Collateral, Aggregate Fair Value	[3]	$ 0	$ 0
[1]	1 Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable.
[2]	2 Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral.
[3]	3 Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.

Fair Value Measurements Debt at

Fair Value Measurements Debt at at Carrying and Fair Value (Details) - USD ($) $ in Thousands		Sep. 30, 2017	Dec. 31, 2016
Liabilities:
Total long-term debt		$ 5,235,000	$ 5,351,661
Subsidiaries [Member]
Liabilities:
Total long-term debt		3,549,229	3,744,886
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member]
Liabilities:
Total long-term debt		3,749,229	3,747,298
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes		250,000	250,000
Long-term debt (fixed-rate), net of discount	[1]	3,499,229	3,497,298
Debt issuance costs	[1]	25,300	27,200
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member]
Liabilities:
Total long-term debt		4,711,358	4,571,044
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes		246,232	210,261
Long-term debt (fixed-rate), net of discount	[1]	$ 4,465,126	$ 4,360,783
[1]	1 The carrying value includes debt issuances costs of $29.1 million and $33.0 million for September 30, 2017 and December 31, 2016, respectively, which are not included in fair value.

Fair Value Measurements Assets

Fair Value Measurements Assets and Liabilities (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		$ 2,099	$ (3,546)	$ 1,597	$ (9,728)
Included in earnings	[1]	2,458	574	3,503	3,228
Included in regulatory assets/liabilities		2,133	(212)	5,715	2,869
Settlements		(3,084)	177	(10,227)	(2,192)
Transferred into Level 3		(1,668)	(727)	(30)	(2,807)
Transferred out of Level 3		1,726	2,201	3,106	7,097
Balance at end of period		3,664	(1,533)	3,664	(1,533)
Long-term Debt, Excluding Current Maturities		5,235,000		5,235,000		$ 5,351,661
Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability						141
Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts		900	900	1,900	4,000
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		643	(3,062)	972	(7,345)
Included in earnings	[1]	2,458	574	3,503	3,228
Included in regulatory assets/liabilities		0	0	0	0
Settlements		(1,783)	93	(5,622)	(461)
Transferred into Level 3		(1,668)	(727)	523	(2,807)
Transferred out of Level 3		1,760	2,532	2,034	6,795
Balance at end of period		1,410	(590)	1,410	(590)
Natural Gas Portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		1,456	(484)	625	(2,383)
Included in earnings	[1]	0	0	0	0
Included in regulatory assets/liabilities		2,133	(212)	5,715	2,869
Settlements		(1,301)	84	(4,605)	(1,731)
Transferred into Level 3		0	0	(553)	0
Transferred out of Level 3		(34)	(331)	1,072	302
Balance at end of period		2,254	$ (943)	2,254	$ (943)
Subsidiaries [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Long-term Debt, Excluding Current Maturities		3,549,229		3,549,229		3,744,886
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		19,482		19,482		63,079
Derivative Liability		65,398		65,398		60,571
Fair Value, Measurements, Recurring [Member] | Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		11,656		11,656		36,460
Derivative Liability		39,622		39,622		41,329
Fair Value, Measurements, Recurring [Member] | Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		7,826		7,826		26,619
Derivative Liability		25,776		25,776		19,101
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		10,900		10,900		53,982
Derivative Liability		60,480		60,480		53,071
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		7,106		7,106		30,666
Derivative Liability		36,482		36,482		36,507
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		3,794		3,794		23,316
Derivative Liability		23,998		23,998		16,423
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		8,582		8,582		9,097
