Puget Energy (PSD) 10-Q 6 Aug 15 2015 Q2 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - Jun. 30, 2015 - shares	Total
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	2,015
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2015
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	2,015
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2015

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Operating revenue:
Electric	$ 469,616	$ 475,580	$ 1,043,243	$ 1,109,133
Gas	184,941	183,935	533,803	571,378
Other	3,784	3,401	8,129	7,780
Total operating revenue	658,341	662,916	1,585,175	1,688,291
Energy costs:
Purchased electricity	104,471	114,627	257,951	295,785
Electric generation fuel	55,652	34,795	103,668	110,232
Residential exchange	(29,054)	(23,621)	(72,768)	(53,624)
Purchased gas	79,465	76,272	235,898	267,578
Unrealized (gain) loss on derivative instruments, net	(8,232)	(17,094)	(11,928)	(24,934)
Utility operations and maintenance	131,972	134,883	269,147	278,960
Non-utility expense and other	2,323	2,293	5,535	5,712
Depreciation	100,412	105,197	206,589	206,916
Conservation amortization	24,561	22,526	54,165	51,508
Taxes other than income taxes	69,999	67,772	164,912	168,590
Total operating expenses	531,569	517,650	1,213,169	1,306,723
Operating income	126,772	145,266	372,006	381,568
Other income (deductions):
Other income	5,255	4,621	10,039	8,863
Other expense	(1,815)	(1,644)	(3,222)	(3,226)
Non-hedged interest rate derivative expense	(1,440)	(1,360)	(3,415)	(2,107)
Interest charges:
AFUDC	1,729	1,562	3,160	2,714
Interest expense	(89,822)	(92,173)	(178,731)	(182,428)
Total before tax	40,679	56,272	199,837	205,384
Tax (expense) or benefit	15,063	15,159	58,545	56,679
Net of Tax	25,616	41,113	141,292	148,705
Subsidiaries [Member]
Operating revenue:
Electric	469,616	475,580	1,043,243	1,109,133
Gas	184,941	183,935	533,803	571,378
Other	3,784	3,401	8,138	7,780
Total operating revenue	658,341	662,916	1,585,184	1,688,291
Energy costs:
Purchased electricity	104,471	114,627	257,951	295,785
Electric generation fuel	55,652	34,795	103,668	110,232
Residential exchange	(29,054)	(23,621)	(72,768)	(53,624)
Purchased gas	79,465	76,272	235,898	267,578
Unrealized (gain) loss on derivative instruments, net	(8,232)	(17,094)	(11,383)	(24,364)
Utility operations and maintenance	131,972	134,883	269,147	278,960
Non-utility expense and other	6,342	5,374	13,349	11,548
Depreciation	100,412	105,197	206,589	206,916
Conservation amortization	24,561	22,526	54,165	51,508
Taxes other than income taxes	69,999	67,772	164,912	168,590
Total operating expenses	535,588	520,731	1,221,528	1,313,129
Operating income	122,753	142,185	363,656	375,162
Other income (deductions):
Other income	5,255	4,621	10,039	8,860
Other expense	(1,815)	(1,644)	(3,222)	(3,226)
Interest charges:
AFUDC	1,729	1,562	3,160	2,714
Interest expense	(62,620)	(65,522)	(125,816)	(129,659)
Interest expense on parent note	(31)	(27)	(63)	(52)
Total before tax	65,271	81,175	247,754	253,799
Tax (expense) or benefit	22,572	23,341	75,955	74,883
Net of Tax	$ 42,699	$ 57,834	$ 171,799	$ 178,916

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Parent [Line Items]
Net income (loss)	$ 25,616	$ 41,113	$ 141,292	$ 148,705
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	1,277	(783)	1,856	(992)
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	0	0	333	347
Other Comprehensive Income Reclassification Of Net Unrealized Gain Loss On Interest Rate Swaps During Period Net Of Tax	0	0	0	94
Other comprehensive income (loss)	1,277	(783)	2,189	(551)
Comprehensive income (loss)	26,893	40,330	143,481	148,154
Subsidiaries [Member]
Parent [Line Items]
Net income (loss)	42,699	57,834	171,799	178,916
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	4,094	1,424	7,475	3,425
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	0	0	686	718
Amortization Of Financing Cash Flow Hedge Contracts To Earnings During Period Net Of Tax	79	79	158	158
Other comprehensive income (loss)	4,173	1,503	8,319	4,301
Comprehensive income (loss)	$ 46,872	$ 59,337	$ 180,118	$ 183,217

CONSOLIDATED STATEMENTS OF COM4

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Net unrealized gain (loss) from pension and postretirement plans, net of tax	$ 688	$ (421)	$ 1,000	$ (534)
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax	0	0	179	187
Reclassification of net unrealized loss on interest rate swaps during the period, net of tax	0	0	0	50
Subsidiaries [Member]
Net unrealized gain (loss) from pension and postretirement plans, net of tax	2,204	766	4,025	1,844
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax	0	0	369	386
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, 2015	Dec. 31, 2014
Utility plant (at original cost, including construction work in progress):
Electric plant	$ 7,289,865	$ 7,135,206
Gas plant	2,757,784	2,680,067
Common plant	471,626	472,926
Less: Accumulated depreciation and amortization	(1,739,918)	(1,611,220)
Net utility plant	8,779,357	8,676,979
Other property and investments:
Goodwill	1,656,513	1,656,513
Other property and investments	88,419	91,139
Total other property and investments	1,744,932	1,747,652
Current assets:
Cash and cash equivalents	14,535	37,527
Restricted cash	7,964	32,863
Accounts receivable, net of allowance for doubtful accounts	240,756	306,923
Unbilled revenue	135,624	168,039
Purchased Gas Adjustment Receivable	0	21,073
Materials and supplies, at average cost	83,494	83,189
Fuel and gas inventory, at average cost	58,090	69,433
Unrealized gain on derivative instruments	17,951	21,178
Income taxes	1	301
Prepaid expense and other	24,183	20,905
Power contract acquisition adjustment gain	42,033	43,843
Deferred income taxes	124,472	161,445
Total current assets	749,103	966,719
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	75,268	95,432
Power Cost Adjustment Mechanism Asset, Noncurrent	4,688	4,623
Regulatory assets related to power contracts	27,592	29,816
Other regulatory assets	892,075	866,835
Unrealized gain on derivative instruments	3,137	3,170
Power contract acquisition adjustment gain	318,184	347,547
Other	98,817	96,275
Total other long-term and regulatory assets	1,419,761	1,443,698
Total assets	12,693,153	12,835,048
Capitalization:
Common stock	0	0
Additional paid-in capital	3,308,957	3,308,957
Earnings reinvested in the business	220,206	271,414
Accumulated Other Comprehensive Income (Loss), Net of Tax	(34,854)	(37,043)
Total common shareholder's equity	3,494,309	3,543,328
Long-term debt:
First mortgage bonds and senior notes	3,364,412	3,189,412
Pollution control bonds	161,860	161,860
Junior subordinated notes	250,000	250,000
Long-term debt	1,800,000	1,699,000
Debt discount	(214,705)	(218,664)
Total long-term debt	5,361,567	5,081,608
Total capitalization	8,855,876	8,624,936
Current liabilities:
Accounts payable	226,109	307,578
Short-term debt	0	85,000
Long-term Debt, Current Maturities	12,000	162,000
Purchased gas adjustment liability	14,890	0
Accrued expenses:
Taxes	99,231	107,782
Salaries and wages	32,762	40,970
Interest	73,525	78,914
Unrealized loss on derivative instruments	130,153	142,195
Power contract acquisition adjustment loss	3,551	3,593
Other	60,959	62,464
Total current liabilities	653,180	990,496
Long-term and regulatory liabilities:
Deferred income taxes	1,524,944	1,522,357
Unrealized loss on derivative instruments	45,889	62,913
Regulatory liabilities	613,287	633,471
Regulatory liabilities related to power contracts	360,217	391,389
Power contract acquisition adjustment loss	24,041	26,223
Other deferred credits	615,719	583,263
Total long-term and regulatory liabilities	$ 3,184,097	$ 3,219,616
Commitments and contingencies
Total capitalization and liabilities	$ 12,693,153	$ 12,835,048
Subsidiaries [Member]
Utility plant (at original cost, including construction work in progress):
Electric plant	9,471,915	9,330,999
Gas plant	3,353,746	3,282,818
Common plant	511,542	512,842
Less: Accumulated depreciation and amortization	(4,557,846)	(4,449,680)
Net utility plant	8,779,357	8,676,979
Other property and investments:
Other property and investments	84,202	86,913
Total other property and investments	84,202	86,913
Current assets:
Cash and cash equivalents	13,320	37,466
Restricted cash	7,964	32,863
Accounts receivable, net of allowance for doubtful accounts	241,179	307,046
Unbilled revenue	135,624	168,039
Purchased Gas Adjustment Receivable	0	21,073
Materials and supplies, at average cost	83,494	83,189
Fuel and gas inventory, at average cost	55,922	66,656
Unrealized gain on derivative instruments	17,951	21,178
Income taxes	1	301
Prepaid expense and other	24,181	20,907
Deferred income taxes	170,716	208,447
Total current assets	750,352	967,165
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	74,759	94,913
Power Cost Adjustment Mechanism Asset, Noncurrent	4,688	4,623
Other regulatory assets	892,048	866,793
Unrealized gain on derivative instruments	3,137	3,170
Other	89,296	89,306
Total other long-term and regulatory assets	1,063,928	1,058,805
Total assets	10,677,839	10,789,862
Capitalization:
Common stock	859	859
Additional paid-in capital	3,275,105	3,246,205
Earnings reinvested in the business	230,034	202,622
Accumulated Other Comprehensive Income (Loss), Net of Tax	(162,638)	(170,957)
Total common shareholder's equity	3,343,360	3,278,729
Long-term debt:
First mortgage bonds and senior notes	3,364,412	3,189,412
Pollution control bonds	161,860	161,860
Junior subordinated notes	250,000	250,000
Debt discount	(1,919)	(13)
Total long-term debt	3,774,353	3,601,259
Total capitalization	7,117,713	6,879,988
Current liabilities:
Accounts payable	226,109	307,572
Short-term debt	0	85,000
Short-term note owed to parent	0	28,933
Long-term Debt, Current Maturities	12,000	162,000
Purchased gas adjustment liability	14,890	0
Accrued expenses:
Taxes	99,231	107,782
Salaries and wages	32,762	40,970
Interest	47,424	55,346
Unrealized loss on derivative instruments	124,139	135,973
Other	60,959	62,464
Total current liabilities	617,514	986,040
Long-term and regulatory liabilities:
Deferred income taxes	1,672,405	1,649,857
Unrealized loss on derivative instruments	43,609	60,063
Regulatory liabilities	611,091	630,651
Other deferred credits	615,507	583,263
Total long-term and regulatory liabilities	$ 2,942,612	$ 2,923,834
Commitments and contingencies
Total capitalization and liabilities	$ 10,677,839	$ 10,789,862

