Puget Energy (PSD) S-4/A 23 Nov 15 Registration of securities issued in business combination transactions (amended) Financial data

Document and Entity Information

Document and Entity Information	9 Months Ended
	Sep. 30, 2015
Document And Entity Information [Abstract]
Document Type	S-4/A
Amendment Flag	false
Document Period End Date	Sep. 30, 2015
Entity Registrant Name	PUGET ENERGY INC /WA
Entity Central Index Key	1,085,392
Entity Filer Category	Non-accelerated Filer

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating revenue:
Electric	$ 482,786	$ 468,530	$ 1,526,029	$ 1,577,663	$ 2,083,797	$ 2,156,920	$ 2,128,230
Natural gas	119,582	121,402	653,385	692,780	1,012,859	1,028,357	1,086,095
Other	3,365	3,783	11,495	11,563	16,515	2,020	831
Total operating revenue	605,733	593,715	2,190,909	2,282,006	3,113,171	3,187,297	3,215,156
Energy costs:
Purchased electricity	97,694	67,984	355,645	363,769	514,087	541,905	622,288
Electric generation fuel	76,863	92,510	180,531	202,741	263,493	261,332	204,956
Residential exchange	(19,530)	(30,963)	(92,297)	(84,587)	(129,036)	(81,053)	(73,555)
Purchased natural gas	46,436	42,550	282,334	310,128	458,691	488,201	538,612
Unrealized (gain) loss on derivative instruments, net	5,588	32,648	(6,339)	7,714	84,146	(102,744)	(133,606)
Utility operations and maintenance	131,208	132,109	400,355	411,068	550,146	529,939	512,765
Non-utility expense and other	1,573	2,911	7,106	8,627	13,109	(3,555)	814
Depreciation					370,962	364,324	337,952
Depreciation and amortization	107,759	105,905	314,348	312,821
Amortization					(5,356)	24,631	55,819
Conservation amortization	24,224	23,047	78,389	74,554	104,096	105,897	114,177
Taxes other than income taxes	64,030	59,945	228,942	228,534	310,982	303,260	319,399
Total operating expenses	535,845	528,646	1,749,014	1,835,369	2,535,320	2,432,137	2,499,621
Operating income	69,888	65,069	441,895	446,637	577,851	755,160	715,535
Other income (deductions):
Other income	4,732	10,956	14,770	19,817	24,038	38,693	49,069
Other expense	(1,621)	(1,806)	(4,843)	(5,032)	(7,457)	(7,134)	(11,770)
Non-hedged interest rate swap (expense) income	(1,156)	(323)	(4,571)	(2,430)	(3,915)	2,420	(4,288)
Interest charges:
AFUDC	2,102	1,474	5,262	4,189	5,611	11,261	22,216
Interest expense	(88,753)	(93,258)	(267,484)	(275,685)	(367,308)	(392,264)	(392,216)
Income (loss) before income taxes	(14,808)	(17,888)	185,029	187,496	228,820	408,136	378,546
Income tax (benefit) expense	(6,880)	(4,930)	51,665	51,749	56,985	122,408	104,725
Net income (loss)	$ (7,928)	$ (12,958)	$ 133,364	$ 135,747	$ 171,835	$ 285,728	$ 273,821

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Net income (loss)	$ (7,928)	$ (12,958)	$ 133,364	$ 135,747	$ 171,835	$ 285,728	$ 273,821
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	562	(314)	2,418	(1,306)	(85,224)	77,579	(13,870)
Reclassification of net unrealized loss on energy derivative instruments settled during the period, net of tax	0	0	333	347	372	37	371
Other Comprehensive Income Reclassification Of Net Unrealized Gain Loss On Interest Rate Swaps During Period Net Of Tax	0	0	0	94	94	2,928	11,577
Other comprehensive income (loss)	562	(314)	2,751	(865)	(84,758)	80,544	(1,922)
Comprehensive income (loss)	$ (7,366)	$ (13,272)	$ 136,115	$ 134,882	$ 87,077	$ 366,272	$ 271,899

CONSOLIDATED STATEMENTS OF COM4

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Net unrealized gain (loss) from pension and postretirement plans, tax	$ 303	$ (169)	$ 1,303	$ (703)	$ (45,890)	$ 41,773	$ (7,469)
Reclassification of net unrealized loss on energy derivative instruments during the period, tax	0	0	179	187	200	20	200
Reclassification of net unrealized loss on interest rate swaps during the period, tax	$ 0	$ 0	$ 0	$ 50	$ 50	$ 1,577	$ 6,234

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2013
Utility plant (at original cost, including construction work in progress):
Electric plant	$ 7,352,382	$ 7,135,206	$ 7,019,853
Natural gas plant	2,805,551	2,680,067	2,528,629
Common plant	481,184	472,926	504,036
Less: Accumulated depreciation and amortization	(1,804,201)	(1,611,220)	(1,373,178)
Net utility plant	8,834,916	8,676,979	8,679,340
Other property and investments:
Goodwill	1,656,513	1,656,513	1,656,513
Other property and investments	87,410	91,139	100,332
Total other property and investments	1,743,923	1,747,652	1,756,845
Current assets:
Cash and cash equivalents	20,200	37,527	44,302
Restricted cash	7,036	32,863	7,171
Accounts receivable, net of allowance for doubtful accounts	245,344	306,923	408,512
Unbilled revenue	127,620	168,039	219,884
Purchased gas adjustment receivable	0	21,073
Materials and supplies, at average cost	84,489	83,189	88,140
Fuel and gas inventory, at average cost	68,360	69,433	66,717
Unrealized gain on derivative instruments	18,771	21,178	18,867
Income taxes	31	301	297
Prepaid expense and other	39,306	20,905	18,787
Power contract acquisition adjustment gain	40,348	43,843	48,509
Deferred income taxes	162,336	161,445	86,004
Total current assets	813,841	966,719	1,007,190
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	71,499	95,432	146,867
Power cost adjustment mechanism	4,717	4,623
Regulatory assets related to power contracts	26,843	29,816	33,753
Other regulatory assets	893,869	866,835	749,382
Unrealized gain on derivative instruments	3,309	3,170	7,733
Power contract acquisition adjustment gain	300,325	347,547	394,556
Other	95,978	96,275	130,909
Total other long-term and regulatory assets	1,396,540	1,443,698	1,463,200
Total assets	12,789,220	12,835,048	12,906,575
Capitalization:
Common stock	0	0	0
Additional paid-in capital	3,308,957	3,308,957	3,308,957
Earnings reinvested in the business	212,188	271,414	323,007
Accumulated other comprehensive income (loss), net of tax	(34,292)	(37,043)	47,715
Total common shareholder's equity	3,486,853	3,543,328	3,679,679
Long-term debt:
First mortgage bonds and senior notes	3,364,412	3,189,412	3,351,412
Pollution control bonds	161,860	161,860	161,860
Junior subordinated notes	250,000	250,000	250,000
Long-term debt	1,800,000	1,699,000	1,699,000
Debt discount and other	(212,555)	(218,664)	(229,796)
Total long-term debt	5,363,717	5,081,608	5,232,476
Total capitalization	8,850,570	8,624,936	8,912,155
Current liabilities:
Accounts payable	233,582	307,578	296,681
Short-term debt	79,500	85,000	162,000
Current maturities of long-term debt	0	162,000	0
Purchased gas adjustment liability	8,347	0	5,938
Accrued expenses:
Taxes	80,055	107,782	109,559
Salaries and wages	36,161	40,970	38,491
Interest	78,011	78,914	79,303
Unrealized loss on derivative instruments	133,061	142,195	48,049
Power contract acquisition adjustment loss	3,624	3,593	3,937
Other	57,509	62,464	60,335
Total current liabilities	709,850	990,496	804,293
Long-term and regulatory liabilities:
Deferred income taxes	1,552,461	1,522,357	1,487,005
Unrealized loss on derivative instruments	55,602	62,913	38,162
Power Cost Adjustment Mechanism		0	5,345
Regulatory liabilities	637,195	633,471	689,060
Regulatory liabilities related to power contracts	340,673	391,389	443,065
Power contract acquisition adjustment loss	23,219	26,223	29,816
Other Deferred Credits, Noncurrent	619,650	583,263	497,674
Total long-term and regulatory liabilities	$ 3,228,800	$ 3,219,616	$ 3,190,127
Commitments and contingencies
Total capitalization and liabilities	$ 12,789,220	$ 12,835,048	$ 12,906,575

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Construction work in progress	$ 353,388	$ 239,690	$ 310,318
Allowance for doubtful accounts	$ 11,488	$ 7,472	$ 7,385
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,000	1,000	1,000
Common stock, shares outstanding (in shares)	200	200	200

CONSOLIDATED STATEMENTS OF COMM

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Earnings Reinvested in the Business	Accumulated Other Comprehensive Income (Loss)
Beginning Balance at Dec. 31, 2011	$ 3,300,923		$ 3,308,957	$ 22,873	$ (30,907)
Beginning Balance, in shares at Dec. 31, 2011		200
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	273,821			273,821
Common stock dividend	(88,594)			(88,594)
Other comprehensive income (loss)	(1,922)				(1,922)
Ending Balance at Dec. 31, 2012	3,484,228		3,308,957	208,100	(32,829)
Ending Balance, in shares at Dec. 31, 2012		200
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	285,728			285,728
Common stock dividend	(170,821)			(170,821)
Other comprehensive income (loss)	80,544				80,544
Ending Balance at Dec. 31, 2013	$ 3,679,679		3,308,957	323,007	47,715
Ending Balance, in shares at Dec. 31, 2013	200	200
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 171,835			171,835
Common stock dividend	(223,428)			(223,428)
Other comprehensive income (loss)	(84,758)				(84,758)
Ending Balance at Dec. 31, 2014	$ 3,543,328		$ 3,308,957	$ 271,414	$ (37,043)
Ending Balance, in shares at Dec. 31, 2014	200	200
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 133,364
Other comprehensive income (loss)	2,751
Ending Balance at Sep. 30, 2015	$ 3,486,853
Ending Balance, in shares at Sep. 30, 2015	200