Derivative Liability		4,918		4,918		7,500
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Electric Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		4,550		4,550		5,794	[2]
Derivative Liability		3,140		3,140		4,822	[2]
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Natural Gas Portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		4,032		4,032		3,303	[2]
Derivative Liability		1,778		1,778		2,678	[2]
Fair Value, Measurements, Recurring [Member] | Parent Company [Member] | Level 2 [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability		0		0		141
Fair Value, Measurements, Recurring [Member] | Parent Company [Member] | Level 3 [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability		0		0		0
Fair Value, Measurements, Recurring [Member] | Parent Company [Member] | Total [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability		0		0		141
Carrying Value [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments, Fair Value Disclosure		49,400		49,400		49,100
Income Approach Valuation Technique [Member] | Carrying Value [Member] | Parent Company [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Long-term Debt, Excluding Current Maturities		5,435,000		5,435,000		5,354,073
Income Approach Valuation Technique [Member] | Carrying Value [Member] | Parent Company [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unamortized Debt Issuance Expense	[3]	29,100		29,100		33,000
Subordinated Debt Obligations, Fair Value Disclosure		250,000		250,000		250,000
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[3]	5,101,936		5,101,936		5,091,593
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure	[3]	83,064		83,064		12,480
Income Approach Valuation Technique [Member] | Carrying Value [Member] | Subsidiaries [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Long-term Debt, Excluding Current Maturities		3,749,229		3,749,229		3,747,298
Income Approach Valuation Technique [Member] | Carrying Value [Member] | Subsidiaries [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unamortized Debt Issuance Expense	[3]	25,300		25,300		27,200
Subordinated Debt Obligations, Fair Value Disclosure		250,000		250,000		250,000
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[3]	3,499,229		3,499,229		3,497,298
Income Approach Valuation Technique [Member] | Total [Member] | Parent Company [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Long-term Debt, Excluding Current Maturities		6,768,709		6,768,709		6,560,028
Income Approach Valuation Technique [Member] | Total [Member] | Parent Company [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Subordinated Debt Obligations, Fair Value Disclosure		246,232		246,232		210,261
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[3]	6,439,413		6,439,413		6,337,287
Long-term Debt, Variable Rate, Net of Discount, Fair Value Disclosure	[3]	83,064		83,064		12,480
Income Approach Valuation Technique [Member] | Total [Member] | Subsidiaries [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Long-term Debt, Excluding Current Maturities		4,711,358		4,711,358		4,571,044
Income Approach Valuation Technique [Member] | Total [Member] | Subsidiaries [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Subordinated Debt Obligations, Fair Value Disclosure		246,232		246,232		210,261
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[3]	$ 4,465,126		$ 4,465,126		$ 4,360,783
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjgwMjdlNTZkN2JjYTRmMDU5ODRiMjQxOTIzZDdkZDE4fFRleHRTZWxlY3Rpb246NDVEMjNBM0EyQ0VGRERCMEY1MjJGMTQ1MzRBMjI4ODQM}
[2]	1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.
[3]	1 The carrying value includes debt issuances costs of $29.1 million and $33.0 million for September 30, 2017 and December 31, 2016, respectively, which are not included in fair value.