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
ASSETS
Construction work in progress	$ 299,085	$ 239,690
Current assets:
Allowance for doubtful accounts	$ 9,129	$ 7,472
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	$ 299,085	$ 239,690
Current assets:
Allowance for doubtful accounts	$ 9,129	$ 7,472
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, 2015	Jun. 30, 2014
Operating activities:
Net income (loss)	$ 141,292	$ 148,705
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	206,589	206,916
Conservation amortization	54,165	51,508
Deferred income taxes and tax credits, net	58,580	56,679
Net unrealized (gain) loss on derivative instruments	(12,707)	(25,664)
Derivative contracts classified as financing activities due to merger	8,045	8,026
AFUDC - Equity	(3,836)	(3,405)
Funding of pension liability	(9,000)	(6,000)
Regulatory Assets	(111,660)	(80,365)
Regulatory liabilities	7,186	3,668
Other long-term assets	13,142	(6,477)
Other long-term liabilities	11,686	37,739
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	98,582	228,718
Materials and supplies	(305)	5,482
Fuel and gas inventory	10,734	2,359
Income taxes	300	297
Prepayments and other	(3,276)	(1,273)
Purchased gas adjustment	35,963	(18,477)
Accounts payable	(80,932)	(64,794)
Taxes payable	(8,551)	(17,536)
Accrued expenses and other	(26,890)	(8,884)
Net cash provided by operating activities	389,107	517,222
Investing activities:
Construction expenditures - excluding equity AFUDC	(265,500)	(217,381)
Treasury grants received	0	107,794
Restricted cash	24,899	(47,793)
Other	2,674	(11,058)
Net cash used in investing activities	(237,927)	(168,438)
Financing activities:
Change in short-term debt and leases, net	(85,000)	(165,789)
Dividends paid	(192,500)	(137,779)
Long-term notes and bonds issued	825,000	299,000
Redemption of bonds and notes	(699,000)	(299,000)
Derivative contracts classified as financing activities due to merger	(8,045)	(8,026)
Issuance cost of bonds and other	(14,627)	3,215
Net cash provided by (used in) financing activities	(174,172)	(308,379)
Net increase (decrease) in cash and cash equivalents	(22,992)	40,405
Cash and cash equivalents at beginning of period	37,527	44,302
Cash and cash equivalents at end of period	14,535	84,707
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	173,941	172,106
Cash payments (refunds) for income taxes	0	0
Accounts payable for capital expenditures eliminated from cash flows	51,239	63,849
Subsidiaries [Member]
Operating activities:
Net income (loss)	171,799	178,916
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	206,589	206,916
Conservation amortization	54,165	51,508
Deferred income taxes and tax credits, net	75,953	74,883
Net unrealized (gain) loss on derivative instruments	(11,383)	(24,364)
AFUDC - Equity	(3,836)	(6,000)
Funding of pension liability	(9,000)	(3,405)
Regulatory Assets	(111,660)	(80,365)
Regulatory liabilities	7,186	3,668
Other long-term assets	12,507	(1,650)
Other long-term liabilities	14,530	33,339
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	98,282	228,559
Materials and supplies	(305)	5,482
Fuel and gas inventory	10,734	2,359
Income taxes	300	297
Prepayments and other	(3,274)	(1,273)
Purchased gas adjustment	35,963	(18,477)
Accounts payable	(80,926)	(64,794)
Taxes payable	(8,551)	(17,536)
Accrued expenses and other	(31,442)	(9,620)
Net cash provided by operating activities	427,631	558,443
Investing activities:
Construction expenditures - excluding equity AFUDC	(265,500)	(217,381)
Treasury grants received	0	107,794
Restricted cash	24,899	(47,793)
Other	4,692	(9,818)
Net cash used in investing activities	(235,909)	(167,198)
Financing activities:
Change in short-term debt and leases, net	(85,000)	(165,789)
Dividends paid	(144,387)	(203,628)
Loan from (payment to) parent	(28,933)	(665)
Investment from parent	28,900	0
Long-term notes and bonds issued	425,000	0
Redemption of bonds and notes	(400,000)	0
Issuance cost of bonds and other	(11,448)	3,886
Net cash provided by (used in) financing activities	(215,868)	(366,196)
Net increase (decrease) in cash and cash equivalents	(24,146)	25,049
Cash and cash equivalents at beginning of period	37,466	44,111
Cash and cash equivalents at end of period	13,320	69,160
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	128,267	123,345
Cash payments (refunds) for income taxes	0	0
Accounts payable for capital expenditures eliminated from cash flows	$ 51,239	$ 63,849

Summary of Consolidation Policy

Summary of Consolidation Policy	6 Months Ended
	Jun. 30, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation and Significant Accounting Policies [Text Block]	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, 2014 . 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 $50.3 million and $119.9 million for the three and six months ended June 30, 2015 , respectively, and $50.6 million and $128.5 million for the three and six months ended June 30, 2014 , 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. PSE's electric and gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. Any differences in revenue are deferred to a regulatory asset for under recovery or regulatory liability for over recovery under alternative revenue recognition. To record revenues under this program, the Company must be able to collect the revenue within 24 months based on alternative revenue recognition guidance. Decoupled rate increases are effective May 1 of each year subject to a 3.0% cap of total revenue for decoupled rate schedules. Any excess revenue above 3.0% will be included in the following year's decoupled rate. The Company will be able to recognize revenue deferred below the 3.0% cap of total revenue for decoupled rate schedules. For revenue deferrals exceeding the annual 3.0% rate cap of total revenue for decoupled rate schedules, the Company will need to review the excess amount for its ability to be collected within 24 months. If the excess amount cannot be collected within 24 months, for GAAP purposes only, the Company will not record any decoupling revenue until it is within the 24 months of collection. Revenues associated with energy costs under the Power Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA) mechanism are excluded from the decoupling mechanism.

New Accounting Pronouncements

New Accounting Pronouncements	6 Months Ended
	Jun. 30, 2015
New Accounting Pronouncements [Abstract]
New Accounting Pronouncements and Changes in Accounting Principles [Text Block]	New Accounting Pronouncements Revenue 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. On July 9, 2015, FASB finalized a one-year deferral for ASU 2014-09, making ASU 2014-09 effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. In addition to the FASB's deferral decision, FASB provided reporting entities with an option to adopt ASU 2014-09 for the fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, the original effective date. The Company plans to adopt ASU 2014-09 according to the original 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 cannot determine the impact this standard will have on its consolidated financial statements. Debt Issuance Costs In April 2015, the FASB issued 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. This new guidance affects only the presentation of debt issuance costs and not the recognition and measurement of debt issuance costs. ASU 2015-03 is to be applied on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption of the amendments is permitted for financial statements that have not been previously issued. The Company plans to adopt ASU 2015-03 during the first quarter of fiscal 2016. The amount of unamortized debt issuance costs as of June 30, 2015 and December 31, 2014 totaled $40.9 million and $35.7 million , respectively. Retirement Benefits In April 2015, the FASB issued ASU 2015-04, " Compensation - Retirement Benefits (Topic 715): Practical Expedient for the Measurement Date of an Employer's Defined Benefit Obligation and Plan Assets. " ASU 2015-04 provides a practical expedient to employers with fiscal year-end dates that do not coincide with a calendar month-end. This practical expedient allows the employers to measure pension and post-retirement benefit plan assets and obligations as of the calendar month-end date closest to the fiscal year-end. ASU 2015-04 is effective for annual reporting periods beginning after December 15, 2015, including interim periods within those annual reporting periods, which will include first quarter of fiscal 2016 for the Company. Early adoption is permitted. If elected by the Company, the practical expedient provided by ASU 2015-04 would be applied prospectively in the first quarter of fiscal 2016. We do not expect this guidance to have a material impact on our results of operations or financial position. Internal-Use Software In April 2015, the FASB issued ASU 2015-05, " Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Fees Paid in a Cloud Computing Arrangement. " ASU 2015-05 requires a customer in a cloud computing arrangement to follow internal-use software guidance if both of the following criteria are met: the customer has the contractual right to take possession of the software at any time during the cloud computing arrangement and can feasibly run the software on its own hardware. If the customer does not meet both criteria, the cloud computing arrangement is considered a service contract and separate accounting for a license would not be permitted. ASU 2015-05 is effective for annual reporting periods, including interim periods within those annual reporting periods, beginning after December 15, 2015. Early adoption is permitted. The Company plans to adopt ASU 2015-05 during the first quarter of fiscal 2016 and is in the process of evaluating the potential impacts, if any, of this new guidance on its financial statements. Fair Value Measurement In May 2015, the FASB issued ASU 2015-07, " Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent) ," which removes the requirement to categorize within the fair value hierarchy all investments for which their fair value is measured using the net asset value per share practical expedient. This ASU also removes the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. Instead, those disclosures will be limited to investments for which the Company has elected to measure the fair value using that practical expedient. ASU 2015-07 is effective for annual reporting periods, and interim periods within those reporting periods, beginning after December 15, 2015 and requires reporting entities to apply this ASU retrospectively to all periods presented. Early adoption is permitted. The Company plans to adopt ASU 2015-07 during the first quarter of fiscal 2016. At this time, the Company cannot determine the impact this standard will have on its consolidated financial statements. Inventory In July 2015, the FASB issued ASU 2015-11, " Inventory (Topic 330): Simplifying the Measurement of Inventory. " ASU 2015-11 requires inventory within scope of this Topic 330 to be measured at the lower of cost and net realizable value. This amendment does not apply to inventory that is measured using last-in, first-out (LIFO) or the retail inventory method. This amendment applies to all other inventory, including inventory measured using first-in, first-out (FIFO) or average cost. The new accounting guidance is effective for annual reporting periods, and interim periods within those annual reporting periods, beginning after December 15, 2016 with early adoption permitted. At this time, the Company cannot determine the impact this standard will have on its consolidated financial statements. The Company plans to adopt ASU 2015-11 during the first quarter of fiscal 2017.

