Puget Energy (PSD) 10-Q 4 Aug 16 2016 Q2 Quarterly report Financial data

Document And Entity Information

Document And Entity Information	6 Months Ended
	Jun. 30, 2016shares
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	2,016
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016
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	2,016
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Operating revenue:
Electric	$ 497,152	$ 469,616	$ 1,127,343	$ 1,043,243
Natural gas	163,443	184,941	486,851	533,803
Other	7,574	3,784	16,672	8,129
Total operating revenue	668,169	658,341	1,630,866	1,585,175
Energy costs:
Purchased electricity	118,551	104,471	261,448	257,951
Electric generation fuel	40,930	55,652	95,123	103,668
Residential exchange	(13,376)	(29,054)	(33,516)	(72,768)
Purchased natural gas	48,273	79,465	171,376	235,898
Unrealized (gain) loss on derivative instruments, net	(46,724)	(8,232)	(63,546)	(11,928)
Utility operations and maintenance	138,018	131,972	284,008	269,147
Non-utility expense and other	5,179	2,323	10,814	5,535
Depreciation and amortization	111,273	100,412	218,787	206,589
Conservation amortization	22,540	24,561	55,751	54,165
Taxes other than income taxes	67,871	69,999	170,163	164,912
Total operating expenses	492,535	531,569	1,170,408	1,213,169
Operating income	175,634	126,772	460,458	372,006
Other income (deductions):
Other income	7,078	5,255	13,053	10,039
Other expense	(2,122)	(1,815)	(3,462)	(3,222)
Non-hedged interest rate swap (expense) income	(359)	(1,440)	(1,213)	(3,415)
Interest charges:
AFUDC	2,603	1,729	4,962	3,160
Interest expense	(88,676)	(89,822)	(177,489)	(178,731)
Income (loss) before income taxes	94,158	40,679	296,309	199,837
Income tax (benefit) expense	29,605	15,063	90,570	58,545
Net income (loss)	64,553	25,616	205,739	141,292
Subsidiaries [Member]
Operating revenue:
Electric	497,152	469,616	1,127,343	1,043,243
Natural gas	163,443	184,941	486,851	533,803
Other	7,574	3,784	16,672	8,138
Total operating revenue	668,169	658,341	1,630,866	1,585,184
Energy costs:
Purchased electricity	118,551	104,471	261,448	257,951
Electric generation fuel	40,930	55,652	95,123	103,668
Residential exchange	(13,376)	(29,054)	(33,516)	(72,768)
Purchased natural gas	48,273	79,465	171,376	235,898
Unrealized (gain) loss on derivative instruments, net	(46,724)	(8,232)	(63,546)	(11,383)
Utility operations and maintenance	138,018	131,972	284,008	269,147
Non-utility expense and other	8,822	6,342	17,856	13,349
Depreciation and amortization	111,273	100,412	218,787	206,589
Conservation amortization	22,540	24,561	55,751	54,165
Taxes other than income taxes	67,871	69,999	170,163	164,912
Total operating expenses	496,178	535,588	1,177,450	1,221,528
Operating income	171,991	122,753	453,416	363,656
Other income (deductions):
Other income	7,077	5,255	13,052	10,039
Other expense	(2,122)	(1,815)	(3,462)	(3,222)
Interest charges:
AFUDC	2,603	1,729	4,962	3,160
Interest expense	(60,647)	(62,620)	(121,422)	(125,816)
Interest expense on parent note	0	(31)	0	(63)
Income (loss) before income taxes	118,902	65,271	346,546	247,754
Income tax (benefit) expense	38,002	22,572	109,140	75,955
Net income (loss)	$ 80,900	$ 42,699	$ 237,406	$ 171,799

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Parent [Line Items]
Net income (loss)	$ 64,553	$ 25,616	$ 205,739	$ 141,292
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	(185)	1,277	(371)	1,856
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	0	0	0	333
Other comprehensive income (loss)	(185)	1,277	(371)	2,189
Comprehensive income (loss)	64,368	26,893	205,368	143,481
Subsidiaries [Member]
Parent [Line Items]
Net income (loss)	80,900	42,699	237,406	171,799
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	2,340	4,094	4,680	7,475
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	0	0	0	686
Amortization Of Financing Cash Flow Hedge Contracts To Earnings During Period Net Of Tax	79	79	158	158
Other comprehensive income (loss)	2,419	4,173	4,838	8,319
Comprehensive income (loss)	$ 83,319	$ 46,872	$ 242,244	$ 180,118

CONSOLIDATED STATEMENTS OF COM4

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Net unrealized gain (loss) from pension and postretirement plans, net of tax	$ 100	$ 688	$ 200	$ 1,000
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax	0	0	0	179
Subsidiaries [Member]
Net unrealized gain (loss) from pension and postretirement plans, net of tax	1,260	2,204	2,520	4,025
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax	0	0	0	369
Amortization of treasury interest rate swaps to earnings, net of tax	$ 43	$ 43	$ 86	$ 86

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Utility plant (at original cost, including construction work in progress):
Electric plant	$ 7,596,857	$ 7,432,490
Natural gas plant	2,943,093	2,850,290
Common plant	536,960	508,750
Less: Accumulated depreciation and amortization	(2,040,106)	(1,878,868)
Net utility plant	9,036,804	8,912,662
Other property and investments:
Goodwill	1,656,513	1,656,513
Other property and investments	84,563	86,731
Total other property and investments	1,741,076	1,743,244
Current assets:
Cash and cash equivalents	19,019	42,494
Restricted cash	10,128	7,949
Accounts receivable, net of allowance for doubtful accounts	230,829	324,391
Unbilled revenue	126,241	217,274
Materials and supplies, at average cost	96,838	78,244
Fuel and gas inventory, at average cost	53,179	58,658
Unrealized gain on derivative instruments	36,255	24,418
Prepaid expense and other	19,566	17,120
Power contract acquisition adjustment gain	34,716	37,031
Total current assets	626,771	807,579
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	71,743	73,231
Power Cost Adjustment Mechanism Asset, Noncurrent	4,813	4,749
Regulatory assets related to power contracts	24,041	26,223
Other regulatory assets	880,378	894,071
Unrealized gain on derivative instruments	8,782	5,225
Power contract acquisition adjustment gain	268,589	288,757
Other	62,536	58,513
Total other long-term and regulatory assets	1,320,882	1,350,769
Total assets	12,725,533	12,814,254
Capitalization:
Common stock	0	0
Additional paid-in capital	3,308,957	3,308,957
Earnings reinvested in the business	381,005	249,534
Accumulated Other Comprehensive Income (Loss), Net of Tax	(27,637)	(27,266)
Total common shareholder's equity	3,662,325	3,531,225
Long-term debt:
First mortgage bonds and senior notes	3,364,412	3,364,412
Pollution control bonds	161,860	161,860
Junior subordinated notes	250,000	250,000
Long-term debt	1,800,000	1,800,000
Debt discount	(241,694)	(248,754)
Total long-term debt	5,334,578	5,327,518
Total capitalization	8,996,903	8,858,743
Current liabilities:
Accounts payable	190,784	259,353
Short-term debt	36,000	159,004
Purchased gas adjustment liability	11,562	12,589
Accrued expenses:
Taxes	101,624	114,854
Salaries and wages	35,722	38,457
Interest	73,443	73,378
Unrealized loss on derivative instruments	67,417	136,173
Power contract acquisition adjustment loss	3,304	3,611
Other	68,405	53,867
Total current liabilities	588,261	851,286
Long-term and regulatory liabilities:
Deferred income taxes	1,524,285	1,435,955
Unrealized loss on derivative instruments	19,859	48,073
Regulatory liabilities	616,231	652,441
Regulatory liabilities related to power contracts	303,304	325,788
Power contract acquisition adjustment loss	20,737	22,613
Other Deferred Credits, Noncurrent	655,953	619,355
Total long-term and regulatory liabilities	3,140,369	3,104,225
Commitments and contingencies
Total capitalization and liabilities	12,725,533	12,814,254
Subsidiaries [Member]
Utility plant (at original cost, including construction work in progress):
Electric plant	9,757,074	9,601,091
Natural gas plant	3,533,415	3,444,744
Common plant	576,867	548,657
Less: Accumulated depreciation and amortization	(4,830,552)	(4,681,830)
Net utility plant	9,036,804	8,912,662
Other property and investments:
Other property and investments	80,901	83,069
Total other property and investments	80,901	83,069
Current assets:
Cash and cash equivalents	18,578	41,856
Restricted cash	10,128	7,949
Accounts receivable, net of allowance for doubtful accounts	230,691	324,358
Unbilled revenue	126,241	217,274
Materials and supplies, at average cost	96,838	78,244
Fuel and gas inventory, at average cost	52,350	57,324
Unrealized gain on derivative instruments	36,255	24,418
Prepaid expense and other	19,566	17,119
Total current assets	590,647	768,542
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	71,213	72,694
Power Cost Adjustment Mechanism Asset, Noncurrent	4,813	4,749
Other regulatory assets	880,375	894,059
Unrealized gain on derivative instruments	8,782	5,225
Other	62,536	58,513
Total other long-term and regulatory assets	1,027,719	1,035,240
Total assets	10,736,071	10,799,513
Capitalization:
Common stock	859	859
Additional paid-in capital	3,275,105	3,275,105
Earnings reinvested in the business	345,310	236,578
Accumulated Other Comprehensive Income (Loss), Net of Tax	(144,712)	(149,550)
Total common shareholder's equity	3,476,562	3,362,992
Long-term debt:
First mortgage bonds and senior notes	3,364,412	3,364,412
Pollution control bonds	161,860	161,860
Junior subordinated notes	250,000	250,000
Debt discount	(30,437)	(31,910)
Total long-term debt	3,745,835	3,744,362
Total capitalization	7,222,397	7,107,354
Current liabilities:
Accounts payable	190,784	259,353
Short-term debt	36,000	159,004
Purchased gas adjustment liability	11,562	12,589
Accrued expenses:
Taxes	101,624	114,854
Salaries and wages	35,722	38,457
Interest	47,899	47,772
Unrealized loss on derivative instruments	64,236	131,420
Other	68,405	53,868
Total current liabilities	556,232	817,317
Long-term and regulatory liabilities:
Deferred income taxes	1,666,329	1,556,616
Unrealized loss on derivative instruments	19,859	47,776
Regulatory liabilities	615,399	651,094
Other Deferred Credits, Noncurrent	655,855	619,356
Total long-term and regulatory liabilities	2,957,442	2,874,842
Commitments and contingencies
Total capitalization and liabilities	$ 10,736,071	$ 10,799,513

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
ASSETS
Construction work in progress	$ 460,797	$ 408,795
Current assets:
Allowance for doubtful accounts	$ 9,644	$ 9,756
Common shareholder’s equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,000	1,000
Common stock, shares outstanding (in shares)	200	200
Subsidiaries [Member]
ASSETS
Construction work in progress	$ 460,797	$ 408,795
Current assets:
Allowance for doubtful accounts	$ 9,644	$ 9,756
Common shareholder’s equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	150,000,000	150,000,000
Common stock, shares outstanding (in shares)	85,903,791	85,903,791