Fair Value Measurements Valuati

Fair Value Measurements Valuation Techniques for Measurement with Unobservable Inputs (Details)	3 Months Ended			9 Months Ended		12 Months Ended
	Sep. 30, 2017USD ($)$ / MWh	Mar. 31, 2017USD ($)$ / MWh	Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)$ / MMBTU$ / MWh	Sep. 30, 2016USD ($)	Dec. 31, 2035	Dec. 31, 2034	Dec. 31, 2033	Dec. 31, 2032	Dec. 31, 2031	Dec. 31, 2030	Dec. 31, 2029	Dec. 31, 2028	Dec. 31, 2027	Dec. 31, 2026	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2016USD ($)$ / MMBTU$ / MWh
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value measurement, sensitivity analysis, hypothetical increase or decrease of market prices, result on fair value	10.00%			10.00%																				10.00%
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value	$ 1,700,000			$ 1,700,000																				$ 200,000
Finite-Lived Intangible Assets, Net
Impairment of Intangible Assets (Excluding Goodwill)		$ 80,300,000		81,345,000
Fair Value Inputs, Comparability Adjustments	3.50%	14.10%
Carrying Value [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure
Fair Value, Measurements, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	19,482,000			19,482,000																				63,079,000
Derivative Liability	65,398,000			65,398,000																				$ 60,571,000
Electric Portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	900,000		$ 900,000	$ 1,900,000	$ 4,000,000
Electric Portfolio [Member] | Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh				8.54																				11.86
Electric Portfolio [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh				28.98																				33.52
Electric Portfolio [Member] | Discounted cash flow [Member] | Weighted Average [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh				17.99																				27.61
Electric Portfolio [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	11,656,000			$ 11,656,000																				$ 36,460,000
Derivative Liability	39,622,000			$ 39,622,000																				$ 41,329,000
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MMBtu) | $ / MMBTU				0.38																				2
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MMBtu) | $ / MMBTU				3.09																				3.24
Natural Gas Portfolio [Member] | Discounted cash flow [Member] | Weighted Average [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MMBtu) | $ / MMBTU				2.75																				2.42
Natural Gas Portfolio [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	7,826,000			$ 7,826,000																				$ 26,619,000
Derivative Liability	25,776,000			25,776,000																				19,101,000
Commodity Contract [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	19,482,000			19,482,000																				63,079,000
Derivative Liability	65,398,000			65,398,000																				$ 60,430,000
Wells Project [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-Lived Intangible Assets, Net	10,621,000	$ 14,879,000		10,621,000
Impairment of Intangible Assets (Excluding Goodwill)	1,012,000	1,812,000
Wells Project [Member] | Carrying Value [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure	$ 9,609,000	$ 13,067,000		$ 9,609,000
Wells Project [Member] | Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh	14.06	8.76
Fair Value Inputs, Power Contract Costs	$ 4,126	$ 3,965
Wells Project [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh	26.86	26.70
Fair Value Inputs, Power Contract Costs	$ 4,126	$ 4,223
Wells Project [Member] | Discounted cash flow [Member] | Weighted Average [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh	22.24	20.86
Fair Value Inputs, Power Contract Costs	$ 4,126	$ 4,051
Rocky Reach Project [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-Lived Intangible Assets, Net		235,331,000
Impairment of Intangible Assets (Excluding Goodwill)		75,513,000
Rocky Reach Project [Member] | Carrying Value [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure		$ 159,818,000
Rocky Reach Project [Member] | Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh		8.53
Fair Value Inputs, Power Contract Costs		$ 5,827
Rocky Reach Project [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh		48.21
Fair Value Inputs, Power Contract Costs		$ 6,780
Rocky Reach Project [Member] | Discounted cash flow [Member] | Weighted Average [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh		27.69
Fair Value Inputs, Power Contract Costs		$ 6,150
Priest Rapids Development [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-Lived Intangible Assets, Net		5,665,000
Impairment of Intangible Assets (Excluding Goodwill)		3,008,000
Priest Rapids Development [Member] | Carrying Value [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure		$ 2,657,000
Priest Rapids Development [Member] | Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh		13.70
Fair Value Inputs, Power Contract Costs		$ 620
Priest Rapids Development [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh		29.38
Fair Value Inputs, Power Contract Costs		$ 4,022
Priest Rapids Development [Member] | Discounted cash flow [Member] | Weighted Average [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh		23.14
Fair Value Inputs, Power Contract Costs		$ 2,306
Scenario, Forecast [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Comparability Adjustments						24.40%	24.40%	24.40%	24.40%	24.40%	24.40%	24.40%	24.40%	24.40%	24.40%	24.40%	24.40%	24.40%	14.10%	14.10%	14.10%	14.10%	14.10%