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	6 Months Ended
	Jun. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Accounting for Derivative Instruments and Hedging Activities	Accounting for Derivative Instruments and Hedging Activities PSE employs various energy portfolio optimization strategies, but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the PCA. Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility in costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. 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. 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, 2015 , 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 while management continues to monitor the economics of terminating the swaps. Unless the economics of terminating the swaps become more favorable, management intends to let them expire naturally 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, 2015 December 31, 2014 (Dollars in Thousands) Volumes Assets 1 Liabilities 2 Volumes Assets 1 Liabilities 2 Interest rate swap derivatives 3 $450 million $ — $ 8,294 $450 million $ — $ 9,073 Electric portfolio derivatives * 11,449 101,416 * 4,822 107,228 Natural gas derivatives (MMBtus) 4 343.0 million 9,639 66,332 360.4 million 19,526 88,807 Total derivative contracts $ 21,088 $ 176,042 $ 24,348 $ 205,108 Current $ 17,951 $ 130,153 $ 21,178 $ 142,195 Long-term 3,137 45,889 3,170 62,913 Total derivative contracts $ 21,088 $ 176,042 $ 24,348 $ 205,108 _______________ 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 Accounting Standards Codification (ASC) 980, “Regulated Operations” (ASC 980) due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 171.6 million One Million British Thermal Units (MMBtu) and purchased electricity of 4.1 million Megawatt Hours (MWhs) at June 30, 2015 , and 140.2 million MMBtus and 5.4 million MWhs at December 31, 2014 . For further details regarding the fair value of derivative instruments, see Note 4. 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. 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, 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 $ 21,088 $ — $ 21,088 $ (16,491 ) $ — $ 4,597 Liabilities Energy derivative contracts 167,748 — 167,748 (16,491 ) — 151,257 Interest rate swaps 2 8,294 — 8,294 — — 8,294 Puget Energy and Puget Sound Energy December 31, 2014 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 $ 24,348 $ — $ 24,348 $ (23,066 ) $ — $ 1,282 Liabilities Energy derivative contracts 196,035 — 196,035 (23,066 ) (20 ) 172,949 Interest rate swaps 2 9,073 — 9,073 — — 9,073 _______________ 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 not designated as hedging instruments, recorded on the statements of income: Puget Energy Three Months Ended Six Months Ended (Dollars in Thousands) Location 2015 2014 2015 2014 Interest rate contracts: Non-hedged interest rate swap (expense) income $ (1,440 ) $ (1,360 ) $ (3,415 ) $ (2,107 ) Interest expense 722 (718 ) 560 (843 ) Commodity contracts: Electric derivatives Unrealized gain (loss) on derivative instruments, net 1 8,232 17,094 11,928 24,934 Electric generation fuel (5,082 ) 864 (15,744 ) 8,691 Purchased electricity (4,261 ) (3,668 ) (26,145 ) 1,715 Total gain (loss) recognized in income on derivatives $ (1,829 ) $ 12,212 $ (32,816 ) $ 32,390 Puget Sound Energy Three Months Ended Six Months Ended (Dollars in Thousands) Location 2015 2014 2015 2014 Commodity contracts: Electric derivatives Unrealized gain (loss) on derivative instruments, net 1 $ 8,232 $ 17,094 $ 11,383 $ 24,364 Electric generation fuel (5,082 ) 864 (15,744 ) 8,691 Purchased electricity (4,261 ) (3,668 ) (26,145 ) 1,715 Total gain (loss) recognized in income on derivatives $ (1,111 ) $ 14,290 $ (30,506 ) $ 34,770 _______________ 1 Differences between Puget Energy and Puget Sound Energy for the six months ending June 30, 2015 and June 30, 2014 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 unrealized gain or loss on derivative contracts is reported in the statement of cash flows under the operating activities section. However, due to purchase accounting requirements, all derivative contracts at Puget Energy were assessed to identify contracts that have a “more than an insignificant” fair value. If the fair value was greater than 10% of the notional value, the contract was deemed as having a financing element. For those contracts, the cash inflows (outflows) are presented in the financing activities section of the statement of cash flows. For the six months ended June 30, 2015 and 2014 , cash outflows related to financing activities of $8.0 million , for both periods were reported on the Puget Energy statement of cash flows. For derivative instruments previously designated as cash flow hedges (including both commodity contracts and interest rate swaps), the effective portion of the gain or loss on the derivative was recorded as a component of Other Comprehensive Income (OCI), and then reclassified into earnings in the same period(s) during which the hedged transaction affected earnings. As of March 31, 2015 , all gains or losses on purchased electricity derivatives recorded in OCI have been reclassified into earnings. The Company does not attempt cash flow hedging for any new transactions and records all mark-to-market adjustments through earnings. The following tables present the Company's pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship, and subsequently reclassified out of Accumulated Other Comprehensive Income (AOCI) into income: Puget Energy Three Months Ended Six Months Ended (Dollars in Thousands) Location 2015 2014 2015 2014 Interest rate contracts: Interest expense $ — $ — $ — $ (144 ) Commodity contracts: Electric derivatives Purchased electricity — — (512 ) (534 ) Total $ — $ — $ (512 ) $ (678 ) Puget Sound Energy Three Months Ended Six Months Ended (Dollars in Thousands) Location 2015 2014 2015 2014 Interest rate contracts: Interest expense 1 $ (122 ) $ (122 ) $ (244 ) $ (244 ) Commodity contracts: Electric derivatives Purchased electricity — — (1,055 ) (1,104 ) Total $ (122 ) $ (122 ) $ (1,299 ) $ (1,348 ) _______________ 1 Within the next twelve months, $0.5 million of losses in AOCI will be reclassified into earnings. 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, 2015 , approximately 99.8% of the Company's energy portfolio exposure, excluding NPNS transactions, is with counterparties that are rated at least investment grade by rating agencies and 0.2% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies. The Company computes credit reserves at a master agreement level by counterparty. The Company considers external credit ratings and market factors, such as credit default swaps and bond spreads, in the determination of reserves. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels. The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are booked as contra accounts to unrealized gain (loss) positions. As of June 30, 2015 , 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, 2015 , 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 quarter ended June 30, 2015 , 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, 2015 : Puget Energy and Puget Sound Energy Contingent Feature Fair Value 1 Posted Contingent (Dollars in Thousands) Liability Collateral Collateral Credit rating 2 $ 29,332 $ — $ 29,332 Requested credit for adequate assurance 57,214 — — Forward value of contract 3 — — — Total $ 86,546 $ — $ 29,332 _______________ 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, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements ASC 820 established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy categorizes the inputs into three levels with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority given to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows: Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Equity securities that are also classified as cash equivalents are considered Level 1 if there are unadjusted quoted prices in active markets for identical assets or liabilities. Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options. Level 3 - Pricing inputs include significant inputs that have little or no observability as of the reporting date. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves, contract terms and prices, credit-risk adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas market 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. Management's assessment was based on the trading activity in real-time and forward electric and natural gas markets. Each quarter, the Company confirms the validity of pricing-service quoted prices (e.g., Level 2 in the fair value hierarchy) used to value commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes are classified as Level 3 in the fair value hierarchy. Assets and Liabilities with Estimated Fair Value The following table presents the fair value hierarchy by level and the carrying value for cash, cash equivalents, restricted cash, notes receivable and short-term debt. 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, 2015 At December 31, 2014 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Cash and cash equivalents $ 14,535 $ — $ 14,535 $ 37,527 $ — $ 37,527 Restricted cash 7,964 — 7,964 32,863 — 32,863 Notes receivable and other investments — 50,830 50,830 — 53,503 53,503 Total assets $ 22,499 $ 50,830 $ 73,329 $ 70,390 $ 53,503 $ 123,893 Liabilities: Short-term debt $ — $ — $ — $ 85,000 $ — $ 85,000 Total liabilities $ — $ — $ — $ 85,000 $ — $ 85,000 Carrying / Fair Value Carrying / Fair Value Puget Sound Energy At June 30, 2015 At December 31, 2014 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Cash and cash equivalents $ 13,320 $ — $ 13,320 $ 37,466 $ — $ 37,466 Restricted cash 7,964 — 7,964 32,863 — 32,863 Notes receivable and other investments — 50,830 50,830 — 53,503 53,503 Total assets $ 21,284 $ 50,830 $ 72,114 $ 70,329 $ 53,503 $ 123,832 Liabilities: Short-term debt $ — $ — $ — $ 85,000 $ — $ 85,000 Short-term debt owed to parent — — — — 28,933 28,933 Total liabilities $ — $ — $ — $ 85,000 $ 28,933 $ 113,933 The fair value of the junior subordinated and long-term notes were estimated using the discounted cash flow method with U.S. Treasury yields and 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, 2015 December 31, 2014 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 159,346 $ 250,000 $ 276,235 Long-term debt (fixed-rate), net of discount 2 5,123,567 6,227,669 4,694,608 6,083,554 Long-term debt (variable-rate) 2 — — 299,000 299,000 Total $ 5,373,567 $ 6,387,015 $ 5,243,608 $ 6,658,789 Puget Sound Energy June 30, 2015 December 31, 2014 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 159,346 $ 250,000 $ 276,235 Long-term debt (fixed-rate), net of discount 2 3,536,353 4,226,899 3,513,259 4,437,473 Total $ 3,786,353 $ 4,386,245 $ 3,763,259 $ 4,713,708 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: Puget Energy Fair Value Fair Value At June 30, 2015 At December 31, 2014 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Interest rate derivative instruments $ 8,294 $ — $ 8,294 $ 9,073 $ — $ 9,073 Total derivative liabilities $ 8,294 $ — $ 8,294 $ 9,073 $ — $ 9,073 Puget Energy and Fair Value Fair Value Puget Sound Energy At June 30, 2015 At December 31, 2014 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 8,777 $ 2,672 $ 11,449 $ 1,654 $ 3,168 $ 4,822 Natural gas derivative instruments 5,340 4,299 9,639 18,064 1,462 19,526 Total assets $ 14,117 $ 6,971 $ 21,088 $ 19,718 $ 4,630 $ 24,348 Liabilities: Electric derivative instruments $ 83,374 $ 18,042 $ 101,416 $ 91,998 $ 15,230 $ 107,228 Natural gas derivative instruments 62,856 3,476 66,332 85,305 3,502 88,807 Total liabilities $ 146,230 $ 21,518 $ 167,748 $ 177,303 $ 18,732 $ 196,035 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 Level 3 Roll-Forward Net Asset/(Liability) 2015 2014 (Dollars in Thousands) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ (16,091 ) $ (1,601 ) $ (17,692 ) $ (14,606 ) $ (1,103 ) $ (15,709 ) Changes during period: Realized and unrealized energy derivatives: Included in earnings 1 (4,064 ) — (4,064 ) 7,800 — 7,800 Included in regulatory assets / liabilities — 2,813 2,813 — 2,120 2,120 Settlements 3 52 (389 ) (337 ) 1,757 (166 ) 1,591 Transferred into Level 3 — — — — — — Transferred out of Level 3 4,733 — 4,733 356 (1,124 ) (768 ) Balance at end of period $ (15,370 ) $ 823 $ (14,547 ) $ (4,693 ) $ (273 ) $ (4,966 ) Puget Energy and Puget Sound Energy Six Months Ended Level 3 Roll-Forward Net Asset/(Liability) 2015 2014 (Dollars in Thousands) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ (12,061 ) $ (2,039 ) $ (14,100 ) $ (15,421 ) $ (361 ) $ (15,782 ) Changes during period: Realized and unrealized energy derivatives: Included in earnings 2 (9,102 ) — (9,102 ) 5,055 — 5,055 Included in regulatory assets / liabilities — 2,938 2,938 — 2,379 2,379 Settlements 3 165 (298 ) (133 ) 2,078 (576 ) 1,502 Transferred into Level 3 (787 ) — (787 ) 3,100 (585 ) 2,515 Transferred out of Level 3 6,415 222 6,637 495 (1,130 ) (635 ) Balance at end of period $ (15,370 ) $ 823 $ (14,547 ) $ (4,693 ) $ (273 ) $ (4,966 ) _______________ 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 $(3.8) million and $4.7 million for the three months ended June 30, 2015 and 2014 , 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 $(8.8) million and $0.1 million for the six months ended June 30, 2015 and 2014 , respectively. 3 The Company had no purchases, sales or issuances during the reported periods. Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company's consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company's consolidated statements of income. In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company's commodity contracts extend beyond what is considered observable as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next, and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month, and reported in the Level 3 Roll-Forward table above. The Company did not have any transfers between Level 2 and Level 1 during the 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 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 purchased commodity contracts as of June 30, 2015 : Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 2,672 $ 18,042 Discounted cash flow Power Prices $15.17 per MWh $38.00 per MWh $28.03 per MWh Natural gas $ 4,299 $ 3,476 Discounted cash flow Natural Gas Prices $1.71 per MMBtu $3.54 per MMBtu $2.79 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 purchased commodity contracts, as of December 31, 2014 : Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 3,168 $ 15,230 Discounted cash flow Power Prices $21.79 per MWh $35.46 per MWh $32.89 per MWh Natural gas $ 1,462 $ 3,502 Discounted cash flow Natural Gas Prices $3.11 per MMBtu $3.83 per MMBtu $3.28 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, 2015 and December 31, 2014 , 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 $3.8 million and $3.9 million , respectively.

Retirement Benefits

Retirement Benefits	6 Months Ended
	Jun. 30, 2015
Compensation and Retirement Disclosure [Abstract]
Retirement Benefits	Retirement Benefits PSE has a defined benefit pension plan covering substantially all 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. All new United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry employees hired on or after January 1, 2014, as well as all new International Brotherhood of Electrical Workers Local Union 77 hired on or after December 12, 2014 and non-represented employees hired on or after January 1, 2014 who elect to accumulate the Company contribution in the cash balance formula portion of the pension plan, will receive annual pay credits of 4% each year. They will also receive interest credits like other participants in the cash balance pension formula of the pension plan, which are at least 1% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, he or she will have annuity and lump sum options for distribution. Those who select the lump sum option will receive their current cash balance amount. PSE also maintains a non-qualified Supplemental Executive Retirement Plan (SERP) for its key senior management employees. In addition to providing pension benefits, PSE provides a legacy group health care and life insurance 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. Purchase accounting adjustments associated with the re-measurement of the retirement plans are recorded at Puget Energy. The following tables summarize the Company’s net periodic benefit cost for the three and six months ended June 30, 2015 and 2014 : Puget Energy Qualified SERP Other Three Months Ended (Dollars in Thousands) 2015 2014 2015 2014 2015 2014 Components of net periodic benefit cost: Service cost $ 5,172 $ 4,206 $ 277 $ 261 $ 23 $ 26 Interest cost 6,937 6,965 570 577 150 159 Expected return on plan assets (11,117 ) (10,511 ) — — (133 ) (134 ) Amortization of prior service (495 ) (495 ) 11 11 — — Amortization of net loss 962 — 410 228 (51 ) (130 ) Net periodic benefit cost $ 1,459 $ 165 $ 1,268 $ 1,077 $ (11 ) $ (79 ) Puget Energy Qualified SERP Other Six Months Ended (Dollars in Thousands) 2015 2014 2015 2014 2015 2014 Components of net periodic benefit cost: Service cost $ 10,644 $ 8,718 $ 554 $ 521 $ 56 $ 56 Interest cost 14,044 14,020 1,140 1,155 311 342 Expected return on plan assets (22,519 ) (21,232 ) — — (266 ) (267 ) Amortization of prior service (990 ) (990 ) 22 22 — (197 ) Amortization of net loss 1,943 — 820 456 (66 ) — Net periodic benefit cost $ 3,122 $ 516 $ 2,536 $ 2,154 $ 35 $ (66 ) Puget Sound Energy Qualified SERP Other Pension Benefits Pension Benefits Benefits Three Months Ended (Dollars in Thousands) 2015 2014 2015 2014 2015 2014 Components of net periodic benefit cost: Service cost $ 5,172 $ 4,206 $ 277 $ 261 $ 23 $ 26 Interest cost 6,937 6,965 570 577 150 159 Expected return on plan assets (11,223 ) (10,708 ) — — (133 ) (134 ) Amortization of prior service (393 ) (393 ) 11 11 1 1 Amortization of net loss 5,141 3,359 530 365 (120 ) (208 ) Net periodic benefit cost $ 5,634 $ 3,429 $ 1,388 $ 1,214 $ (79 ) $ (156 ) Puget Sound Energy Qualified SERP Other Pension Benefits Pension Benefits Benefits Six Months Ended (Dollars in Thousands) 2015 2014 2015 2014 2015 2014 Components of net periodic benefit cost: Service cost $ 10,644 $ 8,718 $ 554 $ 521 $ 56 $ 56 Interest cost 14,044 14,020 1,140 1,155 311 342 Expected return on plan assets (22,731 ) (21,626 ) — — (266 ) (267 ) Amortization of prior service (786 ) (786 ) 22 22 2 2 Amortization of net loss 10,277 6,597 1,060 730 (203 ) (352 ) Net periodic benefit cost $ 11,448 $ 6,923 $ 2,776 $ 2,428 $ (100 ) $ (219 ) The following table summarizes the Company’s change in benefit obligation for the periods ended June 30, 2015 and December 31, 2014 : 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 $ 690,194 $ 573,317 $ 55,855 $ 47,279 $ 15,688 $ 14,939 Service cost 10,644 17,437 554 1,042 56 112 Interest cost 14,044 28,039 1,140 2,310 311 684 Actuarial loss (gain) (588 ) 104,618 — 7,162 (540 ) 1,108 Benefits paid (27,869 ) (33,217 ) (2,565 ) (1,938 ) (703 ) (1,424 ) Medicare part D subsidy — — — — 221 269 Benefit obligation at end of period $ 686,425 $ 690,194 $ 54,984 $ 55,855 $ 15,033 $ 15,688 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, 2015 are expected to be at least $18.0 million , $4.4 million and $0.4 million , respectively. During the three months ended June 30, 2015 , the Company contributed $4.5 million , $0.5 million , and $0.2 million to fund the qualified pension plan, SERP and other postretirement plan, respectively. During the six months ended June 30, 2015 , the Company contributed $9.0 million , $2.6 million , and $0.4 million to fund the qualified pension plan, SERP and other postretirement plan, respectively.