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Operating activities:
Net income (loss)	$ 205,739	$ 141,292
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	218,787	206,589
Conservation amortization	55,751	54,165
Deferred income taxes and tax credits, net	90,018	58,580
Net unrealized (gain) loss on derivative instruments	(65,414)	(12,707)
Derivative Contracts Classified As Financing Due To Merger Impact On Operations Portion	0	8,045
AFUDC – equity	(7,048)	(3,836)
Funding of pension liability	(9,000)	(9,000)
Regulatory Assets	(120,615)	(104,474)
Other long-term assets	14,519	24,828
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	184,595	98,582
Materials and supplies	(18,594)	(305)
Fuel and gas inventory	4,974	10,734
Prepayments and other	(2,738)	(3,276)
Purchased gas adjustment	(1,027)	35,963
Accounts payable	(64,132)	(80,932)
Taxes payable	(13,230)	(8,551)
Accrued expenses and other	4,650	(26,590)
Net cash provided by operating activities	477,235	389,107
Investing activities:
Construction expenditures - excluding equity AFUDC	(303,834)	(265,500)
Restricted cash	(2,179)	24,899
Other	(4,851)	2,674
Net cash used in investing activities	(310,864)	(237,927)
Financing activities:
Change in short-term debt and leases, net	(123,004)	(85,000)
Dividends paid	(74,268)	(192,500)
Proceeds from Issuance of Long-term Debt	0	825,000
Repayments of Long-term Debt	0	(699,000)
Derivative contracts classified as financing activities due to merger	0	(8,045)
Issuance cost of bonds and other	7,426	(14,627)
Net cash provided by (used in) financing activities	(189,846)	(174,172)
Net increase (decrease) in cash and cash equivalents	(23,475)	(22,992)
Cash and cash equivalents at beginning of period	42,494	37,527
Cash and cash equivalents at end of period	19,019	14,535
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	164,130	173,941
Cash payments (refunds) for income taxes	0	0
Accounts payable for capital expenditures eliminated from cash flows	47,151	51,239
Subsidiaries [Member]
Operating activities:
Net income (loss)	237,406	171,799
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	218,787	206,589
Conservation amortization	55,751	54,165
Deferred income taxes and tax credits, net	108,589	75,953
Net unrealized (gain) loss on derivative instruments	(63,546)	(11,383)
AFUDC – equity	(7,048)	(3,836)
Funding of pension liability	(9,000)	(9,000)
Regulatory Assets	(120,615)	(104,474)
Other long-term assets	16,820	27,037
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	184,700	98,282
Materials and supplies	(18,594)	(305)
Fuel and gas inventory	4,974	10,734
Prepayments and other	(2,738)	(3,274)
Purchased gas adjustment	(1,027)	35,963
Accounts payable	(64,132)	(80,926)
Taxes payable	(13,230)	(8,551)
Accrued expenses and other	1,567	(31,142)
Net cash provided by operating activities	528,664	427,631
Investing activities:
Construction expenditures - excluding equity AFUDC	(303,834)	(265,500)
Restricted cash	(2,179)	24,899
Other	(1,707)	4,692
Net cash used in investing activities	(307,720)	(235,909)
Financing activities:
Change in short-term debt and leases, net	(123,004)	(85,000)
Dividends paid	(128,674)	(144,387)
Loan from (payment to) parent	0	(28,933)
Investment from parent	0	28,900
Proceeds from Issuance of Long-term Debt	0	425,000
Repayments of Long-term Debt	0	(400,000)
Issuance cost of bonds and other	7,456	(11,448)
Net cash provided by (used in) financing activities	(244,222)	(215,868)
Net increase (decrease) in cash and cash equivalents	(23,278)	(24,146)
Cash and cash equivalents at beginning of period	41,856	37,466
Cash and cash equivalents at end of period	18,578	13,320
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	113,438	128,267
Cash payments (refunds) for income taxes	0	0
Accounts payable for capital expenditures eliminated from cash flows	$ 47,151	$ 51,239

Summary of Consolidation Policy

Summary of Consolidation Policy	6 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
Basis of Presentation and Significant Accounting Policies	Basis of Presentation Puget Energy is an energy services holding company that owns 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 is an indirect wholly-owned subsidiary of Puget Holdings LLC (Puget Holdings). The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiary, PSE. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary, Puget Western, Inc. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of intercompany transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any purchase accounting adjustments. The consolidated financial statements contained in this Form 10-Q are unaudited. In the respective opinions of the management of Puget Energy and PSE, all adjustments necessary for a fair statement of the results for the interim periods have been reflected and were of a normal recurring nature. These consolidated financial statements should be read in conjunction with the audited financial statements (and the Combined Notes thereto) included in the combined Puget Energy and PSE Annual Report on Form 10-K for the year ended December 31, 2015 . 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. PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $48.8 million and $123.4 million for the three and six months ended June 30, 2016 , respectively, and $50.3 million and $119.9 million for the three and six months ended June 30, 2015, respectively. The Company reports the collection of such taxes on a gross basis in operating revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income. Change in Accounting Principle On January 1, 2016, the Company changed its method of presenting unamortized debt issuance costs in the balance sheet. The new method of presenting debt issuance costs was adopted to comply with ASU 2015-03, "Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" . ASU 2015-03 requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with the presentation of a debt discount. The prior year comparative balance sheet has been adjusted to apply the new method retrospectively. Due to the change in accounting principle, the December 31, 2015 financial statement line item “Other long-term assets” decreased and “Debt discount, issuance costs and other” increased $38.4 million and $30.0 million at Puget Energy and PSE, respectively.

New Accounting Pronouncements

New Accounting Pronouncements	6 Months Ended
	Jun. 30, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements and Changes in Accounting Principles	New Accounting Pronouncements Revenue Recognition In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, " Revenue from Contracts with Customers (Topic 606) ", which outlines a single comprehensive model for use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The ASU is based on the principle that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to fulfill a contract. In August 2015, the FASB issued ASU 2015-14, " Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date" , deferring the effective date for ASU 2014-09 to fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. In addition to the FASB's deferral decision, the FASB provided reporting entities with an option to adopt ASU 2014-09 for the fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, the original effective date. In March 2016, the FASB issued ASU 2016-08, " Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)" . The amendments in ASU 2016-08 are intended to improve the operability and understanding of the implementation guidance on principal versus agent considerations. Topic 606 requires an entity to determine whether the nature of its promise is to provide a good or service to the customer (i.e., the entity is a principal) or to arrange for the good or service to be provided to the customer by another party (i.e., the entity is an agent). The effective date and transition requirements for ASU 2016-08 are the same as the effective date and transition requirements of ASU 2014-09. In April 2016, the FASB issued ASU 2016-10, " Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing". The amendments in ASU 2016-10 are intended to clarify the aspects of identifying performance obligations and the licensing implementation guidance, while retaining the related principles for those areas. The effective date and transition requirements for ASU 2016-10 are the same as the effective date and transition requirements of ASU 2014-09. In May 2016, the FASB issued ASU 2016-12, "Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients". The amendments in ASU 2016-12 are intended to clarify the objective of collectability criterion, presentation of sales taxes and other similar taxes collected from customers, specify the measurement date for noncash consideration, provide practical expedient for contract modifications at transition, define completed contracts at transition and clarify that an entity that retrospectively applies the guidance in Topic 606 to each prior reporting period is not required to disclose the effect of the accounting change for the period of adoption. The effective date and transition requirements for ASU 2016-12 are the same as the effective date and transition requirements of ASU 2014-09. The Company plans to adopt ASU 2014-09 according to the deferred effective date. Reporting entities also have the option of using either a full retrospective or a modified retrospective approach for the adoption of the new standard. The Company initiated a steering committee and project team to evaluate the impact of this standard, update any policies and procedures that may be affected and implement the new revenue recognition guidance. At this time, the Company is still evaluating the impact this standard will have on its consolidated financial statements. Lease Accounting In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" . ASU 2016-02 requires lessees to recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Under the new guidance, lessor accounting is largely unchanged. This amendment is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Earlier adoption is permitted for all entities upon issuance. Reporting entities must apply a modified retrospective approach for the adoption of the new standard. The Company plans to adopt ASU 2016-02 during the first quarter of fiscal year 2019. At this time, the Company is still evaluating the impact this standard will have on its consolidated financial statements. Derivatives and Hedging In March 2016, the FASB issued ASU 2016-06, "Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments" . Topic 815 requires that embedded derivatives be separated from the host contract and accounted for separately as derivatives if certain criteria are met, including the “clearly and closely related” criterion. ASU 2016-06 clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. An entity performing the assessment under the amendment is required to assess the embedded call (put) options solely in accordance with the four-step decision sequence. This amendment is effective for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Earlier adoption is permitted for all entities upon issuance. Reporting entities must apply a modified retrospective approach for the adoption of the new standard. The Company plans to adopt ASU 2016-06 during the first quarter of fiscal year 2017, and is in the process of evaluating the potential impacts, if any, of this new guidance on its financial statements.