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating activities:
Net income (loss)	$ 133,364	$ 135,747	$ 171,835	$ 285,728	$ 273,821
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation			370,962	364,324	337,952
Depreciation and amortization	314,348	312,821
Amortization			(5,356)	24,631	55,819
Conservation amortization	78,389	74,554	104,096	105,897	114,177
Deferred income taxes and tax credits, net	51,664	51,749	56,984	122,409	100,457
Gain on land sales			(4,071)	0	0
Net unrealized (gain) loss on derivative instruments	(7,789)	4,194	80,139	(106,540)	(146,680)
Derivative contracts classified as financing activities due to merger	8,045	8,026	16,349	34,250	92,681
AFUDC - Equity	(6,490)	(5,257)	(7,002)	(15,930)	(25,469)
Funding of pension liability	(13,500)	(9,000)	(18,000)	(20,400)	(22,800)
Regulatory assets	(140,958)	(115,710)	(219,604)	(122,549)	(170,374)
Regulatory liabilities	26,070	(6,907)	(8,730)	50,025	14,054
Other long-term assets	21,042	(5,287)	(6,003)	(24,877)	(1,644)
Other long-term liabilities	(2,570)	36,822	29,765	180,015	95,166
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	101,998	274,463	153,434	(103,949)	35,537
Materials and supplies	(1,300)	4,735	4,951	(5,787)	(6,284)
Fuel and gas inventory	255	(10,032)	(2,742)	21,633	11,527
Income taxes	270	297	(4)	4,499	6,174
Prepayments and other	(18,399)	(14,433)	(2,136)	(5,357)	393
Purchased gas adjustment	29,420	(38,331)	(27,011)	(26,649)	6,647
Accounts payable	(65,736)	(54,197)	9,098	4,597	(25,963)
Taxes payable	(27,727)	(27,737)	(1,777)	13,936	4,896
Accrued expenses and other	(14,400)	(11,350)	6,605	(13,838)	32,598
Net cash provided by operating activities	465,996	605,167	701,782	766,068	782,685
Investing activities:
Construction expenditures - excluding equity AFUDC	(419,389)	(343,619)	(493,130)	(567,938)	(859,791)
Treasury grants received	0	107,876	107,876	0	205,261
Proceeds from disposition of assets			20,296	108,362	0
Restricted cash	25,827	(47,080)	(25,692)	(3,471)	483
Other	2,902	(18,439)	(4,512)	(17,871)	(38,923)
Net cash used in investing activities	(390,660)	(301,262)	(395,162)	(480,918)	(692,970)
Financing activities:
Change in short-term debt and leases, net	(5,500)	(142,864)	(77,000)	(26,578)	148,437
Dividends paid	(192,590)	(179,614)	(223,428)	(170,821)	(88,594)
Long-term notes and bonds issued	825,000	299,000	299,000	161,860	1,314,000
Redemption of bonds and notes	(711,000)	(299,000)	(299,000)	(309,860)	(1,273,000)
Derivative contracts classified as financing activities due to merger	(8,045)	(8,026)	(16,349)	(34,250)	(92,681)
Issuance cost of bonds and other	(528)	8,767	3,382	3,259	430
Net cash provided by (used in) financing activities	(92,663)	(321,737)	(313,395)	(376,390)	8,592
Net increase (decrease) in cash and cash equivalents	(17,327)	(17,832)	(6,775)	(91,240)	98,307
Cash and cash equivalents at beginning of period	37,527	44,302	44,302	135,542	37,235
Cash and cash equivalents at end of period	20,200	26,470	37,527	44,302	135,542
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	252,251	263,921	349,402	334,041	318,305
Cash payments (refunds) for income taxes	0	0	0	(4,500)	(1,898)
Accounts payable for capital expenditures eliminated from cash flows	$ 43,522	$ 61,112	$ 51,776	$ 49,977	$ 79,852