Retirement Benefits Net Periodi

Retirement Benefits Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Qualified Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer			$ 18,000
Components of net periodic benefit cost:
Service cost			15,060		$ 18,913
Interest cost			21,279		28,689
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 500		1,400
Components of net periodic benefit cost:
Service cost			685		1,085
Interest cost			1,714		2,325
Other Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer	100		200
Components of net periodic benefit cost:
Service cost			54		93
Interest cost			375		$ 533
Parent Company [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	5,020	$ 4,976	15,060	$ 14,185
Interest cost	7,093	7,064	21,279	21,516
Expected return on plan assets	(11,945)	(11,589)	(35,837)	(34,964)
Amortization of prior service cost	(495)	(495)	(1,485)	(1,485)
Amortization of net loss (gain)	0	0	0	0
Net periodic benefit cost	(327)	(44)	(983)	(748)
Parent Company [Member] | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	228	271	685	814
Interest cost	571	581	1,714	1,744
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	11	11	33	32
Amortization of net loss (gain)	269	228	807	683
Net periodic benefit cost	1,079	1,091	3,239	3,273
Parent Company [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	18	21	54	70
Interest cost	125	88	375	399
Expected return on plan assets	(115)	(112)	(346)	(334)
Amortization of prior service cost	0	0	0	0
Amortization of net loss (gain)	(101)	(233)	(302)	(289)
Net periodic benefit cost	(73)	(236)	(219)	(154)
Subsidiaries [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	5,020	4,976	15,060	14,185
Interest cost	7,093	7,064	21,279	21,516
Expected return on plan assets	(11,965)	(11,638)	(35,896)	(35,110)
Amortization of prior service cost	(393)	(393)	(1,180)	(1,180)
Amortization of net loss (gain)	3,262	3,963	9,786	11,443
Net periodic benefit cost	3,017	3,972	9,049	10,854
Subsidiaries [Member] | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	228	271	685	814
Interest cost	571	581	1,714	1,744
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	11	11	33	33
Amortization of net loss (gain)	392	333	1,175	997
Net periodic benefit cost	1,202	1,196	3,607	3,588
Subsidiaries [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	18	21	54	70
Interest cost	125	88	375	399
Expected return on plan assets	(115)	(112)	(346)	(334)
Amortization of prior service cost	0	0	0	0
Amortization of net loss (gain)	(160)	(295)	(480)	(474)
Net periodic benefit cost	$ (132)	$ (298)	$ (397)	$ (339)

Retirement Benefits Change in N

Retirement Benefits Change in Net Benefit Obligation (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Qualified Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	$ 652,607	$ 643,088
Service cost	15,060	18,913
Interest cost	21,279	28,689
Actuarial loss/(gain)	(253)	1,545
Benefits paid	(31,344)	(38,730)
Medicare part D subsidiary received	0	0
Administrative Expense	0	(898)
Benefit obligation at end of period	657,349	652,607
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	51,734	51,279
Service cost	685	1,085
Interest cost	1,714	2,325
Actuarial loss/(gain)	0	106
Benefits paid	(1,428)	(3,061)
Medicare part D subsidiary received	0	0
Administrative Expense	0	0
Benefit obligation at end of period	52,705	51,734
Other Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	11,194	13,946
Service cost	54	93
Interest cost	375	533
Actuarial loss/(gain)	373	(2,262)
Benefits paid	(857)	(1,264)
Medicare part D subsidiary received	100	148
Administrative Expense	0	0
Benefit obligation at end of period	$ 11,239	$ 11,194

Retirement Benefits Activity (D

Retirement Benefits Activity (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2017	Dec. 31, 2017
Qualified Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer		$ 18
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 0.5	1.4
Other Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 0.1	$ 0.2
Subsidiaries [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Additional Contribution of Base Pay, Percentage		4.00%
Defined Contribution Plan, Employer Matching Contribution, Percent		1.00%
Scenario, Forecast [Member] | Qualified Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			$ 18
Scenario, Forecast [Member] | Supplemental Employee Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			1.9
Scenario, Forecast [Member] | Other Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			$ 0.3

Regulation and Rates (Details)

Regulation and Rates (Details) - Subsidiaries [Member] $ in Millions

Jan. 01, 2018USD ($)

Nov. 01, 2017USD ($)

Oct. 01, 2017USD ($)

Sep. 15, 2017USD ($)

May 01, 2017USD ($)

Apr. 03, 2017USD ($)

Jan. 13, 2017USD ($)

Jan. 01, 2017USD ($)

Dec. 01, 2016USD ($)

Nov. 01, 2016USD ($)

May 01, 2016USD ($)

Jan. 01, 2016USD ($)

Oct. 01, 2015USD ($)

Jun. 25, 2013

Sep. 30, 2017USD ($)