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	6 Months Ended
	Jun. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Accounting for Derivative Instruments and Hedging Activities	Accounting for Derivative Instruments and Hedging Activities PSE employs various energy portfolio optimization strategies but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the 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 in costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. The forward physical electric agreements are both fixed and variable (at index), while the physical natural gas agreements are variable. To fix the price of wholesale electricity and natural gas, PSE may enter into fixed-for-floating swap (financial) contracts with various counterparties. PSE also utilizes natural gas call and put options as an additional hedging instrument to increase the hedging portfolio's flexibility to react to commodity price fluctuations. 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 June 30, 2016 , Puget Energy had two interest rate swap contracts outstanding which extend to January 2017 . As of the date of this report, these swap instruments are no longer hedging any variable interest rate debt. Management continues to monitor the economics of terminating the swaps, and unless the economics of terminating the swaps become more favorable, management intends to let them mature in January 2017 . PSE did not have any outstanding interest rate swap instruments. The following table presents the volumes, fair values and locations of the Company's derivative instruments recorded on the balance sheets: Puget Energy and Puget Sound Energy June 30, 2016 December 31, 2015 (Dollars in Thousands) Volumes Assets 1 Liabilities 2 Volumes Assets 1 Liabilities 2 Interest rate swap derivatives 3 $450 million $ — $ 3,181 $450 million $ — $ 5,050 Electric portfolio derivatives * 31,657 56,775 * 23,443 112,106 Natural gas derivatives (MMBtus) 4 322.1 million 13,380 27,320 369.5 million 6,200 67,090 Total derivative contracts $ 45,037 $ 87,276 $ 29,643 $ 184,246 Current $ 36,255 $ 67,417 $ 24,418 $ 136,173 Long-term 8,782 19,859 5,225 48,073 Total derivative contracts $ 45,037 $ 87,276 $ 29,643 $ 184,246 _______________ 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. 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 205.0 million One Million British Thermal Units (MMBtu) and purchased electricity of 0.1 million Megawatt Hours (MWhs) at June 30, 2016 , and 202.1 million MMBtus and 0.1 million MWhs at December 31, 2015 . It is the Company's policy to record all derivative transactions on a gross basis at the contract level, without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements, which standardize physical power contracts; International Swaps and Derivatives Association (ISDA) agreements, which standardize financial gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as 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. 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 June 30, 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 $ 45,037 $ — $ 45,037 $ (38,636 ) $ — $ 6,401 Liabilities: Energy derivative contracts 84,095 — 84,095 (38,636 ) (137 ) 45,322 Interest rate swaps 2 3,181 — 3,181 — — 3,181 Puget Energy and Puget Sound Energy December 31, 2015 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 $ 29,643 $ — $ 29,643 $ (23,998 ) $ — $ 5,645 Liabilities: Energy derivative contracts 179,196 — 179,196 (23,998 ) — 155,198 Interest rate swaps 2 5,050 — 5,050 — — 5,050 _______________ 1 All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off. 2 Interest rate swap contracts are only held at Puget Energy. The following tables present the effect and locations of the Company's derivatives recorded on the statements of income: Puget Energy Three Months Ended June 30, Six Months Ended (Dollars in Thousands) Location 2016 2015 2016 2015 Interest rate contracts: Non-hedged interest rate swap (expense) income $ (359 ) $ (1,440 ) $ (1,213 ) $ (3,415 ) Interest expense — 722 — 560 Commodity contracts: Electric derivatives Unrealized gain (loss) on derivative instruments, net 1 46,724 8,232 63,546 11,928 Electric generation fuel (12,327 ) (5,082 ) (33,010 ) (15,744 ) Purchased electricity (3,576 ) (4,261 ) (14,795 ) (26,145 ) Total gain (loss) recognized in income on derivatives $ 30,462 $ (1,829 ) $ 14,528 $ (32,816 ) Puget Sound Energy Three Months Ended June 30, Six Months Ended (Dollars in Thousands) Location 2016 2015 2016 2015 Commodity contracts: Electric derivatives Unrealized gain (loss) on derivative instruments, net 1 $ 46,724 $ 8,232 $ 63,546 $ 11,383 Electric generation fuel (12,327 ) (5,082 ) (33,010 ) (15,744 ) Purchased electricity (3,576 ) (4,261 ) (14,795 ) (26,145 ) Total gain (loss) recognized in income on derivatives $ 30,821 $ (1,111 ) $ 15,741 $ (30,506 ) _______________ 1 Differences between Puget Energy and PSE for the six months ending June 30, 2015 are due to certain derivative contracts recorded at fair value in 2009 and subsequently designated as Normal Purchase Normal Sale (NPNS) or cash flow hedges. These differences occurred through February 2015. The Company is exposed to credit risk primarily through buying and selling electricity and natural gas to serve its customers. Credit risk is the potential loss resulting from a counterparty's non-performance under an agreement. The Company manages credit risk with policies and procedures for, among other things, counterparty credit analysis, exposure measurement, exposure monitoring and exposure mitigation. The Company monitors counterparties that have significant swings in credit default swap rates, have credit rating changes by external rating agencies, have changes in ownership or are experiencing financial distress. Where deemed appropriate, the Company may request collateral or other security from its counterparties to mitigate potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of June 30, 2016 , approximately 92.0% of the Company's energy portfolio exposure, excluding NPNS transactions, is with counterparties that are rated at least investment grade by rating agencies and 8.0% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies. The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors, such as credit default swaps and bond spreads, in the determination of reserves. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels. The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against the unrealized gain (loss) positions. As of June 30, 2016 , the Company was in a net liability position with many 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. As of June 30, 2016 , PSE has posted a $1.0 million letter of credit as a condition of transacting on a physical energy exchange and clearinghouse in Canada. PSE did not trigger any collateral requirements with any of its counterparties during the six months ended June 30, 2016 , nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades. The table below presents the fair value of the overall contractual contingent liability positions for the Company's derivative activity at June 30, 2016 : Puget Energy and Puget Sound Energy (Dollars in Thousands) Fair Value 1 Posted Contingent Contingent Feature Liability Collateral Collateral Credit rating 2 $ (11,748 ) $ — $ 11,748 Requested credit for adequate assurance (15,648 ) — — Forward value of contract 3 (106 ) — — Total $ (27,502 ) $ — $ 11,748 _______________ 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	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements ASC 820 established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy categorizes the inputs into three levels with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority given to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows: Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Equity securities that are also classified as cash equivalents are considered Level 1 if there are unadjusted quoted prices in active markets for identical assets or liabilities. Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options. Level 3 - Pricing inputs include significant inputs that have little or no observability as of the reporting date. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves, contract terms and prices, credit-risk adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs 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. For interest rate swaps, the Company obtains monthly market values from an independent external pricing service using London Interbank Offered Rate (LIBOR) forward rates, which is a significant input. Some of the inputs of the interest rate swap valuations, which are less significant, include the credit standing of the counterparties, assumptions for time value and the impact of the Company's nonperformance risk of its liabilities. The Company classifies cash and cash equivalents, and restricted cash as Level 1 financial instruments due to cash being at stated value, and cash equivalents at quoted market prices. The Company considers its electric, natural gas and interest rate swap contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. 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 following table presents the carrying value for cash, cash equivalents, restricted cash, notes receivable and short-term debt by fair value hierarchy level. The carrying values below are representative of fair values due to the short-term nature of these financial instruments. Carrying / Fair Value Carrying / Fair Value Puget Energy At June 30, 2016 At December 31, 2015 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Cash and cash equivalents $ 19,019 $ — $ 19,019 $ 42,494 $ — $ 42,494 Restricted cash 10,128 — 10,128 7,949 — 7,949 Other investments — 51,874 51,874 — 52,820 52,820 Total assets $ 29,147 $ 51,874 $ 81,021 $ 50,443 $ 52,820 $ 103,263 Liabilities: Short-term debt $ 36,000 $ — $ 36,000 $ 159,004 $ — $ 159,004 Total liabilities $ 36,000 $ — $ 36,000 $ 159,004 $ — $ 159,004 Carrying / Fair Value Carrying / Fair Value Puget Sound Energy At June 30, 2016 At December 31, 2015 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Cash and cash equivalents $ 18,578 $ — $ 18,578 $ 41,856 $ — $ 41,856 Restricted cash 10,128 — 10,128 7,949 — 7,949 Other investments — 51,874 51,874 — 52,820 52,820 Total assets $ 28,706 $ 51,874 $ 80,580 $ 49,805 $ 52,820 $ 102,625 Liabilities: Short-term debt $ 36,000 $ — $ 36,000 $ 159,004 $ — $ 159,004 Total liabilities $ 36,000 $ — $ 36,000 $ 159,004 $ — $ 159,004 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. Carrying values and estimated fair values were as follows: Puget Energy June 30, 2016 December 31, 2015 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 222,780 $ 250,000 $ 211,173 Long-term debt (fixed-rate), net of discount 1 2 5,084,578 6,817,865 5,077,518 6,308,831 Total liabilities $ 5,334,578 $ 7,040,645 $ 5,327,518 $ 6,520,004 Puget Sound Energy June 30, 2016 December 31, 2015 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 222,780 $ 250,000 $ 211,173 Long-term debt (fixed-rate), net of discount 2 2 3,495,835 4,766,386 3,494,362 4,329,444 Total liabilities $ 3,745,835 $ 4,989,166 $ 3,744,362 $ 4,540,617 _______________ 1 The carrying value includes debt issuances costs of $35.6 million , and $38.4 million for June 30, 2016 and December 31, 2015 , respectively, which are not included in fair value. 2 The carrying value includes debt issuances costs of $28.6 million , and $30.0 million for June 30, 2016 and December 31, 2015 , respectively, which are not included in fair value. Assets and Liabilities Measured at Fair Value on a Recurring Basis The following tables present the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis: Fair Value Fair Value Puget Energy At June 30, 2016 At December 31, 2015 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Liabilities: Interest rate derivative instruments $ 3,181 $ — $ 3,181 $ 5,050 $ — $ 5,050 Total liabilities $ 3,181 $ — $ 3,181 $ 5,050 $ — $ 5,050 Puget Energy and Fair Value Fair Value Puget Sound Energy At June 30, 2016 At December 31, 2015 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 24,411 $ 7,246 $ 31,657 $ 10,709 $ 12,734 $ 23,443 Natural gas derivative instruments 10,787 2,593 13,380 4,538 1,662 6,200 Total assets $ 35,198 $ 9,839 $ 45,037 $ 15,247 $ 14,396 $ 29,643 Liabilities: Electric derivative instruments $ 46,467 $ 10,308 $ 56,775 $ 92,027 $ 20,079 $ 112,106 Natural gas derivative instruments 24,243 3,077 27,320 63,045 4,045 67,090 Total liabilities $ 70,710 $ 13,385 $ 84,095 $ 155,072 $ 24,124 $ 179,196 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 June 30, (Dollars in Thousands) 2016 2015 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ 1,602 $ (1,622 ) $ (20 ) $ (16,091 ) $ (1,601 ) $ (17,692 ) Changes during period: Realized and unrealized energy derivatives: Included in earnings 1 (1,954 ) — (1,954 ) (4,064 ) — (4,064 ) Included in regulatory assets / liabilities — 1,562 1,562 — 2,813 2,813 Settlements (494 ) (879 ) (1,373 ) 52 (389 ) (337 ) Transferred into Level 3 — — — — — — Transferred out of Level 3 (2,216 ) 455 (1,761 ) 4,733 — 4,733 Balance at end of period $ (3,062 ) $ (484 ) $ (3,546 ) $ (15,370 ) $ 823 $ (14,547 ) Puget Energy and Puget Sound Energy Six Months Ended (Dollars in Thousands) 2016 2015 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ (7,345 ) $ (2,383 ) $ (9,728 ) $ (12,061 ) $ (2,039 ) $ (14,100 ) Changes during period: Realized and unrealized energy derivatives: Included in earnings 2 2,654 — 2,654 (9,102 ) — (9,102 ) Included in regulatory assets / liabilities — 3,082 3,082 — 2,938 2,938 Settlements (554 ) (1,816 ) (2,370 ) 165 (298 ) (133 ) Transferred into Level 3 (2,080 ) — (2,080 ) (787 ) — (787 ) Transferred out of Level 3 4,263 633 4,896 6,415 222 6,637 Balance at end of period $ (3,062 ) $ (484 ) $ (3,546 ) $ (15,370 ) $ 823 $ (14,547 ) _______________ 1 Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(2.5) million and $(3.8) million for the three months ended June 30, 2016 and 2015 , respectively. 2 Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $3.1 million and $(8.8) million for the six months ended June 30, 2016 and 2015 , 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 table above. The Company did not have any transfers between Level 2 and Level 1 during the reported periods. The Company does periodically transact at locations, or market price points, that are illiquid or for which no prices are available from the independent pricing service. In such circumstances, the Company uses a more liquid price point and performs a 15-month regression against the illiquid locations to serve as a proxy for forward market prices. Such transactions are classified as Level 3. The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs. The only significant unobservable input into the fair value measurement of the Company's Level 3 assets and liabilities is the forward price for electric and natural gas contracts. The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of June 30, 2016 : Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 7,246 $ 10,308 Discounted cash flow Power prices $12.72 per MWh $32.00 per MWh $27.99 per MWh Natural gas $ 2,593 $ 3,077 Discounted cash flow Natural gas prices $1.25 per MMBtu $3.46 per MMBtu $2.53 per MMBtu _______________ 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, 2015 : Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 12,734 $ 20,079 Discounted cash flow Power prices $10.69 per MWh $29.18 per MWh $23.39 per MWh Natural gas $ 1,662 $ 4,045 Discounted cash flow Natural gas prices $1.12 per MMBtu $2.95 per MMBtu $2.25 per MMBtu _______________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently, significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. At June 30, 2016 and December 31, 2015 , a hypothetical 10% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $0.6 million and $1.3 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. At June 30, 2016 , Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets and found no impairment. However, due to decreases in forward power prices of 8.6% at March 31, 2016 and 4.5% at December 31, 2015 , the following impairments were recorded to one of the Company's intangible asset contracts, with corresponding reductions to the regulatory liability as follows: Puget Energy (Dollars in Thousands) Valuation Date Contract Name Carrying Value Fair Value Write Down March 31, 2016 Wells Hydro $ 25,193 $ 19,855 $ 5,338 December 31, 2015 Wells Hydro 32,988 27,628 5,360 The valuations were measured using a discounted cash flow, income-based valuation methodology. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates which are classified as Level 3 within the fair value hierarchy. A less significant input is the discount rate reflective of PSE's cost of capital used in the valuation. Below are significant unobservable inputs used in estimating the impaired long-term power purchase contracts' fair value at March 31, 2016 and December 31, 2015 : Valuation Date Unobservable Input Low High Average March 31, 2016 Power prices $9.46 per MWh $25.96 per MWh $21.38 per MWh Power contract costs (in thousands) $4,100 per qtr $4,659 per qtr $4,452 per qtr December 31, 2015 Power prices $15.16 per MWh $27.25 per MWh $23.23 per MWh Power contract costs (in thousands) $4,100 per qtr $4,659 per qtr $4,417 per qtr