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	(1) Summary of Significant Accounting Policies Basis of Presentation Puget Energy, Inc. (Puget Energy) is an energy services holding company that owns Puget Sound Energy, Inc. (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering 6,000 square miles, primarily in the Puget Sound region. In 2009, Puget Holdings LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiary, PSE. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company.” The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and PSE’s financial statements do not include any ASC 805 purchase accounting adjustments. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $231.7 million, $243.9 million and $244.2 million for 2014, 2013 and 2012, respectively. The Company reports the collection of such taxes on a gross basis in operation revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income. Beginning July 1, 2013, 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 are deferred to a regulatory asset for under recovery or regulatory liability for over recovery. Revenues associated with power costs under the Power Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA) rates are excluded from the decoupling mechanism. Utility Plant Puget Energy and PSE capitalize, at original cost, additions to utility plant, including renewals and betterments. Costs include indirect costs such as engineering, supervision, certain taxes, pension and other employee benefits and an Allowance for Funds Used During Construction (AFUDC). Replacements of minor items of property are included in maintenance expense. When the utility plant is retired and removed from service, the original cost of the property is charged to accumulated depreciation and costs associated with removal of the property, less salvage, are charged to the cost of removal regulatory liability. Planned Major Maintenance Planned major maintenance is an activity that typically occurs when PSE overhauls or substantially upgrades various systems and equipment on its natural gas fired combustion turbines on a scheduled basis. Costs related to planned major maintenance are deferred and amortized to the next scheduled major maintenance. This accounting method also follows the Washington Utilities and Transportation Commission (Washington Commission) regulatory treatment related to these generating facilities. Non-Utility Property, Plant and Equipment For PSE, the costs of other property, plant and equipment are stated at historical cost. Expenditures for refurbishment and improvements that significantly add to productive capacity or extend useful life of an asset are capitalized. Replacement of minor items are expensed on a current basis. Gains and losses on assets sold or retired are reflected in earnings. Depreciation and Amortization For financial statement purposes, the Company provides for depreciation and amortization on a straight-line basis. Amortization is recorded for intangibles such as regulatory assets and liabilities, computer software and franchises. The depreciation of vehicles and equipment is allocated to the asset and expense accounts based on usage. The annual depreciation provision stated as a percent of a depreciable electric utility plant was 2.8%, 2.8% and 2.9% in 2014, 2013 and 2012, respectively; depreciable gas utility plant was 3.4%, 3.4% and 3.4% in 2014, 2013 and 2012, respectively; and depreciable common utility plant was 8.5%, 11.4% and 11.6% in 2014, 2013 and 2012, respectively. The decrease in depreciable common utility plant that occurred between 2014 and 2013 was primarily due to asset retirement. Depreciation on other property, plant and equipment is calculated primarily on a straight-line basis over the useful lives of the assets. The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability. Goodwill In 2009, Puget Holdings completed its merger with Puget Energy. Puget Energy remeasured the carrying amount of all its assets and liabilities to fair value, which resulted in recognition of approximately $1.7 billion in goodwill. ASC 350, “Intangibles—Goodwill and Other” (ASC 350), requires that goodwill be tested for impairment at the reporting unit level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. These events or circumstances could include a significant change in the Company’s business or regulatory outlook, legal factors, a sale or disposition of a significant portion of a reporting unit or significant changes in the financial markets which could influence the Company’s access to capital and interest rates. Application of the goodwill impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, assignment of goodwill to reporting units and the determination of the fair value of the reporting units. Management has determined Puget Energy has only one reporting unit. The goodwill recorded by Puget Energy represents the potential long-term return to the Company’s investors. Goodwill is tested for impairment annually using a two-step process. The first step compares the carrying amount of the reporting unit with its fair value, with a carrying value higher than fair value indicating potential impairment. If the first step test fails, the second step is performed. This would entail a full valuation of Puget Energy’s assets and liabilities and comparing the valuation to its carrying amounts, with the aggregate difference indicating the amount of impairment. Goodwill of a reporting unit is required to be tested for impairment on an interim basis if an event occurs or circumstances change that would cause the fair value of a reporting unit to fall below its carrying amount. Puget Energy conducted its annual impairment test in 2014 using an October 1, 2014 measurement date. The fair value of Puget Energy’s reporting unit was estimated using both discounted cash flow and market approach. Such approaches are considered methodologies that market participants would use. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term rate of growth for Puget Energy business, estimation of the useful life over which cash flows will occur, the selection of utility holding companies determined to be comparable to Puget Energy and determination of an appropriate weighted-average cost of capital or discount rate. The market approach estimates the fair value of the business based on market prices of stocks of comparable companies engaged in the same or similar lines of business. In addition, indications of market value are estimated by deriving multiples of equity or invested capital to various measures of revenue, earnings or cash flow. Changes in these estimates and/or assumptions could materially affect the determination of fair value and goodwill impairment of the reporting unit. Based on the test performed, management has determined that there was no indication of impairment of Puget Energy’s goodwill as of October 1, 2014. There were no known events or circumstances from the date of the assessment through December 31, 2014 that would impact management’s conclusion. Cash and Cash Equivalents Cash and cash equivalents consist of demand bank deposits and short-term highly liquid investments with original maturities of three months or less at the time of purchase. The cash and cash equivalents balance at Puget Energy was $37.5 million and $44.3 million as of December 31, 2014 and 2013, respectively. The 2014 and 2013 balance consisted of cash equivalents, which are reported at cost and approximate fair value, and were $1.8 million and $2.6 million, respectively. Materials and Supplies Materials and supplies are used primarily in the operation and maintenance of electric and natural gas distribution and transmission systems as well as spare parts for combustion turbines used for the generation of electricity. Puget Energy and PSE record these items at weighted-average cost. Fuel and Gas Inventory Fuel and gas inventory is used in the generation of electricity and for future sales to the Company’s natural gas customers. Fuel inventory consists of coal, diesel and natural gas used for generation. Gas inventory consists of natural gas and Liquefied Natural Gas (LNG) held in storage for future sales. Puget Energy and PSE record these items at the lower of cost or market value using the weighted-average cost method. Regulatory Assets and Liabilities PSE accounts for its regulated operations in accordance with ASC 980 “Regulated Operations” (ASC 980). ASC 980 requires PSE to defer certain costs that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. It similarly requires deferral of revenues or gains and losses that are expected to be returned to customers in the future. Accounting under ASC 980 is appropriate as long as rates are established by or subject to approval by independent third-party regulators; rates are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that rates set at levels that will recover costs can be charged to and collected from customers. In most cases, PSE classifies regulatory assets and liabilities as long-term due to the length of the amortization. For further details regarding regulatory assets and liabilities, see Note 3. Allowance for Funds Used During Construction AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. The amount of AFUDC recorded in each accounting period varies depending principally upon the level of construction work in progress and the AFUDC rate used. AFUDC is capitalized as a part of the cost of utility plant and is credited to interest expense and as a non-cash item to other income. Cash inflow related to AFUDC does not occur until these charges are reflected in rates. The AFUDC rates authorized by the Washington Commission for natural gas and electric utility plant additions based on the effective dates are as follows: Effective Date Washington Commission July 1, 2013 - present 7.77 % May 14, 2012 - June 30, 2013 7.80 April 8, 2010 - May 13, 2012 8.10 The Washington Commission authorized the Company to calculate AFUDC using its allowed rate of return. To the extent amounts calculated using this rate exceed the AFUDC calculated rate using the Federal Energy Regulatory Commission (FERC) formula, PSE capitalizes the excess as a deferred asset, crediting other income. The deferred asset is being amortized over the average useful life of PSE’s non-project electric utility plant which is approximately 30 years. Revenue Recognition Operating utility revenue is recognized when the basis of services is rendered, which includes estimated unbilled revenue, in accordance with ASC 605, “Revenue Recognition” (ASC 605). PSE’s estimate of unbilled revenue is based on a calculation using meter readings from its automated meter reading (AMR) system. The estimate calculates unbilled usage at the end of each month as the difference between the customer meter readings on the last day of the month and the last customer meter readings billed. The unbilled usage is then priced at published rates for each schedule to estimate the unbilled revenues by customer. The non-utility subsidiary recognizes revenue when services are performed or upon the sale of assets. Revenue from retail sales is billed based on tariff rates approved by the Washington Commission. Sales of Renewable Energy Credits (RECs) are deferred as a regulatory liability. Beginning July 1, 2013, 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 are deferred to a regulatory asset for under recovery or regulatory liability for over recovery. Revenues associated with power costs under the PCA mechanism and PGA rates are excluded from the decoupling mechanism. The decoupling mechanism reduces earnings volatility, but does not materially affect the timing of cash flow due to the timing difference between the recognition of decoupling revenue and resulting impacts on rates. Allowance for Doubtful Accounts Allowance for doubtful accounts are provided for electric and natural gas customer accounts based upon a historical experience rate of write-offs of energy accounts receivable along with information on future economic outlook. The allowance account is adjusted monthly for this experience rate. The allowance account is maintained until either receipt of payment or the likelihood of collection is considered remote at which time the allowance account and corresponding receivable balance are written off. The Company’s allowance for doubtful accounts at December 31, 2014 and 2013 was $7.5 million and $7.4 million, respectively. Self-Insurance PSE is self-insured for storm damage and environmental contamination occurring on PSE-owned property. In addition, PSE is required to meet a deductible for a portion of the risk associated with comprehensive liability, workers’ compensation claims and catastrophic property losses other than those which are storm related. The Washington Commission has approved the deferral of certain uninsured qualifying storm damage costs that exceed $8.0 million which will be requested for collection in future rates. Additionally, costs may only be deferred if the outage meets the Institute of Electrical and Electronics Engineers (IEEE) outage criteria for system average interruption duration index. Federal Income Taxes For presentation in Puget Energy and PSE’s separate financial statements, income taxes are allocated to the subsidiaries on the basis of separate company computations of tax, modified by allocating certain consolidated group limitations which are attributed to the separate company. Taxes payable or receivable are settled with Puget Holdings. Natural Gas Off-System Sales and Capacity Release PSE contracts for firm natural gas supplies and holds firm transportation and storage capacity sufficient to meet the expected peak winter demand for natural gas by its firm customers. Due to the variability in weather, winter peaking consumption of natural gas by most of its customers and other factors, PSE holds contractual rights to natural gas supplies and transportation and storage capacity in excess of its average annual requirements to serve firm customers on its distribution system. For much of the year, there is excess capacity available for third-party natural gas sales, exchanges and capacity releases. PSE sells excess natural gas supplies, enters into natural gas supply exchanges with third parties outside of its distribution area and releases to third parties excess interstate natural gas pipeline capacity and natural gas storage rights on a short-term basis to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. The proceeds from such activities, net of transactional costs, are accounted for as reductions in the cost of purchased natural gas and passed on to customers through the PGA mechanism, with no direct impact on net income. As a result, PSE nets the sales revenue and associated cost of sales for these transactions in purchased natural gas. Non-Core Gas Sales As part of the Company’s electric operations, PSE provides natural gas to its gas-fired generation facilities. The projected volume of natural gas for power is relative to the price of natural gas. Based on the market prices for natural gas, PSE may use the gas it has already purchased to generate power or PSE may sell the already purchased natural gas. The net proceeds from selling natural gas, previously purchased for power generation, are accounted for in other electric operating revenue and are included in the PCA mechanism. Production Tax Credit Production Tax Credits (PTCs) represent federal income tax incentives available to taxpayers that generate energy from qualifying renewable sources. PSE records the benefit of the PTCs as a regulatory liability until such time as PSE utilizes the tax credit on its tax return. Once utilized, PSE will pass the benefit to customers. Accounting for Derivatives ASC 815 requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value unless the contracts qualify for an exception. PSE enters into derivative contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts and swaps. Some of PSE’s physical electric supply contracts qualify for the Normal Purchase Normal Sale (NPNS) exception to derivative accounting rules. PSE may enter into financial fixed price contracts to economically hedge the variability of certain index-based contracts. Those contracts that do not meet the NPNS exception are marked-to-market to current earnings in the statements of income, subject to deferral under ASC 980, for energy related derivatives due to the PCA mechanism and PGA mechanism. Puget Energy and PSE elected to de-designate all energy related derivative contracts previously recorded as cash flow hedges for the purpose of simplifying its financial reporting in 2009. The contracts that were de-designated related to physical electric supply contracts and natural gas swap contracts used to fix the price of natural gas for electric generation. For these contracts and for contracts initiated after such date, all mark-to-market adjustments are recognized through earnings. The amount previously recorded in accumulated OCI is transferred to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if management determines that the forecasted transaction is probable of not occurring. As a result, the Company will continue to experience the earnings impact of these reversals from OCI in future periods. When these contracts are settled, the contract price becomes part of purchased electricity or electric generation fuel which becomes part of PSE’s PCA mechanism and the unrealized gain or loss is listed separately under energy costs, as it represents the non-rate treatment of energy costs. The Company may enter into swap instruments or other financial derivative instruments to manage the interest rate risk associated with its long-term debt financing and debt instruments. As of December 31, 2014, Puget Energy has interest rate swap contracts outstanding related to its long-term debt. For additional information, see Note 9 Accounting for Derivative Instruments and Hedging Activities. Fair Value Measurements of Derivatives ASC 820, “Fair Value Measurements and Disclosures” (ASC 820), defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). As permitted under ASC 820, the Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements as it believes that the approach is used by market participants for these types of assets and liabilities. Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company values derivative instruments based on daily quoted prices from an independent external pricing service. When external quoted market prices are not available for derivative contracts, the Company uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves. All derivative instruments are sensitive to market price fluctuations that can occur on a daily basis. For additional information, see Note 10 Fair Value Measurements. Debt Related Costs Debt premiums, discounts, expenses and amounts received or incurred to settle hedges are amortized over the life of the related debt for the Company. The premiums and costs associated with reacquired debt are deferred and amortized over the life of the related new issuance, in accordance with ratemaking treatment for PSE. Accumulated Other Comprehensive Income (Loss) The following tables set forth the components of the Company’s accumulated other comprehensive income (loss) at: Puget Energy December 31, (Dollars in Thousands) 2014 2013 Net unrealized loss on energy derivative instruments $ (333 ) $ (705 ) Net unrealized loss on interest rate swaps — (94 ) Net unrealized loss and prior service cost on pension plans (36,710 ) 48,514 Total Puget Energy, net of tax $ (37,043 ) $ 47,715 Puget Sound Energy December 31, (Dollars in Thousands) 2014 2013 Net unrealized loss on energy derivative instruments $ (686 ) $ (2,027 ) Net unrealized loss on treasury interest rate swaps (5,990 ) (6,307 ) Net unrealized loss and prior service cost on pension plans (164,281 ) (87,405 ) Total PSE, net of tax $ (170,957 ) $ (95,739 )