Sep. 30, 2016USD ($)

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Jun. 30, 2013

Regulatory Assets [Line Items]

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

7.77%

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

48.00%

Public Utilities, Rate Case, Approved Effective Return on Equity

9.80%

Electric [Member]

Regulatory Assets [Line Items]

Storm Damage Costs Incurred During Period

$ 21.1

$ 15.6

Storm Damage Costs Deferred During Period

12.4

6.5

Public Utilities, Rate Case, Deferred Storm Costs Threshold

8

Residential Exchange Benefit [Member] | Electric [Member]

Regulatory Assets [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

2.40%

Public Utilities, Approved credit to be passed back to eligible customers

$ (76.4)

Federal Incentive Tracker Tariff [Member] | Electric [Member]

Regulatory Assets [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

0.30%

(0.20%)

Public Utilities, Approved credit to be passed back to eligible customers

$ (51.7)

$ (57.3)

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

Regulatory Assets [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

(1.70%)

Public Utilities, Approved Rate Increase (Decrease), Amount

$ (37.3)

Energy Conservation Costs [Member] | Natural Gas [Member]

Regulatory Assets [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

(0.10%)

0.30%

Public Utilities, Approved Rate Increase (Decrease), Amount

$ (1)

$ 2.9

Energy Conservation Costs [Member] | Electric [Member]

Regulatory Assets [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

0.70%

(0.50%)

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 16.5

$ (11.7)

Property tax tracker [Member] [Domain] | Natural Gas [Member]

Regulatory Assets [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

(0.10%)

0.40%

Public Utilities, Approved Rate Increase (Decrease), Amount

$ (1.1)

$ 3.5

Property tax tracker [Member] [Domain] | Electric [Member]

Regulatory Assets [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

(0.04%)

0.30%

Public Utilities, Approved Rate Increase (Decrease), Amount

$ (0.9)

$ 5.7

Cost recovery mechanism [Member] | Natural Gas [Member]

Regulatory Assets [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

0.60%

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 5.6

Purchased Gas Adjustment (PGA) [Member] | Natural Gas [Member]

Regulatory Assets [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

(0.40%)

Public Utilities, Approved Rate Increase (Decrease), Amount

$ (4.1)

Decoupling Mechanism [Member]

Regulatory Assets [Line Items]

Public Utilities, Percentage of Earning to Be Shared Between the Company and Customers

50.00%

Decoupling Mechanism [Member] | Natural Gas [Member]

Regulatory Assets [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

2.40%

2.80%

2.20%

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 22.4

$ 25.4

$ 2.2

$ 5.5

Decoupling Mechanism [Member] | Electric [Member]

Regulatory Assets [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

2.00%

1.00%

3.00%

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 41.9

$ 20.8

11.9

11.9

Decoupling Mechanism [Member] | Maximum [Member]

Regulatory Assets [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

3.00%

Decoupling Mechanism [Member] | Deferred Revenue [Domain] | Natural Gas [Member]

Regulatory Assets [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 47.4

$ 28.7

General Rate Case [Member]

Regulatory Assets [Line Items]

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

7.60%

7.74%

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

6.55%

6.69%

Public Utilities, Requested Equity Capital Structure, Percentage

48.50%

48.50%

Public Utilities, Requested Return on Equity, Percentage

9.50%

9.80%

Number of new mechanisms

2

Number of parties that agreed to settle

10

Number of parties total

11

Number of contested issues not settled

4

General Rate Case [Member] | Natural Gas [Member]

Regulatory Assets [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 22.3

Public Utilities, Requested Rate Increase (Decrease), Percentage

2.40%

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

$ 35.5

$ 29.3

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

3.80%

3.20%

General Rate Case [Member] | Electric [Member]

Regulatory Assets [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 86.3

Public Utilities, Requested Rate Increase (Decrease), Percentage

4.10%

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

$ 20.2

$ 67.9

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

0.90%

3.20%

Customers share [Member] | Range 2 [Member] | Electric [Member]

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

50.00%

Customers share [Member] | Range 3 [Member] | Electric [Member]