Retirement Benefits

Retirement Benefits	6 Months Ended
	Jun. 30, 2016
Compensation and Retirement Disclosure [Abstract]
Retirement Benefits	Retirement Benefits PSE has a defined benefit pension plan (Qualified Pension Benefits) covering the largest portion of PSE employees. Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates. Starting with January 1, 2014 all newly hired non-represented employees, United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry (UA) employees, and International Brotherhood of Electrical Workers Local Union 77 (IBEW) employees hired on or after December 12, 2014 will receive annual pay credits of 4% each year, which is the Company contribution. Non-represented and IBEW employees can accumulate the Company contribution in the cash balance formula or the 401(k) plan. UA employees will automatically receive the Company contribution in the cash balance formula plan. They will also receive interest credits like other participants in the cash balance pension formula of the pension plan, which are at least 1% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, he or she will have annuity and lump sum options for distribution. Those who select the lump sum option will receive their current cash balance amount. PSE also maintains a non-qualified Supplemental Executive Retirement Plan (SERP) for its key senior management employees. In addition to providing pension benefits, PSE provides legacy group health care and life insurance benefits (Other Benefits) for certain retired employees. These benefits are provided principally through an insurance company. The insurance premiums, paid primarily by retirees, are based on the benefits provided during the prior year. Puget Energy records purchase accounting adjustments associated with the re-measurement of the retirement plans. The following tables summarize the Company’s net periodic benefit cost for the three and six months ended June 30, 2016 and 2015 : Puget Energy Qualified SERP Other Three Months Ended June 30, (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Components of net periodic benefit cost: Service cost $ 4,605 $ 5,172 $ 271 $ 277 $ 24 $ 23 Interest cost 7,226 6,937 582 570 157 150 Expected return on plan assets (11,687 ) (11,117 ) — — (111 ) (133 ) Amortization of prior service cost (495 ) (495 ) 11 11 — — Amortization of net loss (gain) — 962 228 410 (29 ) (51 ) Net periodic benefit cost $ (351 ) $ 1,459 $ 1,092 $ 1,268 $ 41 $ (11 ) Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Six Months Ended (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Components of net periodic benefit cost: Service cost $ 9,209 $ 10,644 $ 542 $ 554 $ 49 $ 56 Interest cost 14,452 14,044 1,163 1,140 313 311 Expected return on plan assets (23,374 ) (22,519 ) — — (222 ) (266 ) Amortization of prior service cost (990 ) (990 ) 22 22 — — Amortization of net loss (gain) — 1,943 456 820 (58 ) (66 ) Net periodic benefit cost $ (703 ) $ 3,122 $ 2,183 $ 2,536 $ 82 $ 35 Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Three Months Ended June 30, (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Components of net periodic benefit cost: Service cost $ 4,605 $ 5,172 $ 271 $ 277 $ 24 $ 23 Interest cost 7,226 6,937 582 570 157 150 Expected return on plan assets (11,736 ) (11,223 ) — — (111 ) (133 ) Amortization of prior service cost (393 ) (393 ) 11 11 — 1 Amortization of net loss (gain) 3,740 5,141 333 530 (90 ) (120 ) Net periodic benefit cost $ 3,442 $ 5,634 $ 1,197 $ 1,388 $ (20 ) $ (79 ) Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Six Months Ended (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Components of net periodic benefit cost: Service cost $ 9,209 $ 10,644 $ 542 $ 554 $ 49 $ 56 Interest cost 14,452 14,044 1,163 1,140 313 311 Expected return on plan assets (23,472 ) (22,731 ) — — (222 ) (266 ) Amortization of prior service cost (786 ) (786 ) 22 22 — 2 Amortization of net loss (gain) 7,480 10,277 666 1,060 (180 ) (203 ) Net periodic benefit cost $ 6,883 $ 11,448 $ 2,393 $ 2,776 $ (40 ) $ (100 ) The following table summarizes the Company’s change in benefit obligation for the periods ended June 30, 2016 and December 31, 2015 : Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Six Months Ended Year Six Months Ended Year Six Months Ended Year (Dollars in Thousands) June 30, December 31, June 30, December 31, June 30, December 31, Change in benefit obligation: Benefit obligation at beginning of period $ 643,088 $ 690,194 $ 51,279 $ 55,855 $ 13,946 $ 15,688 Service cost 9,209 21,287 542 1,108 49 112 Interest cost 14,452 28,088 1,163 2,281 313 621 Actuarial loss (gain) — (55,665 ) — (4,430 ) — (1,416 ) Benefits paid (20,650 ) (39,963 ) (2,092 ) (3,535 ) (664 ) (1,354 ) Medicare part D subsidy received — — — — 5 295 Administrative Expense — (853 ) — — — — Benefit obligation at end of period $ 646,099 $ 643,088 $ 50,892 $ 51,279 $ 13,649 $ 13,946 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, 2016 are expected to be at least $24.0 million , $2.5 million and $0.5 million , respectively. During the three months ended June 30, 2016 , the Company contributed $4.5 million , $1.0 million and $0.2 million to fund the qualified pension plan, SERP and other postretirement plan, respectively. During the six months ended June 30, 2016 , the Company contributed $9.0 million , $2.1 million , and $0.4 million to the fund the qualified pension plan, SERP and other postretirement plan, respectively.

Regulation and Rates

Regulation and Rates	6 Months Ended
	Jun. 30, 2016
Regulation and Rates [Abstract]
Regulation and Rates	Regulation and Rates Decoupling Filings While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms are expected to mitigate the impact of weather on operating revenue and net income. The Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs from residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues will be recovered on a per customer basis regardless of actual consumption levels. The energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. Following each calendar year, PSE will recover or refund the difference between allowed decoupling revenue and the corresponding actual revenue to affected customers over a 12-month period beginning the following May. The decoupling mechanism will end on December 31, 2017 unless the continuation of the mechanism is approved in PSE's next General Rate Case (GRC) filing, which PSE is required to submit by January 17, 2017 at the latest. On April 28, 2016, the Washington Commission approved PSE's request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2016. The overall changes represent a rate increase for electric customers of $20.8 million , or 1.0% , annually, and a rate increase for natural gas customers of $25.4 million , or 2.8% , annually. In addition, PSE exceeded the earnings test threshold for both its electric and natural gas business in 2015. As a result, PSE recorded a reduction in electric decoupling deferral and revenue of $11.9 million and a reduction in natural gas decoupling deferral and revenue of $5.5 million . This was reflected as a reduction to the electric and natural gas rate increases noted above. As noted earlier, the Company is also limited to a 3.0% annual decoupling related cap on increases in total revenue. This limitation was triggered for the natural gas residential rate class. The resulting amount of deferral that was not included in the 2016 rate increase is $28.7 million for natural gas revenue that was accrued through December 31, 2015. This amount may be included in customer rates beginning in May 2017, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases. On April 22, 2015, the Washington Commission approved PSE's request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2015. As part of this filing, PSE also requested to change the methodology of how decoupling deferrals are calculated going forward and adjust deferrals calculated in 2014. The change was done to ensure that the amortization of prior years’ accumulated decoupling deferrals were not included in the calculation of the current year decoupling deferrals. The effect of the methodology change was a reduction of approximately $12.0 million previously recognized revenue from May through December of 2014. The overall changes represent a rate increase for electric customers of $53.8 million , or 2.6% , annually, and a rate increase for natural gas customers of $22.0 million , or 2.1% , annually, effective May 1, 2015. In addition, PSE exceeded the earnings test threshold for its natural gas business in 2014. As a result, PSE recorded a reduction in natural gas decoupling deferral and revenue of $1.3 million . This was reflected as a reduction to the natural gas rate increases noted above. As noted earlier, the Company is also limited to a 3.0% annual decoupling related cap on increases in total revenue. This limitation was triggered for certain rate classes. The resulting amount of deferral that was not included in the 2015 rate increase is $1.9 million for electric revenue and $8.2 million for natural gas revenue that was accrued through December 31, 2014. These amounts may be included in customer rates beginning in May 2016, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases. General Rate Case Filing Postponed to 2017 On March 17, 2016, the Washington Commission approved a joint petition postponing the filing of PSE’s GRC until no later than January 17, 2017. All parties to PSE's 2011 GRC, including Public Counsel, Washington Commission Staff, Industrial Customers of Northwest Utilities (ICNU) and Northwest Industrial Gas Users (NWIGU), either supported the petition or did not oppose it. As part of the petition, PSE agreed to update power costs on December 1, 2016 in conjunction with the Centralia PPA compliance filing and to include in the GRC a filing regarding its interest in Colstrip Units 1 and 2. Monthly allowed revenue per customer values, which include an automatic annual increase, will continue through December 2017 until new rates go into effect from PSE's 2017 GRC. 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 can be recorded as a regulatory asset for qualifying storm damage costs that meet the Institute of Electrical and Electronics Engineers (IEEE) threshold criteria for a major event. For the six months ended June 30, 2016 and 2015 , PSE incurred $15.6 million and $2.5 million , respectively, in storm-related electric transmission and distribution system restoration costs, of which $6.5 million was recorded as a regulatory asset in 2016 and $0.2 million in 2015 . 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 was implemented in 2013 and removed property taxes from general rates and included those costs as a component rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The tracker will be adjusted each year in May 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 impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2016 0.3% $5.7 May 1, 2015 0.4 8.4 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. The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2016 (0.5)% $(11.7) May 1, 2015 0.2 4.2 Federal Incentive Tracker Tariff The Federal Incentive Tracker Tariff passes through to customers the benefits associated with realized treasury grants and production tax credits (PTCs). 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 Federal Incentive Tracker Tariff revenue requirement approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Total annual amount to be passed back to eligible customers (Dollars in Millions) January 1, 2016 (0.2)% $(57.3) January 1, 2015 (0.2) (55.2) Gas Regulation and Rates Gas Conservation Rider The 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. The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2016 0.3% $2.9 May 1, 2015 0.2 2.3 Cost Recovery Mechanism The purpose of the Cost Recovery Mechanism (CRM) is to recover capital costs related to 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 impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) November 1, 2015 0.5% $5.3 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 was implemented in 2013 and removed property taxes from general rates and included those costs as a component rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The tracker will be adjusted each year in May 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 impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2016 0.4% $3.5 June 1, 2015 (0.2) (2.3) 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 liability, 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 PGA rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) November 1, 2015 (17.4)% $(185.9)

Asset Retirement Obligation

Asset Retirement Obligation	6 Months Ended
	Jun. 30, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation Disclosure	Asset Retirement Obligation The Company has recorded liabilities for steam, combustion turbine, combined cycle, and wind generation sites, distribution and transmission poles, gas mains, and leased facilities where disposal is governed by ASC 410 “Asset Retirement and Environmental Obligations (ARO)”. On April 17, 2015, the U.S. Environmental Protection Agency (EPA) published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCR) under the Resource Conservation and Recovery Act, Subtitle D. The CCR 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 by establishing technical requirements for CCR landfills and surface impoundments. The rule also sets out recordkeeping and reporting requirements including requirements to post specific information to a publicly-accessible website. The CCR rule requires significant changes to the Company’s Colstrip, Montana coal-fired steam electric generation facility (Colstrip) operations and those changes were reviewed by the Company and the plant operator in the second and third quarter of 2015. PSE had previously recognized a legal obligation under the EPA rules to dispose of coal ash material at Colstrip, in 2003. Due to the CCR rule, additional disposal costs were added to the ARO. The actual ARO costs related to the CCR rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs. We will continue to gather additional data and coordinate with the plant operator to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, the Company will update the ARO obligation for these changes, which could be material. During the first quarter 2016, the Company updated its estimated decommissioning costs and timing of its ARO for Lower Snake River and Hopkins Ridge wind generation sites and increased the undiscounted ARO liability by $19.7 million . The following table describes the changes to the Company’s ARO for the six months ended June 30, 2016 : Puget Sound Energy (Dollars in Thousands) Changes in ARO Balance at December 31, 2015 $ 85,028 New asset retirement obligation recognized in the period — Liability adjustments (411 ) Revisions in estimated cash flows 16,854 Accretion expense 1,240 Balance at June 30, 2016 $ 102,711