New Accounting Pronouncements

New Accounting Pronouncements	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements	(2) New Accounting Pronouncements Revenue Recognition In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, “ Revenue from Contracts with Customers (Topic 606) In August 2015, the FASB issued ASU 2015-14, “ Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” Consolidation—Variable Interest Entities In February 2015, the FASB issued ASU 2015-02, “ Consolidation (Topic 810): Amendments to the Consolidation Analysis ASU 2015-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted, including adoption in an interim period. Currently, the Company does not have any fee arrangements described under this new amendment with any legal entities. As such, the Company does not expect this guidance to have a material impact on our results of operations or financial position. 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. In August 2015, the FASB issued ASU 2015-15, “ Interest-Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangement ASU 2015-03 and ASU 2015-15 are 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 the amendments during the first quarter of fiscal year 2016. The amount of unamortized debt issuance costs as of September 30, 2015 and December 31, 2014 totaled $39.6 million and $35.7 million, respectively. 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 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 year 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) 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 year 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. 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 year 2017. Retirement Benefits In July 2015, the FASB issued ASU 2015-12, “ Plan Accounting: Defined Benefit Pension Plans (Topic 960), Defined Contribution Pension Plans (Topic 962), and Health and Welfare Benefit Plans (Topic 965). Part I requires fully benefit-responsive contracts to be measured, presented and disclosed only at contract value. Part II requires both participant-directed and nonparticipant-directed investments of employee benefit plans be grouped only by general type, and removes the requirement to include the disclosure of (i) the investment strategy of an investment measured using the net asset value per share practical expedient and is part of a fund that files a U.S. Department of Labor Form 5500; and (ii) the net appreciation or depreciation for investments by general type. Part III provides entities that have a fiscal year-end that does not coincide with a month-end a practical expedient to permit plans to measure investments and investment-related accounts as of a month-end date that is closest to the plan’s fiscal year-end. All three parts are effective for fiscal years beginning after December 15, 2015, and early adoption is permitted for each part. Parts I and II must be applied retrospectively for all financial statements presented. The amendments in Part III must be applied prospectively. The Company plans to adopt ASU 2015-12 during the first quarter of fiscal year 2016 and is in the process of evaluating the potential impacts, if any, of this new guidance on its financial statements. Derivatives and Hedging In August 2015, the FASB Issues ASU 2015-13, “ Derivatives and Hedging (Topic 815): Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets. This amendment was effective upon issuance, and if elected, the guidance must be applied prospectively. The Company does not expect this guidance to have a material impact on our results of operations or financial position.	(2) New Accounting Pronouncements Income Statement In May 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-09, “Revenue from Contracts with Customers (Topic 606)”, that 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. ASU 2014-09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. Early adoption of the ASU is not permitted. Entities 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. Extraordinary and Unusual Items In January 2015, the FASB issued ASU 2015-01, “Income Statement—Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items.” As part of FASB’s initiative to reduce complexity in accounting standards, it issued ASU 2015-01, which eliminates from GAAP the concept of extraordinary items. Currently, Subtopic 225-20 requires an entity to separately classify, present and disclose extraordinary events and transactions. ASU 2015-01 will align GAAP income statement presentation guidance with International Accounting Standards 1, Presentation of Financial Statements, which prohibits the presentation and disclosure of extraordinary items. ASU 2015-01 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The Company is permitted to apply amendments prospectively or retrospectively to all prior periods presented in the financial statements. Early adoption is permitted, provided that the guidance is applied from the beginning of the fiscal year of adoption. At this time, the Company doesn’t expect this standard to have a material effect on the Company’s financial position or results of operations.