Regulation and Rates

Regulation and Rates	6 Months Ended
	Jun. 30, 2015
Regulation and Rates [Abstract]
Regulation and Rates	Regulation and Rates On June 25, 2013, the Washington Commission approved PSE's electric and natural gas decoupling mechanism and Expedited Rate Filing (ERF) tariff filings, effective July 1, 2013. The allowed decoupling revenue per customer for the recovery of delivery system costs will subsequently increase by 3.0% for the electric customers and 2.2% for the gas customers on January 1 of each year, until the conclusion of PSE's next General Rate Case (GRC). Rate increases are subject to a cap of 3.0% of total revenue for customers. The ERF filings also provided for the collection of property taxes through a property tax tracker mechanism. The property tax rate tracker will initially produce no incremental revenue, but is intended to reduce regulatory lag associated with the recovery of future increases in property tax expenses. On July 24, 2013, the Public Counsel Division of the Washington State Attorney General's Office (Public Counsel) and the Industrial Customers of Northwest Utilities each filed a petition in Thurston County Superior Court (the Court) seeking judicial reviews of various aspects of the Washington Commission's ERF and decoupling mechanism final order. In its order, the Washington Commission approved a weighted cost of capital of 7.77% and a capital structure that included 48.0% common equity with a return on equity of 9.8% . The parties' petitions argued that the order violated various procedural and substantive requirements of the Washington Administrative Procedure Act, and so requested that it be vacated and that the matter be remanded to the Washington Commission. Oral arguments regarding this matter were held on May 9, 2014. On June 25, 2014, the court issued a decision in which it affirmed the attrition adjustment (escalating factors referred to as the K-Factor) and the Washington Commission's decision not to consider the case as a GRC, but reversed and remanded the cost of equity for further adjudication consistent with the court's decision. In the remand proceeding evidentiary hearings regarding return on equity were held in February 2015, and initial briefs and reply briefs were filed in March 2015. The Washington Commission issued a final order on remand on June 29, 2015, in which it found that 9.8% is a reasonable return on equity for PSE for the term of the rate plan, taking decoupling and other relevant factors into account. On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2014. The rate change incorporated the effects of an increase to the allowed delivery revenue per customer as well as true-ups to the rate from the prior year. This represents a rate increase for electric customers of $10.6 million , or 0.5% annually, and a rate decrease for natural gas customers of $1.0 million , or 0.1% annually. On April 24, 2014, the Washington Commission approved PSE’s request to change rates under its electric and natural gas property tax tracker mechanism, effective May 1, 2014. The rate change incorporated the effects of an increase in the amount of property taxes paid as well as true-ups to the rate from the prior year. This represents a rate increase for electric customers of $11.0 million , or 0.5% annually, and a rate increase for natural gas customers of $5.6 million , or 0.6% annually. On April 24, 2014, the Washington Commission also approved PSE’s request to change rates under its electric and natural gas conservation riders, effective May 1, 2014. The rate change incorporated the effects of changes in the annual conservation budgets as well as true-ups to the rate from the prior year. The rate change represents a rate increase for electric customers of $12.2 million , or 0.6% annually, and a rate increase for natural gas customers of $0.3 million . On October 30, 2014, the Washington Commission approved the PGA natural gas tariff which proposed to reflect changes in wholesale gas and pipeline transportation costs and changes in deferral amortization rates. The impact of PGA rates is an annual revenue increase of $23.3 million , or 2.5% , with no impact on net operating income. On November 3, 2014, the Washington Commission issued an order approving the settlement of the Power Cost Only Rate Case (PCORC) which was filed on May 23, 2014. The original filing proposed a decrease of $9.6 million (or an average of approximately 0.5% ) in the Company's overall power supply costs. PSE filed joint testimony supporting a settlement stipulation. Customer rates decreased by approximately $19.4 million , or 0.9% annually, as a result of the settlement, effective December 1, 2014. On March 26, 2015, PSE filed a request with the Washington Commission to change rates under its electric and natural gas property tax tracker mechanism, effective May 1, 2015. PSE filed a substitute filing with the Washington Commission on April 15, 2015 for the electric property tax tracker mechanism. The proposed rate change incorporates the effects of an increase to property taxes paid, as well as true-ups to the rate from the prior year. This represents a rate increase for electric customers of $6.5 million , or 0.3% annually. PSE made a subsequent substitute natural gas filing with the Washington Commission on May 1, 2015, which changed the rate effective date to June 1, 2015, and represented a rate decrease for natural gas customers of $2.3 million , or 0.2% annually. On March 27, 2015, PSE, Public Counsel and the Washington Commission Staff filed a settlement proposing changes to the current PCA mechanism. The settling parties filed joint testimony supporting the settlement agreement on April 3, 2015. The settlement agreement will require the Washington Commission's approval. The settlement agreement would not take effect until January 1, 2017. Key components of the settlement will include the following changes to the PCA mechanism: Company's Share Customers' Share Annual Power Cost Variability Over Under Over Under +/- $17 million 100 % 100 % — % — % +/- $17 million - $40 million 35 50 65 50 +/- $40+ million 10 10 90 90 • Reducing the cumulative deferral trigger for surcharge or refund from $30.0 million to $20.0 million ; • Removing fixed production costs from the PCA mechanism and placing them in the decoupling mechanism if the decoupling mechanism continues as part of the next GRC; • Suspending the requirement that a GRC must be filed within three months after rates are approved in a PCORC, and agreeing, for a five-year period, that PSE will not file a GRC or PCORC within six months of the date that rates go into effect for a PCORC filing; • Establishing a five-year moratorium on changes to the PCA/PCORC. 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.

Asset Retirement Obligation

Asset Retirement Obligation	6 Months Ended
	Jun. 30, 2015
Text Block [Abstract]
Asset Retirement Obligation Disclosure [Text Block]	Asset Retirement Obligation The Company has recorded liabilities for steam generation sites, combustion turbine generation sites, wind generation sites, distribution and transmission poles, gas mains, and leased facilities where disposal is governed by ASC 410 “Asset Retirement and Environmental Obligations (ARO)”. On April 17, 2015, the United States Environmental Protection Agency (EPA) published a final rule, effective October 14, 2015, that regulates Coal Combustion Residuals (CCRs) under the Resource Conservation and Recovery Act , Subtitle D. The CCR ruling requires the company to perform an extensive study on the effects of coal ash on the environment and public health. The rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments. The rule becomes effective six months after the publication date, on October 14, 2015. The CCR rule makes significant changes to the Company’s Colstrip operations and those changes were reviewed by the Company and the plant operator in the second quarter of 2015. PSE had previously recognized a legal obligation under EPA rules to dispose of coal ash material at Colstrip, in 2003. Due to the CCR rule, additional disposal costs will be 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. The following table describes all changes to the Company’s asset retirement obligation for the period December 31, 2014 through June 30, 2015 : Puget Sound Energy (Dollars in Thousands) Asset retirement obligation at beginning of period $ 48,909 New asset retirement obligation recognized in the period 34,534 Liability adjustments (15 ) Revisions in estimated cash flows 450 Accretion expense 710 Asset retirement obligation at end of period $ 84,588

Contingencies

Contingencies	6 Months Ended
	Jun. 30, 2015
Text Block [Abstract]
Legal Matters and Contingencies [Text Block]	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, plaintiffs' lawsuit currently alleges 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 2001-2012. Plaintiffs have since indicated that they do not intend to pursue three of the seven projects, leaving a total of four projects remaining. The lawsuit claims that, for each project, the Colstrip plant should have obtained a permit and installed pollution control equipment at Colstrip. The Plaintiffs' complaint also seeks civil penalties and other appropriate relief. The case has been bifurcated into separate liability and remedy trials. The liability trial is currently set for November 2015, and a date for the remedy trial has yet to be determined. PSE is litigating the allegations set forth in the complaint, and as such, it is not reasonably possible to estimate the outcome of this matter. Other Proceedings The Company is also involved in litigation relating to claims arising out of its operations in the normal course of business. The Company has recorded reserves of $0.7 million and $1.7 million relating to these claims as of June 30, 2015 and December 31, 2014 , respectively.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	6 Months Ended
	Jun. 30, 2015
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss) The following tables present the changes in the Company’s AOCI (loss) by component for the three and six months ended June 30, 2015 : Puget Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on energy derivative instruments Changes in AOCI, net of tax (Dollars in Thousands) Total March 31, 2015 $ (36,131 ) $ — $ (36,131 ) Other comprehensive income (loss) before reclassifications — — — Amounts reclassified from accumulated other comprehensive income (loss), net of tax 1,277 — 1,277 Net current-period other comprehensive income (loss) 1,277 — 1,277 June 30, 2015 $ (34,854 ) $ — $ (34,854 ) Puget Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on energy derivative instruments Changes in AOCI, net of tax (Dollars in Thousands) Total December 31, 2014 $ (36,710 ) $ (333 ) $ (37,043 ) Other comprehensive income (loss) before reclassifications — — — Amounts reclassified from accumulated other comprehensive income (loss), net of tax 1,856 333 2,189 Net current-period other comprehensive income (loss) 1,856 333 2,189 June 30, 2015 $ (34,854 ) $ — $ (34,854 ) Puget Sound Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on energy derivative instruments Net unrealized gain (loss) on treasury interest rate swaps Changes in AOCI, net of tax (Dollars in Thousands) Total March 31, 2015 $ (160,900 ) $ — $ (5,911 ) $ (166,811 ) Other comprehensive income (loss) before reclassifications — — — — Amounts reclassified from accumulated other comprehensive income (loss), net of tax 4,094 — 79 4,173 Net current-period other comprehensive income (loss) 4,094 — 79 4,173 June 30, 2015 $ (156,806 ) $ — $ (5,832 ) $ (162,638 ) Puget Sound Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on energy derivative instruments Net unrealized gain (loss) on treasury interest rate swaps Changes in AOCI, net of tax (Dollars in Thousands) Total December 31, 2014 $ (164,281 ) $ (686 ) $ (5,990 ) $ (170,957 ) Other comprehensive income (loss) before reclassifications — — — — Amounts reclassified from accumulated other comprehensive income (loss), net of tax 7,475 686 158 8,319 Net current-period other comprehensive income (loss) 7,475 686 158 8,319 June 30, 2015 $ (156,806 ) $ — $ (5,832 ) $ (162,638 ) Details about these reclassifications out of AOCI for the three and six months ended June 30, 2015 , and 2014 , are as follows: Puget Energy Three Months Ended Six Months Ended (Dollars in Thousands) 2015 2014 2015 2014 Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented Amount reclassified from accumulated other comprehensive income (loss) Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 484 $ 484 $ 969 $ 1,165 Amortization of net gain (loss) (a) (2,449 ) (98 ) (3,825 ) (456 ) Total before tax (1,965 ) 386 (2,856 ) 709 Tax (expense) or benefit 688 (135 ) 1,000 (248 ) Net of Tax $ (1,277 ) $ 251 $ (1,856 ) $ 461 Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: electric derivatives Purchased electricity — — (512 ) (534 ) Tax (expense) or benefit — — 179 187 Net of Tax $ — $ — $ (333 ) $ (347 ) Net unrealized gain (loss) on interest rate swaps: Interest rate contracts Interest expense — — — (144 ) Tax (expense) or benefit — — — 50 Net of Tax $ — $ — $ — $ (94 ) Total reclassification for the period Net of Tax $ (1,277 ) $ 251 $ (2,189 ) $ 20 _______________ (a) These AOCI components are included in the computation of net periodic pension cost (see Note 5 for additional details). Puget Sound Energy Three Months Ended Six Months Ended (Dollars in Thousands) 2015 2014 2015 2014 Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented Amount reclassified from accumulated other comprehensive income (loss) Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 381 $ 381 $ 762 $ 762 Amortization of net gain (loss) (a) (6,679 ) (3,516 ) (12,262 ) (6,975 ) Total before tax (6,298 ) (3,135 ) (11,500 ) (6,213 ) Tax (expense) or benefit 2,204 1,097 4,025 2,175 Net of Tax $ (4,094 ) $ (2,038 ) $ (7,475 ) $ (4,038 ) Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: electric derivatives Purchased electricity — — (1,055 ) (1,104 ) Tax (expense) or benefit — — 369 386 Net of Tax $ — $ — $ (686 ) $ (718 ) Net unrealized gain (loss) on treasury interest rate swaps: Interest rate contracts Interest expense (122 ) (122 ) (244 ) (244 ) Tax (expense) or benefit 43 43 86 86 Net of Tax $ (79 ) $ (79 ) $ (158 ) $ (158 ) Total reclassification for the period Net of Tax $ (4,173 ) $ (2,117 ) $ (8,319 ) $ (4,914 ) _______________ (a) These AOCI components are included in the computation of net periodic pension cost (see Note 5 for additional details).