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Legal Matters and Contingencies	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. Based on a second amended complaint filed in August 2014, the plaintiffs' lawsuit alleged violations of permitting requirements under the New Source Review program of the Clean Air Act and the Montana State Implementation Plan arising from seven projects undertaken at Colstrip during the time period from 2001 to 2012. On July 12, 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station. As part of the settlement, which has been filed with the court for its approval, PSE has agreed, along with Talen Energy, to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana by no later than July 1, 2022. Colstrip Units 3 and 4, which are newer and more efficient, are not affected by the shutdown, and allegations in the lawsuit against Colstrip Units 3 and 4 were dismissed as part of the settlement. PSE is not able to determine the decommissioning costs of Colstrip Units 1 and 2 at this time; however, any associated decommissioning and historical costs are expected to be fully recovered through rates. Other Proceedings The Company is also involved in litigation relating to claims arising out of its operations in the normal course of business. The Company has recorded reserves of $0.5 million and $0.3 million relating to these claims as of June 30, 2016 and December 31, 2015 , respectively. There have been no material changes to the contractual obligations and consolidated commercial commitments set forth in Part II, Item 7 in the Company's Annual Report on Form 10-K for the year ended December 31, 2015 .

Other

Other	6 Months Ended
	Jun. 30, 2016
Other [Abstract]
Other Material Items [Text Block]	Other Related Party Transactions Scott Armstrong serves on the Board of Directors of the Company, and is the president and Chief Executive Officer of Group Health Cooperative (Group Health). Group Health provides coverage to over 600,000 residents in Washington and Northern Idaho. Certain employees of PSE elect Group Health as their medical provider and as a result, PSE paid Group Health a total of $ 10.7 million and $ 20.3 million for medical coverage for the six months ended June 30, 2016 , and the year ended December 31, 2015 , respectively.

Summary of Consolidation Poli17

Summary of Consolidation Policy (Policies)	6 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
Significant Accounting Policies	Summary of Consolidation Policy Basis of Presentation Puget Energy is an energy services holding company that owns 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 is an indirect wholly-owned subsidiary of Puget Holdings LLC (Puget Holdings). The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiary, PSE. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary, Puget Western, Inc. Puget Energy and PSE are collectively referred to herein as “the Company”. The consolidated financial statements are presented after elimination of intercompany transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any purchase accounting adjustments. The consolidated financial statements contained in this Form 10-Q are unaudited. In the respective opinions of the management of Puget Energy and PSE, all adjustments necessary for a fair statement of the results for the interim periods have been reflected and were of a normal recurring nature. These consolidated financial statements should be read in conjunction with the audited financial statements (and the Combined Notes thereto) included in the combined Puget Energy and PSE Annual Report on Form 10-K for the year ended December 31, 2015 . 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. PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $48.8 million and $123.4 million for the three and six months ended June 30, 2016 , respectively, and $50.3 million and $119.9 million for the three and six months ended June 30, 2015, respectively. The Company reports the collection of such taxes on a gross basis in operating revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income. Change in Accounting Principle On January 1, 2016, the Company changed its method of presenting unamortized debt issuance costs in the balance sheet. The new method of presenting debt issuance costs was adopted to comply with ASU 2015-03, "Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" . ASU 2015-03 requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with the presentation of a debt discount. The prior year comparative balance sheet has been adjusted to apply the new method retrospectively. Due to the change in accounting principle, the December 31, 2015 financial statement line item “Other long-term assets” decreased and “Debt discount, issuance costs and other” increased $38.4 million and $30.0 million at Puget Energy and PSE, respectively.

Accounting for Derivative Ins18

Accounting for Derivative Instruments and Hedging Activities (Tables)	6 Months Ended
	Jun. 30, 2016
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 June 30, 2016 December 31, 2015 (Dollars in Thousands) Volumes Assets 1 Liabilities 2 Volumes Assets 1 Liabilities 2 Interest rate swap derivatives 3 $450 million $ — $ 3,181 $450 million $ — $ 5,050 Electric portfolio derivatives * 31,657 56,775 * 23,443 112,106 Natural gas derivatives (MMBtus) 4 322.1 million 13,380 27,320 369.5 million 6,200 67,090 Total derivative contracts $ 45,037 $ 87,276 $ 29,643 $ 184,246 Current $ 36,255 $ 67,417 $ 24,418 $ 136,173 Long-term 8,782 19,859 5,225 48,073 Total derivative contracts $ 45,037 $ 87,276 $ 29,643 $ 184,246 _______________ 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. 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 205.0 million One Million British Thermal Units (MMBtu) and purchased electricity of 0.1 million Megawatt Hours (MWhs) at June 30, 2016 , and 202.1 million MMBtus and 0.1 million MWhs at December 31, 2015 .
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 June 30, 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 $ 45,037 $ — $ 45,037 $ (38,636 ) $ — $ 6,401 Liabilities: Energy derivative contracts 84,095 — 84,095 (38,636 ) (137 ) 45,322 Interest rate swaps 2 3,181 — 3,181 — — 3,181 Puget Energy and Puget Sound Energy December 31, 2015 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 $ 29,643 $ — $ 29,643 $ (23,998 ) $ — $ 5,645 Liabilities: Energy derivative contracts 179,196 — 179,196 (23,998 ) — 155,198 Interest rate swaps 2 5,050 — 5,050 — — 5,050 _______________ 1 All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off. 2 Interest rate swap contracts are only held at Puget Energy.
Schedule of 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 June 30, 2016 : Puget Energy and Puget Sound Energy (Dollars in Thousands) Fair Value 1 Posted Contingent Contingent Feature Liability Collateral Collateral Credit rating 2 $ (11,748 ) $ — $ 11,748 Requested credit for adequate assurance (15,648 ) — — Forward value of contract 3 (106 ) — — Total $ (27,502 ) $ — $ 11,748 _______________ 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 tables present the effect and locations of the Company's derivatives recorded on the statements of income: Puget Energy Three Months Ended June 30, Six Months Ended (Dollars in Thousands) Location 2016 2015 2016 2015 Interest rate contracts: Non-hedged interest rate swap (expense) income $ (359 ) $ (1,440 ) $ (1,213 ) $ (3,415 ) Interest expense — 722 — 560 Commodity contracts: Electric derivatives Unrealized gain (loss) on derivative instruments, net 1 46,724 8,232 63,546 11,928 Electric generation fuel (12,327 ) (5,082 ) (33,010 ) (15,744 ) Purchased electricity (3,576 ) (4,261 ) (14,795 ) (26,145 ) Total gain (loss) recognized in income on derivatives $ 30,462 $ (1,829 ) $ 14,528 $ (32,816 )
Subsidiaries [Member]
Derivative [Line Items]
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance	Puget Sound Energy Three Months Ended June 30, Six Months Ended (Dollars in Thousands) Location 2016 2015 2016 2015 Commodity contracts: Electric derivatives Unrealized gain (loss) on derivative instruments, net 1 $ 46,724 $ 8,232 $ 63,546 $ 11,383 Electric generation fuel (12,327 ) (5,082 ) (33,010 ) (15,744 ) Purchased electricity (3,576 ) (4,261 ) (14,795 ) (26,145 ) Total gain (loss) recognized in income on derivatives $ 30,821 $ (1,111 ) $ 15,741 $ (30,506 ) _______________ 1 Differences between Puget Energy and PSE for the six months ending June 30, 2015 are due to certain derivative contracts recorded at fair value in 2009 and subsequently designated as Normal Purchase Normal Sale (NPNS) or cash flow hedges. These differences occurred through February 2015.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Schedule of Impaired Intangible Assets [Table Text Block]	However, due to decreases in forward power prices of 8.6% at March 31, 2016 and 4.5% at December 31, 2015 , the following impairments were recorded to one of the Company's intangible asset contracts, with corresponding reductions to the regulatory liability as follows: Puget Energy (Dollars in Thousands) Valuation Date Contract Name Carrying Value Fair Value Write Down March 31, 2016 Wells Hydro $ 25,193 $ 19,855 $ 5,338 December 31, 2015 Wells Hydro 32,988 27,628 5,360
Fair Value, by Balance Sheet Grouping	The following table presents the carrying value for cash, cash equivalents, restricted cash, notes receivable and short-term debt by fair value hierarchy level. The carrying values below are representative of fair values due to the short-term nature of these financial instruments. Carrying / Fair Value Carrying / Fair Value Puget Energy At June 30, 2016 At December 31, 2015 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Cash and cash equivalents $ 19,019 $ — $ 19,019 $ 42,494 $ — $ 42,494 Restricted cash 10,128 — 10,128 7,949 — 7,949 Other investments — 51,874 51,874 — 52,820 52,820 Total assets $ 29,147 $ 51,874 $ 81,021 $ 50,443 $ 52,820 $ 103,263 Liabilities: Short-term debt $ 36,000 $ — $ 36,000 $ 159,004 $ — $ 159,004 Total liabilities $ 36,000 $ — $ 36,000 $ 159,004 $ — $ 159,004 Carrying / Fair Value Carrying / Fair Value Puget Sound Energy At June 30, 2016 At December 31, 2015 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Cash and cash equivalents $ 18,578 $ — $ 18,578 $ 41,856 $ — $ 41,856 Restricted cash 10,128 — 10,128 7,949 — 7,949 Other investments — 51,874 51,874 — 52,820 52,820 Total assets $ 28,706 $ 51,874 $ 80,580 $ 49,805 $ 52,820 $ 102,625 Liabilities: Short-term debt $ 36,000 $ — $ 36,000 $ 159,004 $ — $ 159,004 Total liabilities $ 36,000 $ — $ 36,000 $ 159,004 $ — $ 159,004
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. Carrying values and estimated fair values were as follows: Puget Energy June 30, 2016 December 31, 2015 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 222,780 $ 250,000 $ 211,173 Long-term debt (fixed-rate), net of discount 1 2 5,084,578 6,817,865 5,077,518 6,308,831 Total liabilities $ 5,334,578 $ 7,040,645 $ 5,327,518 $ 6,520,004 Puget Sound Energy June 30, 2016 December 31, 2015 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 222,780 $ 250,000 $ 211,173 Long-term debt (fixed-rate), net of discount 2 2 3,495,835 4,766,386 3,494,362 4,329,444 Total liabilities $ 3,745,835 $ 4,989,166 $ 3,744,362 $ 4,540,617 _______________ 1 The carrying value includes debt issuances costs of $35.6 million , and $38.4 million for June 30, 2016 and December 31, 2015 , respectively, which are not included in fair value. 2 The carrying value includes debt issuances costs of $28.6 million , and $30.0 million for June 30, 2016 and December 31, 2015 , respectively, which are not included in fair value.
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation	The following table presents the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy and Puget Sound Energy Three Months Ended June 30, (Dollars in Thousands) 2016 2015 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ 1,602 $ (1,622 ) $ (20 ) $ (16,091 ) $ (1,601 ) $ (17,692 ) Changes during period: Realized and unrealized energy derivatives: Included in earnings 1 (1,954 ) — (1,954 ) (4,064 ) — (4,064 ) Included in regulatory assets / liabilities — 1,562 1,562 — 2,813 2,813 Settlements (494 ) (879 ) (1,373 ) 52 (389 ) (337 ) Transferred into Level 3 — — — — — — Transferred out of Level 3 (2,216 ) 455 (1,761 ) 4,733 — 4,733 Balance at end of period $ (3,062 ) $ (484 ) $ (3,546 ) $ (15,370 ) $ 823 $ (14,547 ) Puget Energy and Puget Sound Energy Six Months Ended (Dollars in Thousands) 2016 2015 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ (7,345 ) $ (2,383 ) $ (9,728 ) $ (12,061 ) $ (2,039 ) $ (14,100 ) Changes during period: Realized and unrealized energy derivatives: Included in earnings 2 2,654 — 2,654 (9,102 ) — (9,102 ) Included in regulatory assets / liabilities — 3,082 3,082 — 2,938 2,938 Settlements (554 ) (1,816 ) (2,370 ) 165 (298 ) (133 ) Transferred into Level 3 (2,080 ) — (2,080 ) (787 ) — (787 ) Transferred out of Level 3 4,263 633 4,896 6,415 222 6,637 Balance at end of period $ (3,062 ) $ (484 ) $ (3,546 ) $ (15,370 ) $ 823 $ (14,547 ) _______________ 1 Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(2.5) million and $(3.8) million for the three months ended June 30, 2016 and 2015 , respectively. 2 Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $3.1 million and $(8.8) million for the six months ended June 30, 2016 and 2015 , respectively.
Fair Value Inputs, Assets and Liabilities, Quantitative Information	Below are significant unobservable inputs used in estimating the impaired long-term power purchase contracts' fair value at March 31, 2016 and December 31, 2015 : Valuation Date Unobservable Input Low High Average March 31, 2016 Power prices $9.46 per MWh $25.96 per MWh $21.38 per MWh Power contract costs (in thousands) $4,100 per qtr $4,659 per qtr $4,452 per qtr December 31, 2015 Power prices $15.16 per MWh $27.25 per MWh $23.23 per MWh Power contract costs (in thousands) $4,100 per qtr $4,659 per qtr $4,417 per qtr The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of June 30, 2016 : Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 7,246 $ 10,308 Discounted cash flow Power prices $12.72 per MWh $32.00 per MWh $27.99 per MWh Natural gas $ 2,593 $ 3,077 Discounted cash flow Natural gas prices $1.25 per MMBtu $3.46 per MMBtu $2.53 per MMBtu _______________ 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, 2015 : Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 12,734 $ 20,079 Discounted cash flow Power prices $10.69 per MWh $29.18 per MWh $23.39 per MWh Natural gas $ 1,662 $ 4,045 Discounted cash flow Natural gas prices $1.12 per MMBtu $2.95 per MMBtu $2.25 per MMBtu _______________ 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.
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 tables present the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis: Fair Value Fair Value Puget Energy At June 30, 2016 At December 31, 2015 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Liabilities: Interest rate derivative instruments $ 3,181 $ — $ 3,181 $ 5,050 $ — $ 5,050 Total liabilities $ 3,181 $ — $ 3,181 $ 5,050 $ — $ 5,050
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 June 30, 2016 At December 31, 2015 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 24,411 $ 7,246 $ 31,657 $ 10,709 $ 12,734 $ 23,443 Natural gas derivative instruments 10,787 2,593 13,380 4,538 1,662 6,200 Total assets $ 35,198 $ 9,839 $ 45,037 $ 15,247 $ 14,396 $ 29,643 Liabilities: Electric derivative instruments $ 46,467 $ 10,308 $ 56,775 $ 92,027 $ 20,079 $ 112,106 Natural gas derivative instruments 24,243 3,077 27,320 63,045 4,045 67,090 Total liabilities $ 70,710 $ 13,385 $ 84,095 $ 155,072 $ 24,124 $ 179,196