Regulation and Rates

Regulation and Rates	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Regulation And Rates [Abstract]
Regulation and Rates	(6) 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%. Following an appeal and remand, 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 August 7, 2015 the Washington Commission issued an order approving the settlement proposing changes to the PCA mechanism. The settlement agreement will 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; and • 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. On September 18, 2015, PSE filed 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 decrease of $185.9 million, or 17.4%, with no impact on net operating income.	(3) Regulation and Rates Regulatory Assets and Liabilities ASC 980 requires PSE to defer certain costs that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. It similarly requires deferral of revenues or gains and losses that are expected to be returned to customers in the future. Below is a chart with the allowed return on the net regulatory assets and liabilities and the associated time periods: Period Rate of Return After-Tax Return July 1, 2013 - present 7.77 % 6.69 % May 14, 2012 - June 30, 2013 7.80 6.71 April 8, 2010 - May 13, 2012 8.10 6.90 The net regulatory assets and liabilities at December 31, 2014 and 2013 included the following: Puget Sound Energy Remaining Amortization December 31, (Dollars in Thousands) 2014 2013 PGA deferral of unrealized losses on derivative instruments (a) $ 69,280 $ 27,555 Chelan PUD contract initiation 16.8 Years 119,316 126,404 Storm damage costs electric 1 to 4 years 118,824 116,328 Environmental remediation (a) 66,018 57,342 Baker Dam licensing operating and maintenance costs 44 years 61,577 57,270 Snoqualmie licensing operating and maintenance costs 30 years 9,202 10,881 Colstrip common property 9.5 years 6,764 7,479 Deferred income taxes (a) 94,913 146,350 Deferred Washington Commission AFUDC 35 years 53,709 55,495 Energy conservation costs 1 to 2 years 42,374 35,987 Unamortized loss on reacquired debt 1 to 21.5 years 35,667 37,832 White River relicensing and other costs 17.9 years 26,685 28,190 Mint Farm ownership and operating costs 10.3 years 20,320 22,320 Investment in Bonneville Exchange power contract 2.5 years 8,816 12,343 Ferndale 4.8 years 19,232 22,811 Lower Snake River 1.3 to 22.3 years 86,275 92,924 Snoqualmie 3.8 years 6,798 8,009 Property tax tracker Less than 2 years 32,253 22,134 PGA receivable 1 year 21,073 — PCA mechanism (a) 4,623 — Electron unrecovered loss 4 years 14,008 — Decoupling under-collection Less than 2 years 55,363 — Various other regulatory assets Varies 14,312 8,078 Total PSE regulatory assets $ 987,402 $ 895,732 Cost of removal (b) $ (313,088 ) $ (269,536 ) Production tax credits (c) (93,616 ) (93,618 ) PGA payable 1 year — (5,938 ) PCA mechanism (a) — (5,345 ) Decoupling over-collection Less than 2 years (12,582 ) (20,535 ) Summit purchase option buy-out 5.8 years (9,188 ) (10,763 ) Deferred gain on Jefferson County sale Less than 1 year (4,731 ) (60,844 ) Deferred credit on Biogas sale 1 year (1,445 ) (10,908 ) Deferred credit on gas pipeline capacity Varies up to 3.8 years (3,564 ) (4,508 ) Renewable energy credits 1 year (2,383 ) (5,820 ) Treasury grants 5 to 44 years (180,496 ) (203,889 ) Deferral of treasury grant amortization Less than 4 years (8,197 ) — Various other regulatory liabilities Up to 4 years (6,092 ) (5,755 ) Total PSE regulatory liabilities $ (635,382 ) $ (697,459 ) PSE net regulatory assets (liabilities) $ 352,020 $ 198,273 (a) Amortization periods vary depending on timing of underlying transactions or awaiting regulatory approval in a future Washington Commission rate proceeding. (b) The balance is dependent upon the cost of removal of underlying assets and the life of utility plant. (c) Amortization will begin once PTCs are utilized by PSE on its tax return. Puget Energy Remaining Amortization December 31, (Dollars in Thousands) 2014 2013 Total PSE regulatory assets (a) $ 987,402 $ 895,732 Puget Energy acquisition adjustments: Regulatory assets related to power contracts 1 to 22 years 29,816 33,753 Various other regulatory assets Varies 561 517 Total Puget Energy regulatory assets $ 1,017,779 $ 930,002 Total PSE regulatory liabilities (a) $ (635,382 ) $ (697,459 ) Puget Energy acquisition adjustments: Regulatory liabilities related to power contracts 1 to 37 years (391,389 ) (443,065 ) Various other regulatory liabilities Varies (2,820 ) (2,884 ) Total Puget Energy regulatory liabilities $ (1,029,591 ) $ (1,143,408 ) Puget Energy net regulatory asset (liabilities) $ (11,812 ) $ (213,406 ) (a) Puget Energy’s regulatory assets and liabilities include purchase accounting adjustments under ASC 805 as a result of the merger. If the Company determines that it no longer meets the criteria for continued application of ASC 980, the Company would be required to write off its regulatory assets and liabilities related to those operations not meeting ASC 980 requirements. Discontinuation of ASC 980 could have a material impact on the Company’s financial statements. In accordance with guidance provided by ASC 410, “Asset Retirement and Environmental Obligations,” PSE reclassified from accumulated depreciation to a regulatory liability $313.1 million and $269.5 million in 2014 and 2013, respectively, for the cost of removal of utility plant. These amounts are collected from PSE’s customers through depreciation rates. Electric Regulation and Rates Storm Damage Deferral Accounting The Washington Commission issued a general rate case order that defined deferrable catastrophic/extraordinary losses and provided that costs in excess of $8.0 million annually may be deferred for qualifying storm damage costs that meet the modified IEEE outage criteria for system average interruption duration index. In 2014 and 2013, PSE incurred $29.7 million and $9.4 million, respectively, in storm-related electric transmission and distribution system restoration costs, of which $18.0 million was deferred in 2014 and no amount was deferred in 2013. Power Cost Only Rate Case Power Cost Only Rate Case (PCORC), a limited-scope proceeding, was approved in 2002 by the Washington Commission to periodically reset power cost rates. In addition to providing the opportunity to reset all power costs, the PCORC proceeding also provides for timely review of new resource acquisition costs and inclusion of such costs in rates at the time the new resource goes into service. To achieve this objective, the Washington Commission has used an expedited six-month PCORC decision timeline rather than the statutory 11-month timeline for a general rate case. On October 23, 2013, the Washington Commission approved an update on the Company’s PCORC, effective November 1, 2013, which reflected decreases in the overall normalized power supply costs. This resulted in an estimated revenue decrease of $10.5 million or 0.5% annually. On November 3, 2014 the Washington Commission issued an order on the settlement of the PCORC which PSE 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 0.90% annually, as a result of the settlement, effective December 1, 2014. Electric Rate Case 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 of $10.6 million, or 0.5% annually, and a rate decrease for natural gas 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 of $11.0 million, or 0.5% annually, and a rate increase for natural gas 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 of $12.2 million, or 0.5% annually, and a rate increase for natural gas of $0.3 million. On November 3, 2014 the Washington Commission approved PSE’s 2014 PCORC. 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 with an effective date of December 1, 2014. PSE filed joint testimony supporting a settlement stipulation. Customer rates decreased by approximately $19.4 million or 0.90% as a result of the settlement, effective December 1, 2014. 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 estimated revenue impact of the decoupling mechanism for electric is an increase of $21.4 million, or 1.0% annually. The estimated revenue impact of the ERF filings for electric is an increase of $30.7 million, or 1.5% annually. In its order, the Washington Commission approved a weighted cost of capital of 7.8% and a capital structure that included 48.0% common equity with a return on equity of 9.8%. Subsequently, certain parties to this proceeding petitioned the Washington Commission to reconsider the order. On December 13, 2013, the Washington Commission approved the settlement agreements for rates effective January 1, 2014. These settlement agreements do not materially change the revenues originally approved in June 2013. 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 (ICNU) 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. The parties’ petition argues that the order violates various procedural and substantive requirements of the Washington Administrative Procedure Act, and so requests 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 letter 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 general rate case, but reversed and remanded the cost of equity for further adjudication consistent with the court’s decision. As a result, there will be evidentiary proceedings regarding Return on Equity (ROE) in February 2015 with an order anticipated in the first half of 2015. On May 7, 2012, the Washington Commission issued its order in PSE’s electric general rate case filed in June 2011, approving a general rate increase for electric customers of $63.3 million or 3.2% annually. The rate increases for electric customers became effective May 14, 2012. In its order, the Washington Commission approved a weighted cost of capital of 7.8% and a capital structure that included 48.0% common equity with a return on equity of 9.8%. PSE’s requested treatment of the prepayments made to Bonneville Power Administration (BPA), filed in May 2010, was approved in the order. The final order rejected PSE’s proposed conservation savings adjustment. Finally, a new rate rider for RECs was proposed by settlement of electric parties and approved by the Washington Commission in the final order. The following table sets forth electric rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Type of Rate Adjustment Effective Date Average Increase (Decrease) PCORC December 1, 2014 (0.9 )% $ (19.4 ) Conservation Rider May 1, 2014 0.5 % 12.2 Decoupling Rate Filing May 1, 2014 0.5 10.6 Property Tax Tracker May 1, 2014 0.5 11.0 PCORC November 1, 2013 0.5 10.5 Decoupling Rate Filing July 1, 2013 1.0 21.4 Expedited Rate Filing July 1, 2013 1.5 30.7 Electric General Rate Case May 14, 2012 3.2 63.3 In addition, PSE will be increasing the allowed delivery revenue per customer under the decoupling filing by 3.0% for electric customers on January 1 of each year until the conclusion of PSE’s next general rate case. Accounting Orders and Petitions On November 27, 2013, the Washington Commission issued an order authorizing PSE to provide the net proceeds from the sale of natural gas supply produced from a landfill-gas recovery project in King County (Biogas) prior to October 31, 2013 as a bill credit to customers over a one-year period in its RECs adjusting price schedule which became effective January 1, 2014. Additionally, the Washington Commission order authorized that all net proceeds from Biogas produced after October 31, 2013 plus the internal labor needed to obtain the net proceeds is reflected as a PSE below-the-line item (i.e., not included in the revenues and expenses considered when setting electric customer rates) and excluded from utility operations. PSE completed the sale of its electric infrastructure assets located in Jefferson County and the transition of electrical services in the county to JPUD on March 31, 2013. The proceeds from the sale exceeded the transferred assets’ net carrying value of $46.7 million resulting in a pre-tax gain of approximately $60.0 million. In its 2010 order on the subject, the Washington Commission stated that PSE must file an accounting and ratemaking petition with the Washington Commission to determine how this gain will be allocated between customers and shareholders. As a result, the gain was deferred and recorded as a regulatory liability pending the Washington Commission’s determination of the accounting and ratemaking treatment. On October 31, 2013, PSE filed an accounting petition for a Washington Commission order that would authorize PSE to retain the gain of $45.0 million and return $15.0 million to its remaining customers over a period of 48 months. On March 28, 2014, intervenors filed response testimonies containing their respective proposals for allocation of the gain, which included