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

90.00%

Customers share [Member] | Range 4 [Member] | Electric [Member]

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

95.00%

Customers share [Member] | Range 1 [Member] | Electric [Member]

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

0.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

50.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

10.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

5.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

100.00%

Under Recovery [Member] | Customers share [Member] | Electric [Member]

Regulatory Assets [Line Items]

Annual Power Cost Variability, Amount

0

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

50.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

90.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

0.00%

Under Recovery [Member] | Company's share [Member] | Electric [Member]

Regulatory Assets [Line Items]

Annual Power Cost Variability, Amount

(8.9)

$ (1.4)

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

50.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

10.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

100.00%

Over Recovery [Member] | Customers share [Member] | Electric [Member]

Regulatory Assets [Line Items]

Annual Power Cost Variability, Amount

$ 0

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

65.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

90.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

0.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

35.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

10.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

100.00%

Deferral Trigger [Member] [Member] | Minimum [Member] | Electric [Member]

Regulatory Assets [Line Items]

Annual Power Cost Variability, Amount

$ 30

Deferral Trigger [Member] [Member] | Maximum [Member] | Electric [Member]

Regulatory Assets [Line Items]

Annual Power Cost Variability, Amount

$ 20

Scenario, Forecast [Member] | Federal Incentive Tracker Tariff [Member] | Electric [Member]

Regulatory Assets [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Percentage

0.20%

Public Utilities, Requested credit to be passed back to eligible customers

$ (48.2)

Subsequent Event [Member] | Residential Exchange Benefit [Member] | Electric [Member]

Regulatory Assets [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

(0.60%)

Public Utilities, Approved credit to be passed back to eligible customers

$ (80.8)

Subsequent Event [Member] | Cost recovery mechanism [Member] | Natural Gas [Member]

Regulatory Assets [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

0.50%

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 4.9

Subsequent Event [Member] | Purchased Gas Adjustment (PGA) [Member] | Natural Gas [Member]

Regulatory Assets [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Percentage

(3.30%)

Public Utilities, Approved Rate Increase (Decrease), Amount

$ (30.8)

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2017USD ($)	Dec. 31, 2016USD ($)	Sep. 06, 2016
Commitments and Contingencies			2
Subsidiaries [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Opening balance	$ 200,345
New asset retirement obligation recognized in the period1	2,881
Liability adjustments	(1,035)
Revisions in estimated cash flows	(18,462)
Accretion expense	4,126
Closing balance	187,855
Subsidiaries [Member] | Colstrip Units 1 and 2 [Member]
Decommissioning Liability, Noncurrent	5,500	$ 45,700
Subsidiaries [Member] | Colstrip Units 3 and 4 [Member]
Decommissioning Liability, Noncurrent	12,700	$ 37,000
Subsidiaries [Member] | Tacoma LNG [Member]
Decommissioning Liability, Noncurrent	1,500
Puget LNG [Member] | Tacoma LNG [Member]
Decommissioning Liability, Noncurrent	$ 1,400

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	Jun. 19, 2017USD ($)	Mar. 28, 2017USD ($)	Jun. 30, 2017USD ($)	Sep. 30, 2017USD ($)	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Sep. 20, 2016USD ($)
Loss Contingencies [Line Items]
Regulatory Assets				$ 175	$ 176.8
Estimated Litigation Liability							$ 3.2
Loss Contingency, Allegations	$ 1.3	$ 1.3
Loss Contingency, Accrual, Current						$ 3.2
Loss Contingency, Damages Awarded, Value	$ 2.8	$ 2.8
Loss Contingency Accrual, Payments			$ 1.5
Contractual Obligation				729.5
Pending Litigation [Member]
Loss Contingencies [Line Items]
Litigation claims accrual				$ 0.6	$ 0.7
Colstrip Units 3 and 4 [Member]
Loss Contingencies [Line Items]
Ownership interest (percent)				25.00%
Colstrip Units 1 and 2 [Member]
Loss Contingencies [Line Items]
Ownership interest (percent)				50.00%
Jointly Owned Utility Plant				2