Retirement Benefits (Tables)

Retirement Benefits (Tables)	6 Months Ended
	Jun. 30, 2016
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 June 30, 2016 and December 31, 2015 : Puget Energy and Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Six Months Ended Year Six Months Ended Year Six Months Ended Year (Dollars in Thousands) June 30, December 31, June 30, December 31, June 30, December 31, Change in benefit obligation: Benefit obligation at beginning of period $ 643,088 $ 690,194 $ 51,279 $ 55,855 $ 13,946 $ 15,688 Service cost 9,209 21,287 542 1,108 49 112 Interest cost 14,452 28,088 1,163 2,281 313 621 Actuarial loss (gain) — (55,665 ) — (4,430 ) — (1,416 ) Benefits paid (20,650 ) (39,963 ) (2,092 ) (3,535 ) (664 ) (1,354 ) Medicare part D subsidy received — — — — 5 295 Administrative Expense — (853 ) — — — — Benefit obligation at end of period $ 646,099 $ 643,088 $ 50,892 $ 51,279 $ 13,649 $ 13,946
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 six months ended June 30, 2016 and 2015 : Puget Energy Qualified SERP Other Three Months Ended June 30, (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Components of net periodic benefit cost: Service cost $ 4,605 $ 5,172 $ 271 $ 277 $ 24 $ 23 Interest cost 7,226 6,937 582 570 157 150 Expected return on plan assets (11,687 ) (11,117 ) — — (111 ) (133 ) Amortization of prior service cost (495 ) (495 ) 11 11 — — Amortization of net loss (gain) — 962 228 410 (29 ) (51 ) Net periodic benefit cost $ (351 ) $ 1,459 $ 1,092 $ 1,268 $ 41 $ (11 ) Puget Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Six Months Ended (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Components of net periodic benefit cost: Service cost $ 9,209 $ 10,644 $ 542 $ 554 $ 49 $ 56 Interest cost 14,452 14,044 1,163 1,140 313 311 Expected return on plan assets (23,374 ) (22,519 ) — — (222 ) (266 ) Amortization of prior service cost (990 ) (990 ) 22 22 — — Amortization of net loss (gain) — 1,943 456 820 (58 ) (66 ) Net periodic benefit cost $ (703 ) $ 3,122 $ 2,183 $ 2,536 $ 82 $ 35
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 June 30, (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Components of net periodic benefit cost: Service cost $ 4,605 $ 5,172 $ 271 $ 277 $ 24 $ 23 Interest cost 7,226 6,937 582 570 157 150 Expected return on plan assets (11,736 ) (11,223 ) — — (111 ) (133 ) Amortization of prior service cost (393 ) (393 ) 11 11 — 1 Amortization of net loss (gain) 3,740 5,141 333 530 (90 ) (120 ) Net periodic benefit cost $ 3,442 $ 5,634 $ 1,197 $ 1,388 $ (20 ) $ (79 ) Puget Sound Energy Qualified Pension Benefits SERP Pension Benefits Other Benefits Six Months Ended (Dollars in Thousands) 2016 2015 2016 2015 2016 2015 Components of net periodic benefit cost: Service cost $ 9,209 $ 10,644 $ 542 $ 554 $ 49 $ 56 Interest cost 14,452 14,044 1,163 1,140 313 311 Expected return on plan assets (23,472 ) (22,731 ) — — (222 ) (266 ) Amortization of prior service cost (786 ) (786 ) 22 22 — 2 Amortization of net loss (gain) 7,480 10,277 666 1,060 (180 ) (203 ) Net periodic benefit cost $ 6,883 $ 11,448 $ 2,393 $ 2,776 $ (40 ) $ (100 )

Regulation and Rates Public Ut

Regulation and Rates Public Utilities, Regulatory Proceeding (Tables)	6 Months Ended
	Jun. 30, 2016
Property tax tracker [Member] [Domain] | Natural Gas [Member]
Regulation and Rates [Line Items]
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments [Table Text Block]	The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2016 0.4% $3.5 June 1, 2015 (0.2) (2.3)
Property tax tracker [Member] [Domain] | Electric [Member]
Regulation and Rates [Line Items]
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments [Table Text Block]	The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2016 0.3% $5.7 May 1, 2015 0.4 8.4
Conservation Rider [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments [Table Text Block]	The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2016 0.3% $2.9 May 1, 2015 0.2 2.3
Conservation Rider [Member] | Electric [Member]
Regulation and Rates [Line Items]
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments [Table Text Block]	The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) May 1, 2016 (0.5)% $(11.7) May 1, 2015 0.2 4.2
Treasury Grants [Member] | Electric [Member]
Regulation and Rates [Line Items]
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments [Table Text Block]	The following table sets forth Federal Incentive Tracker Tariff revenue requirement approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Total annual amount to be passed back to eligible customers (Dollars in Millions) January 1, 2016 (0.2)% $(57.3) January 1, 2015 (0.2) (55.2)
Cost recovery mechanism [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments [Table Text Block]	The following table sets forth CRM rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) November 1, 2015 0.5% $5.3
Purchased Gas Adjustment (PGA) [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments [Table Text Block]	The following table sets forth PGA rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Effective Date Average Percentage Increase (Decrease) in Rates Increase (Decrease) in Revenue (Dollars in Millions) November 1, 2015 (17.4)% $(185.9)

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	6 Months Ended
	Jun. 30, 2016
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations	The following table describes the changes to the Company’s ARO for the six months ended June 30, 2016 : Puget Sound Energy (Dollars in Thousands) Changes in ARO Balance at December 31, 2015 $ 85,028 New asset retirement obligation recognized in the period — Liability adjustments (411 ) Revisions in estimated cash flows 16,854 Accretion expense 1,240 Balance at June 30, 2016 $ 102,711

Summary of Consolidation Poli23

Summary of Consolidation Policy (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016USD ($)mi²	Jun. 30, 2015USD ($)	Jun. 30, 2016USD ($)mi²	Jun. 30, 2015USD ($)	Dec. 31, 2015USD ($)
Subsidiaries [Member]
Summary of Consolidation Policy
Area of Service Territory (in sqmi) | mi²	6,000		6,000
Excise taxes collected	$ 48.8	$ 50.3	$ 123.4	$ 119.9
Unamortized Debt Issuance Expense					$ 30
Adjustments for New Accounting Pronouncement [Member]
Summary of Consolidation Policy
Unamortized Debt Issuance Expense					$ 38.4

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		Jun. 30, 2016USD ($)MWhMMBTUContracts	Dec. 31, 2015USD ($)MWhMMBTU
Interest Rate Swap [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional Amount | $	[1]	$ 450	$ 450
Natural Gas Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary	[2]	322.1	369.5
Electric generation fuel [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary		205	202.1
Purchased Electricity [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary | MWh		0.1	0.1
Parent Company [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Number of Interest Rate Derivatives Held | Contracts		2
[1]	3 Interest rate swap contracts are only held at Puget Energy.
[2]	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.