Other

Other	6 Months Ended
	Jun. 30, 2015
Other [Abstract]
Other Material Items [Text Block]	Other Long-Term Debt On May 26, 2015, PSE issued $425.0 million of senior notes secured by first mortgage bonds. The notes mature in May 2045 and have an interest rate of 4.30% , which is payable semi-annually in May and November. Net proceeds of the issuance were used to fund the early retirement, including accrued interest and make-whole call premiums, of PSE's $150.0 million 5.197% senior notes maturing in October 2015 and PSE's $250.0 million 6.75% senior notes maturing in January 2016. On May 12, 2015, Puget Energy issued $400.0 million of senior secured notes. The notes mature in May 2025 and have an interest rate of 3.65% , which is payable semi-annually in May and November. Net proceeds of the issuance were used to repay $299.1 million principal amount outstanding under Puget Energy's term loans, as well as accrued interest, and to fund a special dividend to shareholders of approximately $96.7 million .

Accounting for Derivative Ins18

Accounting for Derivative Instruments and Hedging Activities (Tables)	6 Months Ended
	Jun. 30, 2015
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, 2015 December 31, 2014 (Dollars in Thousands) Volumes Assets 1 Liabilities 2 Volumes Assets 1 Liabilities 2 Interest rate swap derivatives 3 $450 million $ — $ 8,294 $450 million $ — $ 9,073 Electric portfolio derivatives * 11,449 101,416 * 4,822 107,228 Natural gas derivatives (MMBtus) 4 343.0 million 9,639 66,332 360.4 million 19,526 88,807 Total derivative contracts $ 21,088 $ 176,042 $ 24,348 $ 205,108 Current $ 17,951 $ 130,153 $ 21,178 $ 142,195 Long-term 3,137 45,889 3,170 62,913 Total derivative contracts $ 21,088 $ 176,042 $ 24,348 $ 205,108 _______________ 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 Accounting Standards Codification (ASC) 980, “Regulated Operations” (ASC 980) due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 171.6 million One Million British Thermal Units (MMBtu) and purchased electricity of 4.1 million Megawatt Hours (MWhs) at June 30, 2015 , and 140.2 million MMBtus and 5.4 million MWhs at December 31, 2014 .
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, 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 $ 21,088 $ — $ 21,088 $ (16,491 ) $ — $ 4,597 Liabilities Energy derivative contracts 167,748 — 167,748 (16,491 ) — 151,257 Interest rate swaps 2 8,294 — 8,294 — — 8,294 Puget Energy and Puget Sound Energy December 31, 2014 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 $ 24,348 $ — $ 24,348 $ (23,066 ) $ — $ 1,282 Liabilities Energy derivative contracts 196,035 — 196,035 (23,066 ) (20 ) 172,949 Interest rate swaps 2 9,073 — 9,073 — — 9,073 _______________ 1 All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off. 2 Interest rate swap contracts are only held at Puget Energy.
Schedule of Derivative Instruments, Effect on Other Comprehensive Income (Loss)	The following tables present the Company's pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship, and subsequently reclassified out of Accumulated Other Comprehensive Income (AOCI) into income: Puget Energy Three Months Ended Six Months Ended (Dollars in Thousands) Location 2015 2014 2015 2014 Interest rate contracts: Interest expense $ — $ — $ — $ (144 ) Commodity contracts: Electric derivatives Purchased electricity — — (512 ) (534 ) Total $ — $ — $ (512 ) $ (678 )
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, 2015 : Puget Energy and Puget Sound Energy Contingent Feature Fair Value 1 Posted Contingent (Dollars in Thousands) Liability Collateral Collateral Credit rating 2 $ 29,332 $ — $ 29,332 Requested credit for adequate assurance 57,214 — — Forward value of contract 3 — — — Total $ 86,546 $ — $ 29,332 _______________ 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 not designated as hedging instruments, recorded on the statements of income: Puget Energy Three Months Ended Six Months Ended (Dollars in Thousands) Location 2015 2014 2015 2014 Interest rate contracts: Non-hedged interest rate swap (expense) income $ (1,440 ) $ (1,360 ) $ (3,415 ) $ (2,107 ) Interest expense 722 (718 ) 560 (843 ) Commodity contracts: Electric derivatives Unrealized gain (loss) on derivative instruments, net 1 8,232 17,094 11,928 24,934 Electric generation fuel (5,082 ) 864 (15,744 ) 8,691 Purchased electricity (4,261 ) (3,668 ) (26,145 ) 1,715 Total gain (loss) recognized in income on derivatives $ (1,829 ) $ 12,212 $ (32,816 ) $ 32,390
Subsidiaries [Member]
Derivative [Line Items]
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance	Puget Sound Energy Three Months Ended Six Months Ended (Dollars in Thousands) Location 2015 2014 2015 2014 Commodity contracts: Electric derivatives Unrealized gain (loss) on derivative instruments, net 1 $ 8,232 $ 17,094 $ 11,383 $ 24,364 Electric generation fuel (5,082 ) 864 (15,744 ) 8,691 Purchased electricity (4,261 ) (3,668 ) (26,145 ) 1,715 Total gain (loss) recognized in income on derivatives $ (1,111 ) $ 14,290 $ (30,506 ) $ 34,770 _______________ 1 Differences between Puget Energy and Puget Sound Energy for the six months ending June 30, 2015 and June 30, 2014 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.
Schedule of Derivative Instruments, Effect on Other Comprehensive Income (Loss)	Puget Sound Energy Three Months Ended Six Months Ended (Dollars in Thousands) Location 2015 2014 2015 2014 Interest rate contracts: Interest expense 1 $ (122 ) $ (122 ) $ (244 ) $ (244 ) Commodity contracts: Electric derivatives Purchased electricity — — (1,055 ) (1,104 ) Total $ (122 ) $ (122 ) $ (1,299 ) $ (1,348 ) _______________ 1 Within the next twelve months, $0.5 million of losses in AOCI will be reclassified into earnings.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, by Balance Sheet Grouping	The following table presents the fair value hierarchy by level and the carrying value for cash, cash equivalents, restricted cash, notes receivable and short-term debt. 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, 2015 At December 31, 2014 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Cash and cash equivalents $ 14,535 $ — $ 14,535 $ 37,527 $ — $ 37,527 Restricted cash 7,964 — 7,964 32,863 — 32,863 Notes receivable and other investments — 50,830 50,830 — 53,503 53,503 Total assets $ 22,499 $ 50,830 $ 73,329 $ 70,390 $ 53,503 $ 123,893 Liabilities: Short-term debt $ — $ — $ — $ 85,000 $ — $ 85,000 Total liabilities $ — $ — $ — $ 85,000 $ — $ 85,000 Carrying / Fair Value Carrying / Fair Value Puget Sound Energy At June 30, 2015 At December 31, 2014 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Cash and cash equivalents $ 13,320 $ — $ 13,320 $ 37,466 $ — $ 37,466 Restricted cash 7,964 — 7,964 32,863 — 32,863 Notes receivable and other investments — 50,830 50,830 — 53,503 53,503 Total assets $ 21,284 $ 50,830 $ 72,114 $ 70,329 $ 53,503 $ 123,832 Liabilities: Short-term debt $ — $ — $ — $ 85,000 $ — $ 85,000 Short-term debt owed to parent — — — — 28,933 28,933 Total liabilities $ — $ — $ — $ 85,000 $ 28,933 $ 113,933
Fair Value Inputs, Liabilities, Quantitative Information	The fair value of the junior subordinated and long-term notes were estimated using the discounted cash flow method with U.S. Treasury yields and 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, 2015 December 31, 2014 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 159,346 $ 250,000 $ 276,235 Long-term debt (fixed-rate), net of discount 2 5,123,567 6,227,669 4,694,608 6,083,554 Long-term debt (variable-rate) 2 — — 299,000 299,000 Total $ 5,373,567 $ 6,387,015 $ 5,243,608 $ 6,658,789 Puget Sound Energy June 30, 2015 December 31, 2014 (Dollars in Thousands) Level Carrying Value Fair Value Carrying Value Fair Value Liabilities: Junior subordinated notes 2 $ 250,000 $ 159,346 $ 250,000 $ 276,235 Long-term debt (fixed-rate), net of discount 2 3,536,353 4,226,899 3,513,259 4,437,473 Total $ 3,786,353 $ 4,386,245 $ 3,763,259 $ 4,713,708
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 Level 3 Roll-Forward Net Asset/(Liability) 2015 2014 (Dollars in Thousands) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ (16,091 ) $ (1,601 ) $ (17,692 ) $ (14,606 ) $ (1,103 ) $ (15,709 ) Changes during period: Realized and unrealized energy derivatives: Included in earnings 1 (4,064 ) — (4,064 ) 7,800 — 7,800 Included in regulatory assets / liabilities — 2,813 2,813 — 2,120 2,120 Settlements 3 52 (389 ) (337 ) 1,757 (166 ) 1,591 Transferred into Level 3 — — — — — — Transferred out of Level 3 4,733 — 4,733 356 (1,124 ) (768 ) Balance at end of period $ (15,370 ) $ 823 $ (14,547 ) $ (4,693 ) $ (273 ) $ (4,966 ) Puget Energy and Puget Sound Energy Six Months Ended Level 3 Roll-Forward Net Asset/(Liability) 2015 2014 (Dollars in Thousands) Electric Natural Gas Total Electric Natural Gas Total Balance at beginning of period $ (12,061 ) $ (2,039 ) $ (14,100 ) $ (15,421 ) $ (361 ) $ (15,782 ) Changes during period: Realized and unrealized energy derivatives: Included in earnings 2 (9,102 ) — (9,102 ) 5,055 — 5,055 Included in regulatory assets / liabilities — 2,938 2,938 — 2,379 2,379 Settlements 3 165 (298 ) (133 ) 2,078 (576 ) 1,502 Transferred into Level 3 (787 ) — (787 ) 3,100 (585 ) 2,515 Transferred out of Level 3 6,415 222 6,637 495 (1,130 ) (635 ) Balance at end of period $ (15,370 ) $ 823 $ (14,547 ) $ (4,693 ) $ (273 ) $ (4,966 ) _______________ 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 $(3.8) million and $4.7 million for the three months ended June 30, 2015 and 2014 , 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 $(8.8) million and $0.1 million for the six months ended June 30, 2015 and 2014 , respectively. 3 The Company had no purchases, sales or issuances during the reported periods.
Fair Value Inputs, Assets and Liabilities, Quantitative Information	The following table presents the forward price ranges for the Company's purchased commodity contracts as of June 30, 2015 : Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 2,672 $ 18,042 Discounted cash flow Power Prices $15.17 per MWh $38.00 per MWh $28.03 per MWh Natural gas $ 4,299 $ 3,476 Discounted cash flow Natural Gas Prices $1.71 per MMBtu $3.54 per MMBtu $2.79 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 purchased commodity contracts, as of December 31, 2014 : Fair Value Range (Dollars in Thousands) Assets 1 Liabilities 1 Valuation Technique Unobservable Input Low High Weighted Average Electric $ 3,168 $ 15,230 Discounted cash flow Power Prices $21.79 per MWh $35.46 per MWh $32.89 per MWh Natural gas $ 1,462 $ 3,502 Discounted cash flow Natural Gas Prices $3.11 per MMBtu $3.83 per MMBtu $3.28 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, 2015 and December 31, 2014 , 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 $3.8 million and $3.9 million , respectively.
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: Puget Energy Fair Value Fair Value At June 30, 2015 At December 31, 2014 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Interest rate derivative instruments $ 8,294 $ — $ 8,294 $ 9,073 $ — $ 9,073 Total derivative liabilities $ 8,294 $ — $ 8,294 $ 9,073 $ — $ 9,073
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, 2015 At December 31, 2014 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 8,777 $ 2,672 $ 11,449 $ 1,654 $ 3,168 $ 4,822 Natural gas derivative instruments 5,340 4,299 9,639 18,064 1,462 19,526 Total assets $ 14,117 $ 6,971 $ 21,088 $ 19,718 $ 4,630 $ 24,348 Liabilities: Electric derivative instruments $ 83,374 $ 18,042 $ 101,416 $ 91,998 $ 15,230 $ 107,228 Natural gas derivative instruments 62,856 3,476 66,332 85,305 3,502 88,807 Total liabilities $ 146,230 $ 21,518 $ 167,748 $ 177,303 $ 18,732 $ 196,035

Retirement Benefits (Tables)