a proposal of up to $57.0 million to customers and $3.0 million to PSE. A final order was rendered on September 11, 2014 authorizing PSE to retain $7.5 million of the gain and return $52.7 million to customers. The customer portion is booked to a regulatory liability account in other current liabilities and accruing interest at PSE’s after-tax rate of return. PSE and the parties to the case filed a joint motion to amend the final order to allow for the customer portion to be paid to customers through a bill credit in the month of December 2014. The Commission granted the joint motion on October 1, 2014. PCA Mechanism In 2002, the Washington Commission approved a PCA mechanism that provides for a rate adjustment process if PSE’s costs to provide customers’ electricity vary from a baseline power cost rate established in a rate proceeding. All significant variable power supply cost variables (hydroelectric and wind generation, market price for purchased power and surplus power, natural gas and coal fuel price, generation unit forced outage risk and transmission cost) are included in the PCA mechanism. The PCA mechanism apportions increases or decreases in power costs, on a calendar year basis, between PSE and its customers on a graduated scale. The graduated scale is as follows: Annual Power Cost Variability Customers’ Company’s +/- $20 million 0 % 100 % +/- $20 million - $40 million 50 % 50 % +/- $40 million - $120 million 90 % 10 % +/- $120 + million 95 % 5 % Treasury Grant Section 1603 of the American Recovery and Reinvestment Tax Act of 2009 (Section 1603) authorizes the United States Department of the Treasury (U.S. Treasury) to make grants (Treasury Grants) to taxpayers who place specified energy property in service provided certain conditions are met. Section 1603 precludes a recipient from claiming PTCs on property for which a grant is claimed. PSE received two treasury grants with a total amount of $107.9 million, related to Baker and Snoqualmie hydro facilities. These grants have been accounted as a reduction to utility plant and will be amortized over the life of the plant based on the Washington Commission authorization. The Wild Horse Wind Project (Wild Horse) expansion facility was placed into service on November 9, 2009. The capacity of the Wild Horse facility was expanded from 229 megawatts (MW) to 273 MW through the addition of wind turbines. In February 2010, the U.S. Treasury approved a Treasury Grant of $28.7 million. The 343 MW Lower Snake River facility was placed into service on February 29, 2012. In December 2012, the U.S. Treasury approved a Treasury Grant of $205.3 million. On February 29, 2012, PSE filed proposed tariff revisions, with stated effective dates of April 1, 2012, and subsequently revised by filing on March 29, 2012 with stated effective dates of June 1, 2012, to pass-through $2.4 million in interest on the unamortized balance of the Wild Horse Expansion Treasury Grant. On June 26, 2012, the Washington Commission approved PSE’s methods and calculations and new rates became effective on July 3, 2012. On January 31, 2013, the Washington Commission approved a rate change to the PSE’s Federal Incentive Tracker tariff, effective February 1, 2013, which incorporated the effects of the Treasury Grant related to the Lower Snake River wind generation project and keeping the ten year amortization period and inclusion of interest on the unamortized balance of the grants. The rate change passed through 11 months of amortization for both grants to eligible customers over 11 months beginning February 1, 2013. Of the total credit, $34.6 million represents the pass-back of grant amortization and $23.8 million represents the pass through of interest. This represents an overall average rate decrease of 2.8%. On December 27, 2013, the Washington Commission approved the annual true-up and rate filing to the PSE’s Federal Incentive Tracker tariff, effective January 1, 2014. The true-up filing resulted in a total credit of $58.5 million to be passed back to eligible customers over the twelve months beginning January 1, 2014. Of the total credit, $37.8 million represents the pass-back of grant amortization and $20.6 million represents the pass through of interest, in addition to a minor true-up associated with the 2013 rate period. This filing represents an overall average rate increase of 0.3%. Gas Regulation and Rates Gas General Rate Cases and Other Filings Affecting Rates On May 7, 2012, the Washington Commission issued its order in PSE’s natural gas general rate case filed in June 2011, approving a general rate increase for natural gas customers of $13.4 million, or 1.3% annually. The rate increases for natural gas customers became effective May 14, 2012. In its order, the Washington Commission approved a weighted cost of capital of 7.8% and a capital structure that included 48.0% common equity with a return on equity of 9.8%. On June 1, 2012, PSE filed with the Washington Commission a petition seeking an Accounting Order authorizing PSE to change the existing natural gas conservation tracker mechanism into a rider mechanism to be consistent with the electric conservation program recovery. The accounting petition requested the ability to recover the costs associated with the Company’s current gas conservation programs via transfers from amounts deferred for the over-recovery of commodity costs in the Company’s PGA mechanism. The Commission granted PSE’s accounting petition on June 28, 2012. The approved accounting petition resulted in an increase to gas conservation revenues of $6.9 million and an increase to conservation amortization expense of $6.6 million. On June 25, 2013, the Washington Commission approved PSE’s electric and natural gas decoupling mechanism and ERF tariff filings, effective July 1, 2013. The estimated revenue impact of the decoupling mechanism for natural gas is an increase of $10.8 million, or 1.1% annually. The estimated revenue impact of the ERF filings for natural gas is a decrease of $2.0 million, or a decrease of 0.2% annually. In its order, the Washington Commission approved a weighted cost of capital of 7.8% and a capital structure that included 48.0% common equity with a return on equity of 9.8%. Subsequently, certain parties to this proceeding petitioned the Washington Commission to reconsider the order. On December 13, 2013, the Washington Commission approved a series of settlement agreements for rates effective January 1, 2014. These settlement agreements do not materially change the revenues originally approved in June 2013. As a result, certain high volume natural gas industrial customers rate schedules are excluded from the decoupling mechanism and will be subject to certain effects of abnormal weather, conservation impacts and changes in customer usage patterns. 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 (ICNU) each filed a petition in Thurston County Superior Court (the Court) seeking judicial review of various aspects of the Washington Commission’s ERF and decoupling mechanism final order. The parties’ petition argues that the order violates various procedural and substantive requirements of the Washington Administrative Procedure Act, and so requests 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 letter decision in which it affirmed the attrition adjustment K-Factor and the Washington Commission’s decision not to consider the case as a general rate case, but reversed and remanded the cost of equity for further adjudication consistent with the court’s decision. As a result, there will be evidentiary proceedings regarding ROE in February 2015 with an order anticipated in the first half of 2015. Purchased Gas Adjustment PSE has a PGA mechanism in retail natural gas rates to recover variations in natural gas supply and transportation costs. Variations in natural gas rates are passed through to customers; therefore, PSE’s net income is not affected by such variations. Changes in the PGA rates affect PSE’s revenue, but do not impact net operating income as the changes to revenue are offset by increased or decreased purchased gas and gas transportation costs. 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 decrease of $23.3 million , or 2.5% annually, with no impact on net operating income. On October 30, 2013, the Washington Commission approved PSE’s PGA natural gas tariff, effective on November 1, 2013, which reflected changes in wholesale gas and pipeline transportation costs and changes in deferral amortization rates. The estimated revenue impact of the approved change is an increase of $4.0 million, or 0.4% annually, with no impact on net operating income. On October 31, 2012, the Washington Commission approved PSE’s PGA natural gas tariff filing and allowed the rates to go into effect on November 1, 2012 on a temporary basis subject to revision. The rates resulted in a decrease to the rates charged to customers under the PGA. On May 1, 2013, the Washington Commission approved the proposed rates and allowed them to be made permanent. The estimated revenue impact of the approved change is a decrease of $77.0 million, or 7.7% annually, with no impact on net operating income. The following table sets forth natural gas rate adjustments that were approved by the Washington Commission and the corresponding impact to PSE’s annual revenue based on the effective dates: Type of Rate Adjustment Effective Date Average Annual Purchased Gas Adjustment November 1, 2014 (2.5 )% $ (23.3 ) Decoupling Rate Filing May 1, 2014 (0.1 ) (1.0 ) Purchased Gas Adjustment November 1, 2013 0.4 4.0 Decoupling Rate Filing July 1, 2013 1.1 10.8 Expedited Rate Filing July 1, 2013 (0.2 ) (2.0 ) Purchased Gas Adjustment November 1, 2012 (7.7 ) (77.0 ) Natural Gas General Rate Case May 14, 2012 1.3 13.4 Purchased Gas Adjustment November 1, 2011 (4.3 ) (43.5 ) Natural Gas General Tariff Adjustment April 1, 2011 1.8 19.0 In addition, PSE will be increasing the allowed delivery revenue per customer under the decoupling filing by 2.2% for natural gas customers on January 1 of each year until the conclusion of PSE’s next general rate case. Environmental Remediation The Company is subject to environmental laws and regulations by the federal, state and local authorities and is required to undertake certain environmental investigative and remedial efforts as a result of these laws and regulations. The Company has been named by the Environmental Protection Agency (EPA), the Washington State Department of Ecology and/or other third parties as potentially responsible at several contaminated sites and manufactured gas plant sites. PSE has implemented an ongoing program to test, replace and remediate certain underground storage tanks (UST) as required by federal and state laws. The UST replacement component of this effort is finished, but PSE continues its work remediating and/or monitoring relevant sites. During 1992, the Washington Commission issued orders regarding the treatment of costs incurred by the Company for certain sites under its environmental remediation program. The orders authorize the Company to accumulate and defer prudently incurred cleanup costs paid to third parties for recovery in rates established in future rate proceedings, subject to Washington Commission review. The Washington Commission consolidated the gas and electric methodological approaches to remediation and deferred accounting in an order issued October 8, 2008. Per the guidance of ASC 450, “Contingencies,” the Company reviews its estimated future obligations and will record adjustments, if any, on a quarterly basis. Management believes it is probable and reasonably estimable that the impact of the potential outcomes of disputes with certain property owners and other potentially responsible parties will result in environmental remediation costs of $35.4 million for gas and $5.7 million for electric. The Company believes a significant portion of its past and future environmental remediation costs are recoverable from insurance companies, from third parties or from customers under a Washington Commission order. The Company is also subject to cost-sharing agreements with third parties regarding environmental remediation projects in Seattle, Washington and Bellingham, Washington. The Company has taken the lead for both projects. As of December 31, 2014, the Company’s share of future remediation costs is estimated to be approximately $25.2 million. The Company’s deferred electric environmental costs are $13.4 million, $12.3 million, and $10.9 million at December 31, 2014, 2013 and 2012, respectively, net of insurance proceeds. The Company’s deferred natural gas environmental costs are $52.6 million, $45.1 million, and $66.4 million at December 31, 2014, 2013 and 2012, respectively, net of insurance proceeds.