Accounting for Derivative Ins25

Accounting for Derivative Instruments and Hedging Activities Derivative Assets and Liabilities (Details) $ in Thousands, MMBTU in Millions		Jun. 30, 2016USD ($)MMBTU	Dec. 31, 2015USD ($)MMBTU
Derivative [Line Items]
Unrealized gain on derivative instruments		$ 36,255	$ 24,418
Derivative Liability, Current		67,417	136,173
Assets, Long-term		8,782	5,225
Unrealized loss on derivative instruments		19,859	48,073
Subsidiaries [Member]
Derivative [Line Items]
Unrealized gain on derivative instruments		36,255	24,418
Derivative Liability, Current		64,236	131,420
Assets, Long-term		8,782	5,225
Unrealized loss on derivative instruments		19,859	47,776
Commodity Contract [Member]
Derivative [Line Items]
Assets		45,037	29,643
Derivative Liability		84,095	179,196
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Assets	[1]	45,037	29,643
Derivative Liability	[2]	87,276	184,246
Not Designated as Hedging Instrument [Member] | Parent Company [Member]
Derivative [Line Items]
Unrealized gain on derivative instruments	[1]	36,255	24,418
Derivative Liability, Current	[2]	67,417	136,173
Assets, Long-term	[1]	8,782	5,225
Unrealized loss on derivative instruments	[2]	19,859	48,073
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	[3]	450,000	450,000
Assets	[1],[3]	0	0
Derivative Liability	[2],[3]	3,181	5,050
Not Designated as Hedging Instrument [Member] | Electric portfolio [Member]
Derivative [Line Items]
Assets	[1]	31,657	23,443
Derivative Liability	[2]	56,775	112,106
Not Designated as Hedging Instrument [Member] | Natural gas portfolio [Member]
Derivative [Line Items]
Assets	[1],[4]	13,380	6,200
Derivative Liability	[2],[4]	$ 27,320	$ 67,090
Not Designated as Hedging Instrument [Member] | Natural Gas Derivatives [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	[4]	322.1	369.5
[1]	1 Balance sheet locations: Current and Long-term Unrealized gain on derivative instruments.
[2]	2 Balance sheet locations: Current and Long-term Unrealized loss on derivative instruments.
[3]	3 Interest rate swap contracts are only held at Puget Energy.
[4]	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.

Accounting for Derivative Ins26

Accounting for Derivative Instruments and Hedging Activities Net Amount of Derivatives Reported in the Statement of Financial Position (Details) - USD ($) $ in Thousands		Jun. 30, 2016	Dec. 31, 2015
Commodity Contract [Member]
Assets:
Gross Amount Recognized in the Statement of Financial Position	[1]	$ 45,037	$ 29,643
Gross Amounts Offset in the Statement of Financial Position		0	0
Net of Amounts Presented in the Statement of Financial Position		45,037	29,643
Commodity Contracts		(38,636)	(23,998)
Cash Collateral Received		0	0
Net Amount		6,401	5,645
Liabilities:
Gross Amount Recognized in the Statement of Financial Position	[1]	84,095	179,196
Gross Amounts Offset in the Statement of Financial Position		0	0
Net of Amounts Presented in the Statement of Financial Position		84,095	179,196
Commodity Contracts		(38,636)	(23,998)
Cash Collateral Posted		(137)	0
Net Amount		45,322	155,198
Interest Rate Contract [Member]
Liabilities:
Gross Amount Recognized in the Statement of Financial Position	[1],[2]	3,181	5,050
Gross Amounts Offset in the Statement of Financial Position	[2]	0	0
Net of Amounts Presented in the Statement of Financial Position	[2]	3,181	5,050
Commodity Contracts	[2]	0	0
Cash Collateral Posted	[2]	0	0
Net Amount	[2]	$ 3,181	$ 5,050
[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		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		$ (46,724)	$ (8,232)	$ (63,546)	$ (11,928)
Subsidiaries [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		(46,724)	(8,232)	(63,546)	(11,383)
Not Designated as Hedging Instrument [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		(30,462)	1,829	(14,528)	32,816
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		359	1,440	1,213	3,415
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	(722)	0	(560)
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	[1]	(46,724)	(8,232)	(63,546)	(11,928)
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		12,327	5,082	33,010	15,744
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Purchased Electricity [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		3,576	4,261	14,795	26,145
Not Designated as Hedging Instrument [Member] | Subsidiaries [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		(30,821)	1,111	(15,741)	30,506
Not Designated as Hedging Instrument [Member] | Subsidiaries [Member] | Commodity Contract [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	[1]	(46,724)	(8,232)	(63,546)	(11,383)
Not Designated as Hedging Instrument [Member] | Subsidiaries [Member] | Commodity Contract [Member] | Electric generation fuel [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		12,327	5,082	33,010	15,744
Not Designated as Hedging Instrument [Member] | Subsidiaries [Member] | Commodity Contract [Member] | Purchased Electricity [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		$ 3,576	$ 4,261	$ 14,795	$ 26,145
[1]	1 Differences between Puget Energy and PSE for the six months ending June 30, 2015 are due to certain derivative contracts recorded at fair value in 2009 and subsequently designated as Normal Purchase Normal Sale (NPNS) or cash flow hedges. These differences occurred through February 2015.

Accounting for Derivative Ins28

Accounting for Derivative Instruments and Hedging Activities Contractual Contingent Liability (Details) $ in Thousands	Jun. 30, 2016USD ($)
Electric portfolio [Member]
Derivative [Line Items]
Fair Value Liability	$ (27,502)	[1]
Posted Collateral	0
Additional Collateral, Aggregate Fair Value	11,748
Electric portfolio [Member] | Credit Rating [Member]
Derivative [Line Items]
Fair Value Liability	(11,748)	[1],[2]
Posted Collateral	0	[2]
Additional Collateral, Aggregate Fair Value	11,748	[2]
Electric portfolio [Member] | Requested credit for adequate assurance [Member]
Derivative [Line Items]
Fair Value Liability	(15,648)	[1]
Posted Collateral	0
Additional Collateral, Aggregate Fair Value	0
Electric portfolio [Member] | Forward Value of Contract [Member]
Derivative [Line Items]
Fair Value Liability	(106)	[1],[3]
Posted Collateral	0	[3]
Additional Collateral, Aggregate Fair Value	$ 0	[3]
Electric portfolio [Member] | External Credit Rating, Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage	92.00%
Electric portfolio [Member] | External Credit Rating, Non Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage	8.00%
Natural gas portfolio [Member] | Credit Rating [Member]
Derivative [Line Items]
Posted Collateral	$ 1,000	[2]
[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 Carryin

Fair Value Measurements Carrying Value (Details) - Carrying Value [Member] - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Parent Company [Member]
Assets:
Cash and Cash Equivalents	$ 19,019	$ 42,494
Restricted Cash	10,128	7,949
Other Investments	51,874	52,820
Total assets	81,021	103,263
Liabilities:
Short-term Debt	36,000	159,004
Total liabilities	36,000	159,004
Parent Company [Member] | Level 1 [Member]
Assets:
Cash and Cash Equivalents	19,019	42,494
Restricted Cash	10,128	7,949
Other Investments	0	0
Total assets	29,147	50,443
Liabilities:
Short-term Debt	36,000	159,004
Total liabilities	36,000	159,004
Parent Company [Member] | Level 2 [Member]
Assets:
Cash and Cash Equivalents	0	0
Restricted Cash	0	0
Other Investments	51,874	52,820
Total assets	51,874	52,820
Liabilities:
Short-term Debt	0	0
Total liabilities	0	0
Subsidiaries [Member]
Assets:
Cash and Cash Equivalents	18,578	41,856
Restricted Cash	10,128	7,949
Other Investments	51,874	52,820
Total assets	80,580	102,625
Liabilities:
Short-term Debt	36,000	159,004
Total liabilities	36,000	159,004
Subsidiaries [Member] | Level 1 [Member]
Assets:
Cash and Cash Equivalents	18,578	41,856
Restricted Cash	10,128	7,949
Other Investments	0	0
Total assets	28,706	49,805
Liabilities:
Short-term Debt	36,000	159,004
Total liabilities	36,000	159,004
Subsidiaries [Member] | Level 2 [Member]
Assets:
Cash and Cash Equivalents	0	0
Restricted Cash	0	0
Other Investments	51,874	52,820
Total assets	51,874	52,820
Liabilities:
Short-term Debt	0	0
Total liabilities	$ 0	$ 0

Fair Value Measurements Debt at

Fair Value Measurements Debt at at Carrying and Fair Value (Details) - USD ($) $ in Thousands		Jun. 30, 2016	Dec. 31, 2015
Subsidiaries [Member]
Liabilities:
Long-term debt (fixed-rate), net of discount			$ 30,000
Discounted cash flow [Member] | Parent Company [Member] | Carrying Value [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure		$ 5,334,578	5,327,518
Discounted cash flow [Member] | Parent Company [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes		250,000	250,000
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[1]	5,084,578	5,077,518
Long-term debt (fixed-rate), net of discount	[1]	35,600	38,400
Discounted cash flow [Member] | Parent Company [Member] | Fair Value [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure		7,040,645	6,520,004
Discounted cash flow [Member] | Parent Company [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes		222,780	211,173
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[1]	6,817,865	6,308,831
Discounted cash flow [Member] | Subsidiaries [Member] | Carrying Value [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure		3,745,835	3,744,362
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, Fair Value Disclosure	[2]	3,495,835	3,494,362
Long-term debt (fixed-rate), net of discount	[1]	28,600	30,000
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure		4,989,166	4,540,617
Discounted cash flow [Member] | Subsidiaries [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes		222,780	211,173
Long-term Debt, Fixed Rate, Net of Discount, Fair Value Disclosure	[2]	$ 4,766,386	$ 4,329,444
[1]	1 The carrying value includes debt issuances costs of $35.6 million, and $38.4 million for June 30, 2016 and December 31, 2015, respectively, which are not included in fair value.
[2]	2 The carrying value includes debt issuances costs of $28.6 million, and $30.0 million for June 30, 2016 and December 31, 2015, respectively, which are not included in fair value.

Fair Value Measurements Assets

Fair Value Measurements Assets and Liabilities (Details) - USD ($) $ in Thousands		3 Months Ended				6 Months Ended
		Jun. 30, 2016		Jun. 30, 2015		Jun. 30, 2016		Jun. 30, 2015		Dec. 31, 2015
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		$ (20)		$ (17,692)		$ (9,728)		$ (14,100)
Included in earnings		(1,954)	[1]	(4,064)	[1]	2,654	[2]	(9,102)	[2]
Included in regulatory assets/liabilities		1,562		2,813		3,082		2,938
Settlements		(1,373)		(337)		(2,370)		(133)
Transferred into Level 3		0		0		(2,080)		(787)
Transferred out of Level 3		(1,761)		4,733		4,896		6,637
Balance at end of period		(3,546)		(14,547)		(3,546)		(14,547)
Electric portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts		(2,500)		(3,800)		3,100		(8,800)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		1,602		(16,091)		(7,345)		(12,061)
Included in earnings		(1,954)	[1]	(4,064)	[1]	2,654	[2]	(9,102)	[2]
Included in regulatory assets/liabilities		0		0		0		0
Settlements		(494)		52		(554)		165
Transferred into Level 3		0		0		(2,080)		(787)
Transferred out of Level 3		(2,216)		4,733		4,263		6,415
Balance at end of period		(3,062)		(15,370)		(3,062)		(15,370)
Natural gas portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		(1,622)		(1,601)		(2,383)		(2,039)
Included in earnings		0	[1]	0	[1]	0	[2]	0	[2]
Included in regulatory assets/liabilities		1,562		2,813		3,082		2,938
Settlements		(879)		(389)		(1,816)		(298)
Transferred into Level 3		0		0		0		0
Transferred out of Level 3		455		0		633		222
Balance at end of period		(484)		$ 823		(484)		$ 823
Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		45,037				45,037				$ 29,643
Derivative Liability		84,095				84,095				179,196
Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	[3]	3,181				3,181				5,050
Fair Value, Measurements, Recurring [Member] | Parent Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability		3,181				3,181
Fair Value, Measurements, Recurring [Member] | Parent Company [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability		3,181				3,181
Fair Value, Measurements, Recurring [Member] | Parent Company [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability										5,050
Fair Value, Measurements, Recurring [Member] | Parent Company [Member] | Level 1 [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability										5,050
Fair Value, Measurements, Recurring [Member] | Parent Company [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability		3,181				3,181				0
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		3,181				3,181				0
Fair Value, Measurements, Recurring [Member] | Parent Company [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability		0				0				5,050
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				5,050
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		45,037				45,037				29,643
Derivative Liability		84,095				84,095				179,196
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Commodity Contract [Member] | Electric portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		31,657				31,657				23,443
Derivative Liability		56,775				56,775				112,106
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Commodity Contract [Member] | Natural gas portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		13,380				13,380				6,200
Derivative Liability		27,320				27,320				67,090
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		35,198				35,198				15,247
Derivative Liability		70,710				70,710				155,072
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Level 2 [Member] | Commodity Contract [Member] | Electric portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		24,411				24,411				10,709
Derivative Liability		46,467				46,467				92,027
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Level 2 [Member] | Commodity Contract [Member] | Natural gas portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		10,787				10,787				4,538
Derivative Liability		24,243				24,243				63,045
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		9,839				9,839				14,396
Derivative Liability		13,385				13,385				24,124
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Level 3 [Member] | Commodity Contract [Member] | Electric portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		7,246	[4]			7,246	[4]			12,734	[5]
Derivative Liability		10,308	[4]			10,308	[4]			20,079	[5]
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Level 3 [Member] | Commodity Contract [Member] | Natural gas portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		2,593	[4]			2,593	[4]			1,662	[5]
Derivative Liability		$ 3,077	[4]			$ 3,077	[4]			$ 4,045	[5]
[1]	1 Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(2.5) million and $(3.8) million for the three months ended June 30, 2016 and 2015, respectively.
[2]	2 Income Statement locations: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $3.1 million and $(8.8) million for the six months ended June 30, 2016 and 2015, respectively.
[3]	2 Interest rate swap contracts are only held at Puget Energy.
[4]	1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions
[5]	1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