Retirement Benefits (Tables)	6 Months Ended
	Jun. 30, 2015
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, 2015 and December 31, 2014 : 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 $ 690,194 $ 573,317 $ 55,855 $ 47,279 $ 15,688 $ 14,939 Service cost 10,644 17,437 554 1,042 56 112 Interest cost 14,044 28,039 1,140 2,310 311 684 Actuarial loss (gain) (588 ) 104,618 — 7,162 (540 ) 1,108 Benefits paid (27,869 ) (33,217 ) (2,565 ) (1,938 ) (703 ) (1,424 ) Medicare part D subsidy — — — — 221 269 Benefit obligation at end of period $ 686,425 $ 690,194 $ 54,984 $ 55,855 $ 15,033 $ 15,688
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, 2015 and 2014 : Puget Energy Qualified SERP Other Three Months Ended (Dollars in Thousands) 2015 2014 2015 2014 2015 2014 Components of net periodic benefit cost: Service cost $ 5,172 $ 4,206 $ 277 $ 261 $ 23 $ 26 Interest cost 6,937 6,965 570 577 150 159 Expected return on plan assets (11,117 ) (10,511 ) — — (133 ) (134 ) Amortization of prior service (495 ) (495 ) 11 11 — — Amortization of net loss 962 — 410 228 (51 ) (130 ) Net periodic benefit cost $ 1,459 $ 165 $ 1,268 $ 1,077 $ (11 ) $ (79 ) Puget Energy Qualified SERP Other Six Months Ended (Dollars in Thousands) 2015 2014 2015 2014 2015 2014 Components of net periodic benefit cost: Service cost $ 10,644 $ 8,718 $ 554 $ 521 $ 56 $ 56 Interest cost 14,044 14,020 1,140 1,155 311 342 Expected return on plan assets (22,519 ) (21,232 ) — — (266 ) (267 ) Amortization of prior service (990 ) (990 ) 22 22 — (197 ) Amortization of net loss 1,943 — 820 456 (66 ) — Net periodic benefit cost $ 3,122 $ 516 $ 2,536 $ 2,154 $ 35 $ (66 )
Subsidiaries [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Schedule of Net Benefit Costs	Puget Sound Energy Qualified SERP Other Pension Benefits Pension Benefits Benefits Three Months Ended (Dollars in Thousands) 2015 2014 2015 2014 2015 2014 Components of net periodic benefit cost: Service cost $ 5,172 $ 4,206 $ 277 $ 261 $ 23 $ 26 Interest cost 6,937 6,965 570 577 150 159 Expected return on plan assets (11,223 ) (10,708 ) — — (133 ) (134 ) Amortization of prior service (393 ) (393 ) 11 11 1 1 Amortization of net loss 5,141 3,359 530 365 (120 ) (208 ) Net periodic benefit cost $ 5,634 $ 3,429 $ 1,388 $ 1,214 $ (79 ) $ (156 ) Puget Sound Energy Qualified SERP Other Pension Benefits Pension Benefits Benefits Six Months Ended (Dollars in Thousands) 2015 2014 2015 2014 2015 2014 Components of net periodic benefit cost: Service cost $ 10,644 $ 8,718 $ 554 $ 521 $ 56 $ 56 Interest cost 14,044 14,020 1,140 1,155 311 342 Expected return on plan assets (22,731 ) (21,626 ) — — (266 ) (267 ) Amortization of prior service (786 ) (786 ) 22 22 2 2 Amortization of net loss 10,277 6,597 1,060 730 (203 ) (352 ) Net periodic benefit cost $ 11,448 $ 6,923 $ 2,776 $ 2,428 $ (100 ) $ (219 )

Regulation and Rates Schedule o

Regulation and Rates Schedule of Graduated Sale of Rate Adjustment Mechanism (Tables)	6 Months Ended
	Jun. 30, 2015
Regulation and Rates [Abstract]
Schedule of Graduated Scale of Rate Adjustment Mechanisms [Table Text Block]	Key components of the settlement will include the following changes to the PCA mechanism: Company's Share Customers' Share Annual Power Cost Variability Over Under Over Under +/- $17 million 100 % 100 % — % — % +/- $17 million - $40 million 35 50 65 50 +/- $40+ million 10 10 90 90

Accumulated Other Comprehensi22

Accumulated Other Comprehensive Income (Tables)	6 Months Ended
	Jun. 30, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Schedule of Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss) The following tables present the changes in the Company’s AOCI (loss) by component for the three and six months ended June 30, 2015 : Puget Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on energy derivative instruments Changes in AOCI, net of tax (Dollars in Thousands) Total March 31, 2015 $ (36,131 ) $ — $ (36,131 ) Other comprehensive income (loss) before reclassifications — — — Amounts reclassified from accumulated other comprehensive income (loss), net of tax 1,277 — 1,277 Net current-period other comprehensive income (loss) 1,277 — 1,277 June 30, 2015 $ (34,854 ) $ — $ (34,854 ) Puget Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on energy derivative instruments Changes in AOCI, net of tax (Dollars in Thousands) Total December 31, 2014 $ (36,710 ) $ (333 ) $ (37,043 ) Other comprehensive income (loss) before reclassifications — — — Amounts reclassified from accumulated other comprehensive income (loss), net of tax 1,856 333 2,189 Net current-period other comprehensive income (loss) 1,856 333 2,189 June 30, 2015 $ (34,854 ) $ — $ (34,854 )
Parent Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification out of Accumulated Other Comprehensive Income	Details about these reclassifications out of AOCI for the three and six months ended June 30, 2015 , and 2014 , are as follows: Puget Energy Three Months Ended Six Months Ended (Dollars in Thousands) 2015 2014 2015 2014 Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented Amount reclassified from accumulated other comprehensive income (loss) Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 484 $ 484 $ 969 $ 1,165 Amortization of net gain (loss) (a) (2,449 ) (98 ) (3,825 ) (456 ) Total before tax (1,965 ) 386 (2,856 ) 709 Tax (expense) or benefit 688 (135 ) 1,000 (248 ) Net of Tax $ (1,277 ) $ 251 $ (1,856 ) $ 461 Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: electric derivatives Purchased electricity — — (512 ) (534 ) Tax (expense) or benefit — — 179 187 Net of Tax $ — $ — $ (333 ) $ (347 ) Net unrealized gain (loss) on interest rate swaps: Interest rate contracts Interest expense — — — (144 ) Tax (expense) or benefit — — — 50 Net of Tax $ — $ — $ — $ (94 ) Total reclassification for the period Net of Tax $ (1,277 ) $ 251 $ (2,189 ) $ 20 _______________ (a) These AOCI components are included in the computation of net periodic pension cost (see Note 5 for additional details)
Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Schedule of Accumulated Other Comprehensive Income (Loss)	Puget Sound Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on energy derivative instruments Net unrealized gain (loss) on treasury interest rate swaps Changes in AOCI, net of tax (Dollars in Thousands) Total March 31, 2015 $ (160,900 ) $ — $ (5,911 ) $ (166,811 ) Other comprehensive income (loss) before reclassifications — — — — Amounts reclassified from accumulated other comprehensive income (loss), net of tax 4,094 — 79 4,173 Net current-period other comprehensive income (loss) 4,094 — 79 4,173 June 30, 2015 $ (156,806 ) $ — $ (5,832 ) $ (162,638 ) Puget Sound Energy Net unrealized gain (loss) and prior service cost on pension plans Net unrealized gain (loss) on energy derivative instruments Net unrealized gain (loss) on treasury interest rate swaps Changes in AOCI, net of tax (Dollars in Thousands) Total December 31, 2014 $ (164,281 ) $ (686 ) $ (5,990 ) $ (170,957 ) Other comprehensive income (loss) before reclassifications — — — — Amounts reclassified from accumulated other comprehensive income (loss), net of tax 7,475 686 158 8,319 Net current-period other comprehensive income (loss) 7,475 686 158 8,319 June 30, 2015 $ (156,806 ) $ — $ (5,832 ) $ (162,638 )
Reclassification out of Accumulated Other Comprehensive Income	Puget Sound Energy Three Months Ended Six Months Ended (Dollars in Thousands) 2015 2014 2015 2014 Details about accumulated other comprehensive income (loss) components Affected line item in the statement where net income (loss) is presented Amount reclassified from accumulated other comprehensive income (loss) Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 381 $ 381 $ 762 $ 762 Amortization of net gain (loss) (a) (6,679 ) (3,516 ) (12,262 ) (6,975 ) Total before tax (6,298 ) (3,135 ) (11,500 ) (6,213 ) Tax (expense) or benefit 2,204 1,097 4,025 2,175 Net of Tax $ (4,094 ) $ (2,038 ) $ (7,475 ) $ (4,038 ) Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: electric derivatives Purchased electricity — — (1,055 ) (1,104 ) Tax (expense) or benefit — — 369 386 Net of Tax $ — $ — $ (686 ) $ (718 ) Net unrealized gain (loss) on treasury interest rate swaps: Interest rate contracts Interest expense (122 ) (122 ) (244 ) (244 ) Tax (expense) or benefit 43 43 86 86 Net of Tax $ (79 ) $ (79 ) $ (158 ) $ (158 ) Total reclassification for the period Net of Tax $ (4,173 ) $ (2,117 ) $ (8,319 ) $ (4,914 ) _______________ (a) These AOCI components are included in the computation of net periodic pension cost (see Note 5 for additional details)

Summary of Consolidation Poli23

Summary of Consolidation Policy (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015USD ($)mi²	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)mi²	Jun. 30, 2014USD ($)	Jan. 01, 2015
Maximum [Member] | Decoupling Mechanism [Member]
Schedule of Capitalization, Equity [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)					3.00%
Subsidiaries [Member]
Schedule of Capitalization, Equity [Line Items]
Area of Service Territory (in sqmi)	6,000		6,000
Excise taxes collected | $	$ 50.3	$ 50.6	$ 119.9	$ 128.5

New Accounting Pronouncements D

New Accounting Pronouncements Debt Issuance Costs (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Debt Issuance Costs [Abstract]
Debt Issuance Cost	$ 40.9	$ 35.7

Accounting for Derivative Ins25

Accounting for Derivative Instruments and Hedging Activities Derivative Activity and Notional Amounts (Details) MWh in Millions, MMBTU in Millions, $ in Millions		Jun. 30, 2015USD ($)MWhMMBTUContracts	Dec. 31, 2014USD ($)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]	343	360.4
Electric generation fuel [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary		171.6	140.2
Purchased Electricity [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary | MWh		4.1	5.4
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 Accounting Standards Codification (ASC) 980, “Regulated Operations” (ASC 980) due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.

Accounting for Derivative Ins26

Accounting for Derivative Instruments and Hedging Activities Derivative Assets and Liabilities (Details) $ in Thousands, MMBTU in Millions		Jun. 30, 2015USD ($)MMBTU	Dec. 31, 2014USD ($)MMBTU
Derivative [Line Items]
Unrealized gain on derivative instruments		$ 17,951	$ 21,178
Assets, Long-term		3,137	3,170
Unrealized loss on derivative instruments		130,153	142,195
Unrealized loss on derivative instruments		45,889	62,913
Subsidiaries [Member]
Derivative [Line Items]
Unrealized gain on derivative instruments		17,951	21,178
Assets, Long-term		3,137	3,170
Unrealized loss on derivative instruments		124,139	135,973
Unrealized loss on derivative instruments		43,609	60,063
Commodity Contract [Member]
Derivative [Line Items]
Assets		21,088	24,348
Derivative Liability		167,748	196,035
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Assets	[1]	21,088	24,348
Derivative Liability	[2]	176,042	205,108
Not Designated as Hedging Instrument [Member] | Parent Company [Member]
Derivative [Line Items]
Unrealized gain on derivative instruments	[1]	17,951	21,178
Assets, Long-term	[1]	3,137	3,170
Unrealized loss on derivative instruments	[2]	130,153	142,195
Unrealized loss on derivative instruments	[2]	45,889	62,913
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]	8,294	9,073
Not Designated as Hedging Instrument [Member] | Electric portfolio [Member]
Derivative [Line Items]
Assets	[1]	11,449	4,822
Derivative Liability	[2]	101,416	107,228
Not Designated as Hedging Instrument [Member] | Natural gas portfolio [Member]
Derivative [Line Items]
Assets	[1],[4]	9,639	19,526
Derivative Liability	[2],[4]	$ 66,332	$ 88,807
Not Designated as Hedging Instrument [Member] | Natural Gas Derivatives [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	[4]	343	360.4
[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 Accounting Standards Codification (ASC) 980, “Regulated Operations” (ASC 980) due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.