Dividend Payment Restrictions

Dividend Payment Restrictions	12 Months Ended
	Dec. 31, 2014
Dividend Payment Restrictions [Abstract]
Dividend Payment Restrictions	(4) Dividend Payment Restrictions The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE’s electric and natural gas mortgage indentures. At December 31, 2014, approximately $438.4 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant. Beginning February 6, 2009, pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE’s ratio of Adjusted Earnings Before Interest, Tax, Depreciation and Amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3 to one. The common equity ratio, calculated on a regulatory basis, was 47.7% at December 31, 2014, and the EBITDA to interest expense was 4.3 to one for the twelve months then ended. PSE’s ability to pay dividends is also limited by the terms of its credit facilities, pursuant to which PSE is not permitted to pay dividends during any Event of Default (as defined in the facilities), or if the payment of dividends would result in an Event of Default, such as failure to comply with certain financial covenants. Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission. Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than 2 to one. Puget Energy’s EBITDA to interest expense was 3.1 to one for the twelve months ended December 31, 2014. At December 31, 2014, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

Utility Plant

Utility Plant	12 Months Ended
	Dec. 31, 2014
Regulated Operations [Abstract]
Utility Plant	(5) Utility Plant Estimated Puget Energy Puget Sound Energy Utility Plant At December 31, At December 31, (Dollars In Thousands) 2014 2013 2014 2013 Electric, gas and common utility plant classified by prescribed accounts: Distribution plant 10-50 $ 4,748,988 $ 4,448,451 $ 6,417,551 $ 6,127,732 Production plant 25-125 2,973,853 2,966,223 3,907,224 3,948,270 Transmission plant 45-65 1,189,296 1,043,605 1,306,009 1,162,929 General plant 5-35 481,116 504,965 553,130 599,156 Intangible plant (including capitalized software) 3-50 311,959 316,614 304,135 309,972 Plant acquisition adjustment 7-30 242,826 242,826 282,792 282,792 Underground storage 25-60 28,859 27,857 42,494 41,501 Liquefied natural gas storage 25-45 12,628 12,622 14,498 14,492 Plant held for future use NA 54,996 28,742 55,148 28,895 Recoverable Cushion Gas NA 8,655 8,655 8,655 8,655 Plant not classified 1-100 91,519 124,589 91,519 124,589 Grant NA (105,659 ) — (105,659 ) — Capital leases, net of accumulated amortization 1 5 9,473 17,051 9,473 17,051 Less: accumulated provision for depreciation (1,611,220 ) (1,373,178 ) (4,449,680 ) (4,297,012 ) Subtotal $ 8,437,289 $ 8,369,022 $ 8,437,289 $ 8,369,022 Construction work in progress NA 239,690 310,318 239,690 310,318 Net utility plant $ 8,676,979 $ 8,679,340 $ 8,676,979 $ 8,679,340 1 Accumulated amortization of capital leases at Puget Energy was $28.4 million in 2014 and $20.8 million in 2013. Accumulated amortization of capital leases at PSE was $28.4 million in 2014 and $20.8 million in 2013. Jointly owned generating plant service costs are included in utility plant service cost at the Company’s ownership share. The following table indicates the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2014. These amounts are also included in the Utility Plant table above. Jointly Owned Generating Plants (Dollars in Thousands) Energy Company’s Puget Energy’s Share Puget Sound Energy’s Share Plant in Accumulated Plant in Accumulated Colstrip Units 1 & 2 Coal 50 % $ 158,516 $ (12,047 ) $ 293,103 $ (146,635 ) Colstrip Units 3 & 4 Coal 25 % 234,787 (28,763 ) 509,619 (303,594 ) Colstrip Units 1 – 4 Common Facilities 1 Coal various 83 (21 ) 252 (189 ) Frederickson 1 Gas 49.85 % 61,771 (5,750 ) 70,719 (14,698 ) Jackson Prairie Gas Storage 33.34 % 28,185 (4,099 ) 42,494 (18,409 ) 1 The Company’s ownership is 50% for Colstrip 1&2 and 25% for Colstrip Units 3 &4. As of December 31, 2014, there are no new Asset Retirement Obligations (ARO) in 2014 and $0.4 million in 2013. The following table describes all changes to the Company’s ARO liability: At December 31, (Dollars in Thousands) 2014 2013 Asset retirement obligation at beginning of period $ 48,687 $ 45,496 New asset retirement obligation recognized in the period — 350 Liability settled in the period (602 ) (1,188 ) Revisions in estimated cash flows (480 ) 2,769 Accretion expense 1,304 1,260 Asset retirement obligation at end of period $ 48,909 $ 48,687 The Company has identified the following obligations, as defined by ASC 410, “Asset Retirement and Environmental Obligations,” which were not recognized because the liability for these assets cannot be reasonably estimated at December 31, 2014 due to: • A legal obligation under Federal Dangerous Waste Regulations to dispose of asbestos-containing material in facilities that are not scheduled for remodeling, demolition or sales. The disposal cost related to these facilities could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated; • An obligation under Washington state law to decommission the wells at the Jackson Prairie natural gas storage facility upon termination of the project. Since the project is expected to continue as long as the Northwest pipeline continues to operate, the liability cannot be reasonably estimated; • An obligation to pay its share of decommissioning costs at the end of the functional life of the major transmission lines. The major transmission lines are expected to be used indefinitely; therefore, the liability cannot be reasonably estimated. • A legal obligation under Washington state environmental laws to remove and properly dispose of certain under and above ground fuel storage tanks. The disposal costs related to under and above ground storage tanks could not be measured since the retirement date is indeterminable; therefore, the liability cannot be reasonably estimated; • An obligation to pay decommissioning costs at the end of utility service franchise agreements to restore the surface of the franchise area. The decommissioning costs related to facilities at the franchise area could not be measured since the decommissioning date is indeterminable; therefore, the liability cannot be reasonably estimated; and • A potential legal obligation may arise upon the expiration of an existing FERC hydropower license if FERC orders the project to be decommissioned, although PSE contends that FERC does not have such authority. Given the value of ongoing generation, flood control and other benefits provided by these projects, PSE believes that the potential for decommissioning is remote and cannot be reasonably estimated.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Long-Term Debt	(6) Long-Term Debt (Dollars in Thousands) At December 31, Series Type Due 2014 2013 Puget Sound Energy: 7.350% First Mortgage Bond 2015 $ 10,000 $ 10,000 7.360% First Mortgage Bond 2015 2,000 2,000 5.197% Senior Secured Note 2015 150,000 150,000 6.750% Senior Secured Note 2016 250,000 250,000 5.500% Promissory Note 1 2017 2,412 2,412 6.740% Senior Secured Note 2018 200,000 200,000 7.150% First Mortgage Bond 2025 15,000 15,000 7.200% First Mortgage Bond 2025 2,000 2,000 7.020% Senior Secured Note 2027 300,000 300,000 7.000% Senior Secured Note 2029 100,000 100,000 3.900% Pollution Control Bond 2031 138,460 138,460 4.000% Pollution Control Bond 2031 23,400 23,400 5.483% Senior Secured Note 2035 250,000 250,000 6.724% Senior Secured Note 2036 250,000 250,000 6.274% Senior Secured Note 2037 300,000 300,000 5.757% Senior Secured Note 2039 350,000 350,000 5.795% Senior Secured Note 2040 325,000 325,000 5.764% Senior Secured Note 2040 250,000 250,000 4.434% Senior Secured Note 2041 250,000 250,000 5.638% Senior Secured Note 2041 300,000 300,000 4.700% Senior Secured Note 2051 45,000 45,000 6.974% Junior Subordinated Note 2067 250,000 250,000 Unamortized discount on senior notes (13 ) (14 ) PSE long-term debt $ 3,763,259 $ 3,763,258 Puget Energy: Fair value adjustment of PSE long-term debt $ (218,619 ) $ (229,746 ) Credit Facility 2017 — 299,000 Term-Loan 2016 100,000 — Term-Loan 2017 100,000 — Term-Loan 2016 99,000 — 6.500% Senior Secured Note 2020 450,000 450,000 6.000% Senior Secured Note 2021 500,000 500,000 5.625% Senior Secured Note 2022 450,000 450,000 Unamortized discount on senior notes (32 ) (36 ) Total Puget Energy long-term debt $ 5,243,608 $ 5,232,476 1 Puget Western, Inc., a wholly owned subsidiary of PSE, Promissory Note. PSE’s senior secured notes will cease to be secured by the pledged first mortgage bonds on the date that all of the first mortgage bonds issued and outstanding under the electric or natural gas utility mortgage indenture have been retired. As of December 31, 2014, the latest maturity date of the first mortgage bonds, other than pledged first mortgage bonds, is December 22, 2025. Puget Sound Energy Long-Term Debt PSE has in effect a shelf registration statement under which it may issue, from time to time, up to $800 million aggregate principal amount of senior notes secured by pledged first mortgage bonds. The Company remains subject to the restrictions of PSE’s indentures and credit agreements on the amount of first mortgage bonds that PSE may issue. Substantially all utility properties owned by PSE are subject to the lien of the Company’s electric and natural gas mortgage indentures. To issue additional first mortgage bonds under these indentures, PSE’s earnings available for interest must exceed certain minimums as defined in the indentures. At December 31, 2014, the earnings available for interest exceeded the required amount. Puget Sound Energy Pollution Control Bonds PSE has two series of Pollution Control Bonds (the Bonds) outstanding. Amounts outstanding were borrowed from the City of Forsyth, Montana who obtained the funds from the sale of Customized Pollution Control Refunding Bonds issued to finance pollution control facilities at Colstrip Units 3 & 4. In May 2013, PSE refinanced $161.9 million of the Bonds to a lower weighted average interest rate from 5.01% to 3.91%. The Bonds will mature on March 1, 2031. On or after March 1, 2023, the Company may elect to call the bonds at a redemption price of 100% of the principal amount thereof, without premium, plus accrued interest, if any, to the redemption date. Due to the refinance of the Bonds, Puget Energy wrote off $18.0 million of fair value related to the Bonds that were redeemed to interest expense. Each series of the Bonds is collateralized by a pledge of PSE’s first mortgage bonds, the terms of which match those of the Bonds. No payment is due with respect to the related series of first mortgage bonds so long as payment is made on the Bonds. Puget Energy Long-Term Debt At the time of the merger in 2009, Puget Energy entered into a $1.225 billion five-year term-loan and a $1.0 billion five-year capital expenditure credit facility for funding capital expenditures. In February 2012, Puget Energy entered into a $1.0 billion five-year revolving senior secured credit facility and the 2009 term loan and capital expenditure facilities were terminated. Concurrent with the closing of the new PSE credit facilities in February 2013, the Company reduced the size of Puget Energy’s credit facility to $800.0 million. The Puget Energy revolving senior secured credit facility also has an accordion feature that, upon the banks’ approval, would increase the size of the facility to $1.3 billion. In April 2014, the Company completed an amendment to the senior secured credit facility, extending the maturity from February 2017 to April 2018, updating the fee structure, eliminating a financial covenant and updating or clarifying the definitions of other terms and conditions of the facility. All other terms and conditions of that facility remain unchanged from when it was committed in 2012. As a revolving facility, amounts borrowed may be repaid without a reduction in the size of the facility. The Puget Energy revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains a financial covenant based on the Maximum Leverage Ratio, as defined in the agreement governing the senior secured credit facility. In June 2014, Puget Energy entered into three bilateral term loans, with two and three year maturities, which in total, equal $299 million. The proceeds of the term loans were used to pay off the outstanding Puget Energy revolving credit facility balance, which subsequently allows the Company to carry the debt with lower interest expense. All other terms, conditions and covenants are consistent with each other and the credit facility agreement, with the exception of maturity and price. Long-Term Debt Maturities The principal amounts of long-term debt maturities for the next five years and thereafter are as follows: (Dollars in Thousands) 2015 2016 2017 2018 2019 Thereafter Total Maturities of: PSE long-term debt $ 162,000 $ 250,000 $ 2,412 $ 200,000 $ — $ 3,148,860 $ 3,763,272 Puget Energy long-term debt — 199,000 100,000 — — 1,400,000 1,699,000 Puget Energy long-term debt $ 162,000 $ 449,000 $ 102,412 $ 200,000 $ — $ 4,548,860 $ 5,462,272 Financial Covenants Puget Energy’s credit facility contains a financial covenant related to maximum leverage. As of December 31, 2014, the Company is in compliance with its long-term debt financial covenants.