Fair Value Measurements Valuati

Fair Value Measurements Valuation Technicques for Measurement with Unobservable Inputs (Details)	3 Months Ended			6 Months Ended		12 Months Ended
	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)$ / MWh	Jun. 30, 2015USD ($)	Jun. 30, 2016USD ($)$ / MMBTU$ / MWh	Jun. 30, 2015USD ($)	Dec. 31, 2015USD ($)$ / MWh	Dec. 31, 2014$ / MMBTU$ / MWh
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Comparability Adjustments		8.60%				4.50%
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	$ 600,000			$ 600,000		$ 1,300,000
Impairment of Intangible Assets (Excluding Goodwill)		$ 5,338,000				5,360,000
Carrying Value [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure		$ 19,855,000				$ 27,628,000
Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh		9.46				15.16
Fair Value Inputs, Power Contract Costs		$ 4,100				$ 4,100
Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh		25.96				27.25
Fair Value Inputs, Power Contract Costs		$ 4,659				$ 4,659
Discounted cash flow [Member] | Weighted Average [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh) | $ / MWh		21.38				23.23
Fair Value Inputs, Power Contract Costs		$ 4,452				$ 4,417
Commodity Contract [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	45,037,000			45,037,000		29,643,000
Derivative Liability	84,095,000			$ 84,095,000		179,196,000
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				12.72			10.69
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				32			29.18
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				27.99			23.39
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				1.25			1.12
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				3.46			2.95
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				2.53			2.25
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	45,037,000			$ 45,037,000		29,643,000
Derivative Liability	84,095,000			84,095,000		179,196,000
Fair Value, Measurements, Recurring [Member] | Parent Company [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Liability	3,181,000			3,181,000
Electric portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	(2,500,000)		$ (3,800,000)	3,100,000	$ (8,800,000)
Electric portfolio [Member] | Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Commodity Contract [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	31,657,000			31,657,000		23,443,000
Derivative Liability	56,775,000			56,775,000		112,106,000
Natural gas portfolio [Member] | Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Commodity Contract [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	13,380,000			13,380,000		6,200,000
Derivative Liability	$ 27,320,000			$ 27,320,000		67,090,000
Wells Project [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-Lived Intangible Assets, Net		$ 25,193,000				$ 32,988,000

Retirement Benefits Net Periodi

Retirement Benefits Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost			$ 9,209		$ 21,287
Interest cost			14,452		28,088
Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost			542		1,108
Interest cost			1,163		2,281
Other Benefit [Member]
Components of net periodic benefit cost:
Service cost			49		112
Interest cost			313		$ 621
Parent Company [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	$ 4,605	$ 5,172	9,209	$ 10,644
Interest cost	7,226	6,937	14,452	14,044
Expected return on plan assets	(11,687)	(11,117)	(23,374)	(22,519)
Amortization of prior service cost	(495)	(495)	(990)	(990)
Amortization of net loss (gain)	0	962	0	1,943
Defined Benefit Plan, Net Periodic Benefit Cost	(351)	1,459	(703)	3,122
Parent Company [Member] | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	271	277	542	554
Interest cost	582	570	1,163	1,140
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	11	11	22	22
Amortization of net loss (gain)	228	410	456	820
Defined Benefit Plan, Net Periodic Benefit Cost	1,092	1,268	2,183	2,536
Parent Company [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	24	23	49	56
Interest cost	157	150	313	311
Expected return on plan assets	(111)	(133)	(222)	(266)
Amortization of prior service cost	0	0	0	0
Amortization of net loss (gain)	(29)	(51)	(58)	(66)
Defined Benefit Plan, Net Periodic Benefit Cost	41	(11)	82	35
Subsidiaries [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	4,605	5,172	9,209	10,644
Interest cost	7,226	6,937	14,452	14,044
Expected return on plan assets	(11,736)	(11,223)	(23,472)	(22,731)
Amortization of prior service cost	(393)	(393)	(786)	(786)
Amortization of net loss (gain)	3,740	5,141	7,480	10,277
Defined Benefit Plan, Net Periodic Benefit Cost	3,442	5,634	6,883	11,448
Subsidiaries [Member] | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	271	277	542	554
Interest cost	582	570	1,163	1,140
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	11	11	22	22
Amortization of net loss (gain)	333	530	666	1,060
Defined Benefit Plan, Net Periodic Benefit Cost	1,197	1,388	2,393	2,776
Subsidiaries [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	24	23	49	56
Interest cost	157	150	313	311
Expected return on plan assets	(111)	(133)	(222)	(266)
Amortization of prior service cost	0	1	0	2
Amortization of net loss (gain)	(90)	(120)	(180)	(203)
Defined Benefit Plan, Net Periodic Benefit Cost	$ (20)	$ (79)	$ (40)	$ (100)

Retirement Benefits Change in N

Retirement Benefits Change in Net Benefit Obligation (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Qualified Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	$ 643,088	$ 690,194
Service cost	9,209	21,287
Interest cost	14,452	28,088
Actuarial loss/(gain)	0	(55,665)
Benefits paid	(20,650)	(39,963)
Medicare part D subsidiary received	0	0
Defined benefit plan expected administration expense	0	(853)
Benefit obligation at end of period	646,099	643,088
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	51,279	55,855
Service cost	542	1,108
Interest cost	1,163	2,281
Actuarial loss/(gain)	0	(4,430)
Benefits paid	(2,092)	(3,535)
Medicare part D subsidiary received	0	0
Defined benefit plan expected administration expense	0	0
Benefit obligation at end of period	50,892	51,279
Other Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	13,946	15,688
Service cost	49	112
Interest cost	313	621
Actuarial loss/(gain)	0	(1,416)
Benefits paid	(664)	(1,354)
Medicare part D subsidiary received	5	295
Defined benefit plan expected administration expense	0	0
Benefit obligation at end of period	$ 13,649	$ 13,946

Retirement Benefits Activity (D

Retirement Benefits Activity (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2016	Dec. 31, 2016
Qualified Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Company Contribution	$ 4.5	$ 9
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Company Contribution	1	2.1
Other Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Company Contribution	$ 0.2	$ 0.4
Subsidiaries [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent	1.00%	4.00%
Scenario, Forecast [Member] | Qualified Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			$ 24
Scenario, Forecast [Member] | Supplemental Employee Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			2.5
Scenario, Forecast [Member] | Other Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			$ 0.5

Regulation and Rates (Details)

Regulation and Rates (Details) - USD ($) $ in Millions

3 Months Ended

6 Months Ended

12 Months Ended

Jun. 30, 2016

Jun. 30, 2015

Jun. 30, 2016

Jun. 30, 2015

Dec. 31, 2016

Dec. 31, 2015

May 01, 2016

Oct. 31, 2015

Jun. 01, 2015

May 01, 2015

Jan. 01, 2015

Dec. 31, 2014

Regulatory Assets [Line Items]

Storm Damage Costs Incurred During Period

$ 15.6

$ 2.5

Storm Damage Costs Deferred During Period

$ 6.5

$ 0.2

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

(0.20%)

Public Utilities, Rate Case, Deferred Storm Costs Threshold

$ 8

$ 8

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

$ (55.2)

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

Regulatory Assets [Line Items]

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

$ 3.5

$ (2.3)

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

0.40%

(0.20%)

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

Regulatory Assets [Line Items]

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

$ 5.7

$ 8.4

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

0.30%

0.40%

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

Regulatory Assets [Line Items]

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

$ 5.3

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

0.50%

Conservation Rider [Member] | Natural Gas [Member]

Regulatory Assets [Line Items]

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

$ 2.9

$ 2.3

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

0.30%

0.20%

Conservation Rider [Member] | Electric [Member]

Regulatory Assets [Line Items]

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

$ (11.7)

$ 4.2

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

(0.50%)

0.20%

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

Regulatory Assets [Line Items]

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

$ (185.9)

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

(17.40%)

Decoupling Mechanism [Member]

Regulatory Assets [Line Items]

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

$ (12)

Decoupling Mechanism [Member] | Natural Gas [Member]

Regulatory Assets [Line Items]

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

(5.5)

$ 25.4

$ 22

$ (1.3)

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

2.80%

2.10%

Decoupling Mechanism [Member] | Electric [Member]

Regulatory Assets [Line Items]

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

(11.9)

$ 20.8

$ 53.8

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

1.00%

2.60%

Decoupling Mechanism [Member] | Maximum [Member]

Regulatory Assets [Line Items]

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

3.00%

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

Regulatory Assets [Line Items]

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

$ 28.7

8.2

Decoupling Mechanism [Member] | Deferred Revenue [Domain] | Electric [Member]

Regulatory Assets [Line Items]

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

$ 1.9

Scenario, Forecast [Member]

Regulatory Assets [Line Items]

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

(0.20%)

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

$ (57.3)

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - Subsidiaries [Member] - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015
Public Utilities, Property, Plant and Equipment, Decommissioning Obligations		$ 19,700
Increase (Decrease) in Asset Retirement Obligations	$ 102,711		$ 85,028
Asset Retirement Obligations, Significant Changes	0
Asset Retirement Obligation, Liabilities Incurred	(411)
Asset Retirement Obligation, Revision of Estimate	16,854
Asset Retirement Obligation, Accretion Expense	$ 1,240

Commitments and Contingencies (

Commitments and Contingencies (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Colstrip Units 1 and 2 [Member]
Loss Contingencies [Line Items]
Ownership interest (percent)	50.00%
Colstrip Units 3 and 4 [Member]
Loss Contingencies [Line Items]
Ownership interest (percent)	25.00%
Pending Litigation [Member]
Loss Contingencies [Line Items]
Litigation claims accrual	$ 0.5	$ 0.3

Other Related Party Transaction

Other Related Party Transactions (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transaction, Amounts of Transaction	$ 10.7	$ 20.3