Accounting for Derivative Ins27

Accounting for Derivative Instruments and Hedging Activities Net Amount of Derivatives Reported in the Statement of Financial Position (Details) - Entity [Domain] - USD ($) $ in Thousands		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Liabilities
Derivative contracts classified as financing activities due to merger		$ (8,045)	$ (8,026)
Commodity Contract [Member]
Assets
Gross Amount Recognized in the Statement of Financial Position	[1]	21,088		$ 24,348
Gross Amounts Offset in the Statement of Financial Position		0		0
Net of Amounts Presented in the Statement of Financial Position		21,088		24,348
Commodity Contracts		(16,491)		(23,066)
Cash Collateral Received		0		0
Net Amount		4,597		1,282
Liabilities
Gross Amount Recognized in the Statement of Financial Position	[1]	167,748		196,035
Gross Amounts Offset in the Statement of Financial Position		0		0
Net of Amounts Presented in the Statement of Financial Position		167,748		196,035
Commodity Contracts		(16,491)		(23,066)
Cash Collateral Posted		0		(20)
Net Amount		151,257		172,949
Interest Rate Contract [Member]
Liabilities
Gross Amount Recognized in the Statement of Financial Position	[1],[2]	8,294		9,073
Gross Amounts Offset in the Statement of Financial Position	[2]	0		0
Net of Amounts Presented in the Statement of Financial Position	[2]	8,294		9,073
Commodity Contracts	[2]	0		0
Cash Collateral Posted	[2]	0		0
Net Amount	[2]	$ 8,294		$ 9,073
[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 Ins28

Accounting for Derivative Instruments and Hedging Activities Recognized in Statement of Income (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		$ (8,232)	$ (17,094)	$ (11,928)	$ (24,934)
Subsidiaries [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		(8,232)	(17,094)	(11,383)	(24,364)
Not Designated as Hedging Instrument [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		1,829	(12,212)	32,816	(32,390)
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		1,440	1,360	3,415	2,107
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		(722)	718	(560)	843
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]	(8,232)	(17,094)	(11,928)	(24,934)
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		5,082	(864)	15,744	(8,691)
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Purchased Electricity [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		4,261	3,668	26,145	(1,715)
Not Designated as Hedging Instrument [Member] | Subsidiaries [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments		1,111	(14,290)	30,506	(34,770)
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]	(8,232)	(17,094)	(11,383)	(24,364)
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		5,082	(864)	15,744	(8,691)
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		$ 4,261	$ 3,668	$ 26,145	$ (1,715)
[1]	1 Differences between Puget Energy and Puget Sound Energy for the six months ending June 30, 2015 and June 30, 2014 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 Ins29

Accounting for Derivative Instruments and Hedging Activities Recognized in Other Comprehensive Income (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended		12 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Purchased electricity		$ 104,471	$ 114,627	$ 257,951	$ 295,785
Subsidiaries [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Purchased electricity		104,471	114,627	257,951	295,785
Cash Flow Hedging [Member] | Subsidiaries [Member] | Interest Rate Swap [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship	[1]	122	122	244	244
Cash Flow Hedging [Member] | Subsidiaries [Member] | Energy Related Derivative [Member] | Electric Generation Fuel [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship		0	0		(1,104)
Other Comprehensive Income (Loss) [Member] | Cash Flow Hedging [Member] | Parent Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship		0	0	(512)	(678)
Other Comprehensive Income (Loss) [Member] | Cash Flow Hedging [Member] | Parent Company [Member] | Interest Rate Swap [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship		0	0	0	144
Other Comprehensive Income (Loss) [Member] | Cash Flow Hedging [Member] | Parent Company [Member] | Energy Related Derivative [Member] | Electric Generation Fuel [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship				(512)	(534)
Other Comprehensive Income (Loss) [Member] | Cash Flow Hedging [Member] | Subsidiaries [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship		$ (122)	$ (122)	$ (1,299)	$ (1,348)
Scenario, Forecast [Member] | Cash Flow Hedging [Member] | Subsidiaries [Member] | Interest Rate Swap [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship						$ (500)
[1]	1 Within the next twelve months, $0.5 million of losses in AOCI will be reclassified into earnings.

Accounting for Derivative Ins30

Accounting for Derivative Instruments and Hedging Activities Contractual Contingent Liability (Details) - Jun. 30, 2015 - USD ($) $ in Thousands		Total
Electric portfolio [Member]
Derivative [Line Items]
Fair Value Liability	[1]	$ 86,546
Posted Collateral		0
Additional Collateral, Aggregate Fair Value		29,332
Electric portfolio [Member] | Credit Rating [Member]
Derivative [Line Items]
Fair Value Liability	[1],[2]	29,332
Posted Collateral	[2]	0
Additional Collateral, Aggregate Fair Value	[2]	29,332
Electric portfolio [Member] | Requested credit for adequate assurance [Member]
Derivative [Line Items]
Fair Value Liability	[1]	57,214
Posted Collateral		0
Additional Collateral, Aggregate Fair Value		0
Electric portfolio [Member] | Forward value of contract [Member]
Derivative [Line Items]
Fair Value Liability	[1],[3]	0
Posted Collateral	[3]	0
Additional Collateral, Aggregate Fair Value	[3]	$ 0
Electric portfolio [Member] | External Credit Rating, Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage		99.80%
Electric portfolio [Member] | External Credit Rating, Non Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage		0.20%
Natural gas portfolio [Member] | Credit Rating [Member]
Derivative [Line Items]
Posted Collateral	[2]	$ 1,000
[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, 2015	Dec. 31, 2014
Parent Company [Member]
Assets:
Cash and Cash Equivalents	$ 14,535	$ 37,527
Restricted Cash	7,964	32,863
Notes Receivable and Other	50,830	53,503
Total assets	73,329	123,893
Liabilities:
Short-term Debt	0	85,000
Total liabilities	0	85,000
Parent Company [Member] | Level 1 [Member]
Assets:
Cash and Cash Equivalents	14,535	37,527
Restricted Cash	7,964	32,863
Notes Receivable and Other	0	0
Total assets	22,499	70,390
Liabilities:
Short-term Debt	0	85,000
Total liabilities	0	85,000
Parent Company [Member] | Level 2 [Member]
Assets:
Cash and Cash Equivalents	0	0
Restricted Cash	0	0
Notes Receivable and Other	50,830	53,503
Total assets	50,830	53,503
Liabilities:
Short-term Debt	0	0
Total liabilities	0	0
Subsidiaries [Member]
Assets:
Cash and Cash Equivalents	13,320	37,466
Restricted Cash	7,964	32,863
Notes Receivable and Other	50,830	53,503
Total assets	72,114	123,832
Liabilities:
Short-term Debt	0	85,000
Short-term Debt owed by PSE to PE	0	28,933
Total liabilities	0	113,933
Subsidiaries [Member] | Level 1 [Member]
Assets:
Cash and Cash Equivalents	13,320	37,466
Restricted Cash	7,964	32,863
Notes Receivable and Other	0	0
Total assets	21,284	70,329
Liabilities:
Short-term Debt	0	85,000
Short-term Debt owed by PSE to PE	0	0
Total liabilities	0	85,000
Subsidiaries [Member] | Level 2 [Member]
Assets:
Cash and Cash Equivalents	0	0
Restricted Cash	0	0
Notes Receivable and Other	50,830	53,503
Total assets	50,830	53,503
Liabilities:
Short-term Debt	0	0
Short-term Debt owed by PSE to PE	0	28,933
Total liabilities	$ 0	$ 28,933

Fair Value Measurements Debt at

Fair Value Measurements Debt at at Carrying and Fair Value (Details) - Discounted cash flow [Member] - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Parent Company [Member] | Carrying Value [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	$ 5,373,567	$ 5,243,608
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	5,123,567	4,694,608
Long Term Debt (variable rate) net of discount	0	299,000
Parent Company [Member] | Fair Value [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	6,387,015	6,658,789
Parent Company [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes	159,346	276,235
Long-term debt (fixed-rate), net of discount	6,227,669	6,083,554
Long Term Debt (variable rate) net of discount	0	299,000
Subsidiaries [Member] | Carrying Value [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	3,786,353	3,763,259
Subsidiaries [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes	250,000	250,000
Long-term debt (fixed-rate), net of discount	3,536,353	3,513,259
Subsidiaries [Member] | Fair Value [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	4,386,245	4,713,708
Subsidiaries [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes	159,346	276,235
Long-term debt (fixed-rate), net of discount	$ 4,226,899	$ 4,437,473

Fair Value Measurements Assets

Fair Value Measurements Assets and Liabilities (Details) - USD ($) $ in Thousands		3 Months Ended				6 Months Ended
		Jun. 30, 2015		Jun. 30, 2014		Jun. 30, 2015		Jun. 30, 2014		Dec. 31, 2014
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		$ (17,692)		$ (15,709)		$ (14,100)		$ (15,782)
Included in earnings		(4,064)	[1]	7,800	[1]	(9,102)	[2]	5,055	[2]
Included in regulatory assets/liabilities		2,813		2,120		2,938		2,379
Settlements	[3]	(337)		1,591		(133)		1,502
Transferred into Level 3		0		0		(787)		2,515
Transferred out of Level 3		4,733		(768)		6,637		(635)
Balance at end of period		(14,547)		(4,966)		(14,547)		(4,966)
Electric portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts		(3,800)		4,700		(8,800)		100
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		(16,091)		(14,606)		(12,061)		(15,421)
Included in earnings		(4,064)	[1]	7,800	[1]	(9,102)	[2]	5,055	[2]
Included in regulatory assets/liabilities		0		0		0		0
Settlements	[3]	52		1,757		165		2,078
Transferred into Level 3		0		0		(787)		3,100
Transferred out of Level 3		4,733		356		6,415		495
Balance at end of period		(15,370)		(4,693)		(15,370)		(4,693)
Natural gas portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period		(1,601)		(1,103)		(2,039)		(361)
Included in earnings		0	[1]	0	[1]	0	[2]	0	[2]
Included in regulatory assets/liabilities		2,813		2,120		2,938		2,379
Settlements	[3]	(389)		(166)		(298)		(576)
Transferred into Level 3		0		0		0		(585)
Transferred out of Level 3		0		(1,124)		222		(1,130)
Balance at end of period		823		$ (273)		823		$ (273)
Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		21,088				21,088				$ 24,348
Derivative Liability		167,748				167,748				196,035
Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	[4]	8,294				8,294				9,073
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		8,294				8,294				9,073
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		8,294				8,294				9,073
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				0
Fair Value, Measurements, Recurring [Member] | Parent Company [Member] | Level 3 [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability		0				0				0
Fair Value, Measurements, Recurring [Member] | Parent Company [Member] | Total [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability		8,294				8,294				9,073
Fair Value, Measurements, Recurring [Member] | Parent Company [Member] | Total [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability		8,294				8,294				9,073
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		14,117				14,117				19,718
Derivative Liability		146,230				146,230				177,303
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		8,777				8,777				1,654
Derivative Liability		83,374				83,374				91,998
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		5,340				5,340				18,064
Derivative Liability		62,856				62,856				85,305
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		6,971				6,971				4,630
Derivative Liability		21,518				21,518				18,732
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		2,672	[5]			2,672	[5]			3,168	[6]
Derivative Liability		18,042	[5]			18,042	[5]			15,230	[6]
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		4,299	[5]			4,299	[5]			1,462	[6]
Derivative Liability		3,476	[5]			3,476	[5]			3,502	[6]
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Total [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		21,088				21,088				24,348
Derivative Liability		167,748				167,748				196,035
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Total [Member] | Commodity Contract [Member] | Electric portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		11,449				11,449				4,822
Derivative Liability		101,416				101,416				107,228
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Total [Member] | Commodity Contract [Member] | Natural gas portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets		9,639				9,639				19,526
Derivative Liability		$ 66,332				$ 66,332				$ 88,807
[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 $(3.8) million and $4.7 million for the three months ended June 30, 2015 and 2014, 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 $(8.8) million and $0.1 million for the six months ended June 30, 2015 and 2014, respectively.
[3]	3 The Company had no purchases, sales or issuances during the reported periods.
[4]	2 Interest rate swap contracts are only held at Puget Energy.
[5]	1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions
[6]	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) - Fair Value, Measurement Frequency [Domain] - Entity [Domain] $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)$ / MMBTU$ / MWh	Jun. 30, 2014USD ($)	Dec. 31, 2013USD ($)$ / MMBTU$ / MWh	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Mar. 31, 2014USD ($)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value	$ 14,547	$ 4,966	$ 14,547	$ 4,966	$ 15,782	$ 17,692	$ 14,100	$ 15,709
Fair Value measurement, sensitivity analysis, hypothetical increase or decrease of market prices, result on fair value	10.00%		10.00%
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value	$ 3,800		$ 3,800				3,900
Commodity Contract [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	21,088		21,088				24,348
Derivative Liability	167,748		$ 167,748				196,035
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			15.17		21.79
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			38		35.46
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			28.03		32.89
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			1.71		3.11
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			3.54		3.83
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			2.79		3.28
Electric portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value	15,370	4,693	$ 15,370	4,693	$ 15,421	16,091	12,061	14,606
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	(3,800)	4,700	(8,800)	100
Natural gas portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value	$ (823)	$ 273	$ (823)	$ 273	$ 361	$ 1,601	$ 2,039	$ 1,103

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, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost			$ (10,644)		$ (17,437)
Interest cost			(14,044)		(28,039)
Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost			(554)		(1,042)
Interest cost			(1,140)		(2,310)
Other Benefit [Member]
Components of net periodic benefit cost:
Service cost			(56)		(112)
Interest cost			(311)		$ (684)
Parent Company [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	$ (5,172)	$ (4,206)	(10,644)	$ (8,718)
Interest cost	(6,937)	(6,965)	(14,044)	(14,020)
Expected return on plan assets	(11,117)	(10,511)	(22,519)	(21,232)
Amortization of prior service cost	(495)	(495)	(990)	(990)
Amortization of net loss (gain)	962	0	1,943	0
Defined Benefit Plan, Net Periodic Benefit Cost	1,459	165	3,122	516
Parent Company [Member] | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	(277)	(261)	(554)	(521)
Interest cost	(570)	(577)	(1,140)	(1,155)
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	11	11	22	22
Amortization of net loss (gain)	410	228	820	456
Defined Benefit Plan, Net Periodic Benefit Cost	1,268	1,077	2,536	2,154
Parent Company [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	(23)	(26)	(56)	(56)
Interest cost	(150)	(159)	(311)	(342)
Expected return on plan assets	(133)	(134)	(266)	(267)
Amortization of prior service cost	0	0	0	(197)
Amortization of net loss (gain)	(51)	(130)	(66)	0
Defined Benefit Plan, Net Periodic Benefit Cost	(11)	(79)	35	(66)
Subsidiaries [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	(5,172)	(4,206)	(10,644)	(8,718)
Interest cost	(6,937)	(6,965)	(14,044)	(14,020)
Expected return on plan assets	(11,223)	(10,708)	(22,731)	(21,626)
Amortization of prior service cost	(393)	(393)	(786)	(786)
Amortization of net loss (gain)	5,141	3,359	10,277	6,597
Defined Benefit Plan, Net Periodic Benefit Cost	5,634	3,429	11,448	6,923
Subsidiaries [Member] | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	(277)	(261)	(554)	(521)
Interest cost	(570)	(577)	(1,140)	(1,155)
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	11	11	22	22
Amortization of net loss (gain)	530	365	1,060	730
Defined Benefit Plan, Net Periodic Benefit Cost	1,388	1,214	2,776	2,428
Subsidiaries [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	(23)	(26)	(56)	(56)
Interest cost	(150)	(159)	(311)	(342)
Expected return on plan assets	(133)	(134)	(266)	(267)
Amortization of prior service cost	1	1	2	2
Amortization of net loss (gain)	(120)	(208)	(203)	(352)
Defined Benefit Plan, Net Periodic Benefit Cost	$ (79)	$ (156)	$ (100)	$ (219)

Retirement Benefits Change in N

Retirement Benefits Change in Net Benefit Obligation (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Qualified Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	$ 690,194	$ 573,317
Service cost	(10,644)	(17,437)
Interest cost	14,044	28,039
Actuarial loss/(gain)	(588)	104,618
Benefits paid	(27,869)	(33,217)
Medicare part D subsidiary received	0	0
Benefit obligation at end of period	686,425	690,194
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	55,855	47,279
Service cost	(554)	(1,042)
Interest cost	1,140	2,310
Actuarial loss/(gain)	0	7,162
Benefits paid	(2,565)	(1,938)
Medicare part D subsidiary received	0	0
Benefit obligation at end of period	54,984	55,855
Other Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	15,688	14,939
Service cost	(56)	(112)
Interest cost	311	684
Actuarial loss/(gain)	(540)	1,108
Benefits paid	(703)	(1,424)
Medicare part D subsidiary received	221	269
Benefit obligation at end of period	$ 15,033	$ 15,688

Retirement Benefits Activity (D

Retirement Benefits Activity (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2015	Dec. 31, 2015
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	0.5	2.6
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%
Scenario, Forecast [Member] | Qualified Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			$ 18
Scenario, Forecast [Member] | Supplemental Employee Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			4.4
Scenario, Forecast [Member] | Other Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			$ 0.4
Scenario, Forecast [Member] | Subsidiaries [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent		4.00%

Regulation and Rates (Details)

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

3 Months Ended

6 Months Ended

Jun. 30, 2015

Jun. 30, 2014

Jun. 30, 2015

Jun. 30, 2014

Jun. 01, 2015

May. 01, 2015

Jan. 01, 2015

Dec. 31, 2014

Dec. 01, 2014

Nov. 01, 2014

May. 23, 2014

May. 01, 2014

Jul. 02, 2013

Jun. 25, 2013

Regulatory Assets [Line Items]

Net Income (Loss) Attributable to Parent

$ 25,616

$ 41,113

$ 141,292

$ 148,705

Subsidiaries [Member]

Regulatory Assets [Line Items]

Net Income (Loss) Attributable to Parent

42,699

$ 57,834

171,799

$ 178,916

Rate Case, Approved Effective Weighted Cost of Capital

7.77%

Rate Case, Approved Effective Common Equity in Capital Structure

48.00%

Rate Case, Approved Effective Return on Equity

9.80%

Decoupling Mechanism [Member] | Natural Gas [Member]

Regulatory Assets [Line Items]

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

2.20%

Decoupling Mechanism [Member] | Subsidiaries [Member]

Regulatory Assets [Line Items]

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

$ (12,000)

Decoupling Mechanism [Member] | Subsidiaries [Member] | Electric [Member]

Regulatory Assets [Line Items]

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

$ 53,800

$ 10,600

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

2.60%

0.50%

Decoupling Mechanism [Member] | Subsidiaries [Member] | Natural Gas [Member]

Regulatory Assets [Line Items]

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

$ 22,000

$ (1,300)

$ (1,000)

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

2.10%

(0.10%)

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

Regulatory Assets [Line Items]

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

$ (19,400)

$ (9,600)

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

(0.90%)

(0.50%)

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

Regulatory Assets [Line Items]

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

$ 23,300

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

2.50%

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

Regulatory Assets [Line Items]

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

$ 6,500

$ 0

$ 11,000

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

0.30%

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

Regulatory Assets [Line Items]

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

$ (2,300)

$ 5,600

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

(0.20%)

0.60%

Conservation Rider [Member] | Subsidiaries [Member] | Electric [Member]

Regulatory Assets [Line Items]

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

$ 12,200

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

0.60%

Conservation Rider [Member] | Subsidiaries [Member] | Natural Gas [Member]

Regulatory Assets [Line Items]

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

$ 300

Maximum [Member] | Decoupling Mechanism [Member]

Regulatory Assets [Line Items]

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

3.00%

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

Regulatory Assets [Line Items]

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

1,900

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

Regulatory Assets [Line Items]

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

$ 8,200

Range 1 [Member]

Regulatory Assets [Line Items]

Annual Power Cost Variability, Amount

17,000

17,000

Range 2 [Member] [Member] | Minimum [Member]

Regulatory Assets [Line Items]

Annual Power Cost Variability, Amount

17,000

17,000

Range 2 [Member] [Member] | Maximum [Member]

Regulatory Assets [Line Items]

Annual Power Cost Variability, Amount

40,000

40,000

Range 3 [Member] [Member]

Regulatory Assets [Line Items]

Annual Power Cost Variability, Amount

$ 40,000

$ 40,000

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

0.00%

0.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

100.00%

100.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

65.00%

65.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

35.00%

35.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

90.00%

90.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

10.00%

10.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

0.00%

0.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

100.00%

100.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

50.00%

50.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

50.00%

50.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

90.00%

90.00%

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

Regulatory Assets [Line Items]

Annual Power Cost Variability, Percentage

10.00%

10.00%

Deferral Trigger [Member] [Member]

Regulatory Assets [Line Items]

Annual Power Cost Variability, Amount

$ 20,000

$ 20,000

$ 30,000

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - Subsidiaries [Member] - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Increase (Decrease) in Asset Retirement Obligations	$ 84,588	$ 48,909
Asset Retirement Obligations, Significant Changes	34,534
Asset Retirement Obligation, Liabilities Incurred	(15)
Asset Retirement Obligation, Revision of Estimate	450
Asset Retirement Obligation, Accretion Expense	$ 710

Contingencies (Details)

Contingencies (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
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	$ 0.7	$ 1.7

Accumulated Other Comprehensi41

Accumulated Other Comprehensive Income - Changes by Component (Details) - Jun. 30, 2015 - USD ($) $ in Thousands		Total	Total
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance			$ (37,043)
Ending balance		$ (34,854)	(34,854)
Parent Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		(36,131)	(37,043)
Other comprehensive income (loss) before reclassifications		0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		1,277	2,189
Net current-period other comprehensive income (loss)		1,277	2,189
Ending balance		(34,854)	(34,854)
Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		(166,811)	(170,957)
Other comprehensive income (loss) before reclassifications		0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		4,173	8,319
Net current-period other comprehensive income (loss)		4,173	8,319
Ending balance		(162,638)	(162,638)
Net unrealized gain (loss) and prior service cost on pension plans | Parent Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		(36,131)	(36,710)
Other comprehensive income (loss) before reclassifications		0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		1,277	1,856
Net current-period other comprehensive income (loss)		1,277	1,856
Ending balance		(34,854)	(34,854)
Net unrealized gain (loss) and prior service cost on pension plans | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		(160,900)	(164,281)
Other comprehensive income (loss) before reclassifications		0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		4,094	7,475
Net current-period other comprehensive income (loss)		4,094	7,475
Ending balance		(156,806)	(156,806)
Energy Related Derivative [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Parent Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		0	(333)
Other comprehensive income (loss) before reclassifications		0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		0	333
Net current-period other comprehensive income (loss)		0	333
Ending balance		0	0
Energy Related Derivative [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		0	(686)
Other comprehensive income (loss) before reclassifications		0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		0	686
Net current-period other comprehensive income (loss)		0	686
Ending balance		0	0
Interest Rate Swap [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		(5,911)	(5,990)
Other comprehensive income (loss) before reclassifications		0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		79	158
Net current-period other comprehensive income (loss)		79	158
Ending balance	[1]	$ (5,832)	$ (5,832)
[1]	_(a) These AOCI components are included in the computation of net periodic pension cost (see Note 5 for additional details)

Accumulated Other Comprehensi42

Accumulated Other Comprehensive Income - Reclassification Location (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax		$ 0	$ 0	$ 179	$ 187
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0	0	(333)	(347)
Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax		0	0	369	386
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0	0	(686)	(718)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent		(1,277)	251	(2,189)	20
Reclassification out of Accumulated Other Comprehensive Income [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent		(4,173)	(2,117)	(8,319)	(4,914)
Net unrealized gain (loss) and prior service cost on pension plans | Reclassification out of Accumulated Other Comprehensive Income [Member] | Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Amortization of prior service cost	[1]	484	484	969	1,165
Amortization of net gain (loss)	[1]	(2,449)	(98)	(3,825)	(456)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax		(1,965)	386	(2,856)	709
Total before tax		688	(135)	1,000	(248)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax		(1,277)	251	(1,856)	461
Net unrealized gain (loss) and prior service cost on pension plans | Reclassification out of Accumulated Other Comprehensive Income [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Amortization of prior service cost	[1]	381	381	762	762
Amortization of net gain (loss)	[1]	(6,679)	(3,516)	(12,262)	(6,975)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax		(6,298)	(3,135)	(11,500)	(6,213)
Total before tax		2,204	1,097	4,025	2,175
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax		(4,094)	(2,038)	(7,475)	(4,038)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Derivative [Member] | Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax		0	0	(512)	(534)
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax		0	0	(179)	(187)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0	0	(333)	(347)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Derivative [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax		0	0	(1,055)	(1,104)
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax		0	0	(369)	(386)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0	0	(686)	(718)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate Swap [Member] | Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax		0	0	0	(144)
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax		0	0	0	(50)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0	0	0	(94)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate Swap [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax		(122)	(122)	(244)	(244)
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax		(43)	(43)	(86)	(86)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		$ (79)	$ (79)	$ (158)	$ (158)
[1]	_(a) These AOCI components are included in the computation of net periodic pension cost (see Note 5 for additional details)

Other (Term Loan) (Details)

Other (Term Loan) (Details) - Senior Notes [Member] - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015	Jan. 31, 2016	Oct. 31, 2015	May. 26, 2015	May. 12, 2015	Jun. 29, 2014
Debt Instrument [Line Items]
Long-term Debt, Gross					$ 400	$ 299.1
Special Dividend [Line Items]	$ 96.7
Subsidiaries [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross				$ 425
Debt Instrument, Interest Rate, Stated Percentage				4.30%	3.65%
Scenario, Forecast [Member] | Subsidiaries [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 250	$ 150
Debt Instrument, Interest Rate, Stated Percentage		6.75%	5.197%