Liquidity Facilities and Other

Liquidity Facilities and Other Financing Arrangements	12 Months Ended
	Dec. 31, 2014
Liquidity Facilities And Other Financing Arrangements [Abstract]
Liquidity Facilities and Other Financing Arrangements	(7) Liquidity Facilities and Other Financing Arrangements As of December 31, 2014 and 2013, PSE had $85.0 million and $162.0 million in short-term debt outstanding, respectively, exclusive of the demand promissory note with Puget Energy. Outside of the consolidation of PSE’s short-term debt, Puget Energy had no short-term debt outstanding in either year as borrowings under its credit facilities are classified as long-term. PSE’s weighted-average interest rate on short-term debt, including borrowing rate, commitment fees and the amortization of debt issuance costs, during 2014 and 2013 was 4.05% and 3.93%, respectively. As of December 31, 2014, PSE and Puget Energy had several committed credit facilities that are described below. Puget Sound Energy Credit Facilities PSE has two unsecured revolving credit facilities which provide, in aggregate, $1.0 billion of short-term liquidity needs. These facilities consist of a $650.0 million revolving liquidity facility (which includes a liquidity letter of credit facility and a swingline facility) to be used for general corporate purposes, including a backstop to the Company’s commercial paper program and a $350.0 million revolving energy hedging facility (which includes an energy hedging letter of credit facility). The $650.0 million liquidity facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facilities also have an accordion feature which, upon the banks’ approval, would increase the total size of these facilities to $1.450 billion. In April 2014, the Company completed a one-year extension on both of the liquidity and hedging facilities, extending the maturity from February 2018 to April 2019, and updating or clarifying the definitions of other terms and conditions of the facilities from when they were committed in 2013. The credit agreements are syndicated among numerous lenders and contain usual and customary affirmative and negative covenants that, among other things, place limitations on PSE’s ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreements also contain a financial covenant of total debt to total capitalization of 65% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of December 31, 2014, PSE was in compliance with all applicable covenant ratios. The credit agreements provide PSE with the ability to borrow at different interest rate options. The credit agreements allow PSE to borrow at the bank’s prime rate or to make floating rate advances at the London Interbank Offered Rate (LIBOR) plus a spread that is based upon PSE’s credit rating. PSE must pay a commitment fee on the unused portion of the credit facilities. The spreads and the commitment fee depend on PSE’s credit ratings. As of the date of this report, the spread to the LIBOR is 1.25% and the commitment fee is 0.175%. As of December 31, 2014, no amounts were drawn and outstanding under PSE’s liquidity facility. No amounts were drawn and outstanding under the $350.0 million energy hedging facility. No letters of credit were outstanding under either facility, and $85.0 million was outstanding under the commercial paper program. Outside of the credit agreements, PSE had a $4.2 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada. Demand Promissory Note In 2006, PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a Demand Promissory Note (Note) pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy. Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lower of the weighted-average interest rates of PSE’s outstanding commercial paper interest rate or PSE’s senior unsecured revolving credit facility. Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. At December 31, 2014, the outstanding balance of the Note was $28.9 million. The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE’s financial statements. Puget Energy Credit Facility At December 31, 2014, Puget Energy maintained an $800.0 million revolving senior secured credit facility. In April, 2014, the Company completed an amendment to the senior secured credit facility, extending the maturity from February 2017 to April 2018, updating the fee structure, eliminating a financial covenant and updating or clarifying the definitions of other terms and conditions of the facility. The Puget Energy revolving senior secured credit facility also has an accordion feature which, upon the banks’ approval, would increase the size of the facility to $1.3 billion. The revolving senior secured credit facility provides Puget Energy the ability to borrow at different interest rate options and includes variable fee levels. Interest rates may be based on the bank’s prime rate or LIBOR plus a spread based on Puget Energy’s credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of December 31, 2014, there was no amount drawn and outstanding under the facility. As a result of Puget Energy’s credit rating upgrade in 2014, the spread over LIBOR was 1.75% and the commitment fee was 0.28% as of the date of this report. Puget Energy entered into interest rate swap contracts to manage the interest rate risk associated with the credit facility or similar variable rate debt. The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains a Maximum Leverage Ratio financial covenant as defined in the agreement governing the senior secured credit facility. As of December 31, 2014, Puget Energy was in compliance with all applicable covenants.

Leases

Leases	12 Months Ended
	Dec. 31, 2014
Leases [Abstract]
Leases	(8) Leases PSE leases buildings and assets under operating leases. Certain leases contain purchase options, renewal options and escalation provisions. Operating lease expenses net of sublease receipts were: (Dollars in Thousands) At December 31, 2014 $ 30,737 2013 29,392 2012 29,661 Payments received for the subleases of properties were immaterial for each of the years ended 2014, 2013 and 2012. Future minimum lease payments for non-cancelable leases net of sublease receipts are: (Dollars in Thousands) At December 31, Operating Capital 2015 $ 17,677 $ 8,160 2016 21,454 2,178 2017 22,179 — 2018 20,423 — 2019 15,180 — Thereafter 120,791 — Total minimum lease payments $ 217,704 $ 10,338

Accounting for Derivative Instr

Accounting for Derivative Instruments and Hedging Activities	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Accounting for Derivative Instruments and Hedging Activities	(3) 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 September 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. Management continues to monitor the economics of terminating the swaps, and unless the economics of terminating the swaps become more favorable, management intends to let them 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 September 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 $ — $ 7,622 $ 450 million $ — $ 9,073 Electric portfolio derivatives * 15,916 111,472 * 4,822 107,228 Natural gas derivatives (MMBtus) 4 345.6 million 6,164 69,569 360.4 million 19,526 88,807 Total derivative contracts $ 22,080 $ 188,663 $ 24,348 $ 205,108 Current $ 18,771 $ 133,061 $ 21,178 $ 142,195 Long-term 3,309 55,602 3,170 62,913 Total derivative contracts $ 22,080 $ 188,663 $ 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 ASC 980, “Regulated Operations,” due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 175.1 million One Million British Thermal Units (MMBtu) and purchased electricity of 1.1 million Megawatt Hours (MWhs) at September 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 September 30, 2015 (Dollars in Thousands) Gross Amount 1 Gross Amounts Net of Amounts Gross Amounts Not Offset in the Net Commodity Cash Collateral Assets: Energy derivative contracts $ 22,080 $ — $ 22,080 $ (18,416 ) $ — $ 3,664 Liabilities: Energy derivative contracts 181,041 — 181,041 (18,416 ) — 162,625 Interest rate swaps 2 7,622 — 7,622 — — 7,622 Puget Energy and Puget Sound Energy December 31, 2014 (Dollars in Thousands) Gross Amount 1 Gross Amounts Net of Amounts Gross Amounts Not Offset in the Net Commodity Cash Collateral 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 Nine Months Ended (Dollars in Thousands) Location 2015 2014 2015 2014 Interest rate contracts: Non-hedged interest rate swap (expense) income $ (1,156 ) $ (323 ) $ (4,571 ) $ (2,430 ) Interest expense — 1,241 560 398 Commodity contracts: Electric derivatives Unrealized gain (loss) on derivative instruments, net 1 (5,588 ) (32,648 ) 6,339 (7,714 ) Electric generation fuel (11,768 ) (420 ) (27,512 ) 8,271 Purchased electricity (8,344 ) 972 (34,489 ) 2,687 Total gain (loss) recognized in income on derivatives $ (26,856 ) $ (31,178 ) $ (59,673 ) $ 1,212 Puget Sound Energy Three Months Ended Nine Months Ended (Dollars in Thousands) Location 2015 2014 2015 2014 Commodity contracts: Electric derivatives Unrealized gain (loss) on derivative instruments, net 1 $ (5,588 ) $ (32,648 ) $ 5,795 $ (8,284 ) Electric generation fuel (11,768 ) (420 ) (27,512 ) 8,271 Purchased electricity (8,344 ) 972 (34,489 ) 2,687 Total gain (loss) recognized in income on derivatives $ (25,700 ) $ (32,096 ) $ (56,206 ) $ 2,674 1 Differences between Puget Energy and PSE for the nine months ending September 30, 2015 and September 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 nine months ended September 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 Nine 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 Nine Months Ended (Dollars in Thousands) Location 2015 2014 2015 2014 Interest rate contracts: Interest expense 1 $ (122 ) $ (122 ) $ (366 ) $ (366 ) Commodity contracts: Electric derivatives Purchased electricity — — (1,055 ) (1,104 ) Total $ (122 ) $ (122 ) $ (1,421 ) $ (1,470 ) 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 September 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 netted against the unrealized gain (loss) positions. As of September 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 September 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 September 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 September 30, 2015: Puget Energy and Puget Sound Energy (Dollars in Thousands) Contingent Feature Fair Value 1 Posted Contingent Credit rating 2 $ 27,360 $ — $ 27,360 Requested credit for adequate assurance 66,785 — — Forward value of contract 3 — — — Total $ 94,145 $ — $ 27,360 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.	(9) 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 contracts 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 December 31, 2014, Puget Energy had two interest rate swap contracts outstanding which extend to 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 Year Ended December 31, (Dollars in Thousands) Volumes (millions) Assets 1 Liabilities 2 2014 2013 2014 2013 2014 2013 Interest rate swap derivatives 3 $ 450.0 $ 450.0 $ — $ — $ 9,073 $ 13,223 Electric portfolio derivatives * * 4,822 18,479 107,228 37,312 Natural gas derivatives (MMBtus) 4 360.4 423.5 19,526 8,121 88,807 35,676 Total derivative contracts $ 24,348 $ 26,600 $ 205,108 $ 86,211 Current $ 21,178 $ 18,867 $ 142,195 $ 48,049 Long-term 3,170 7,733 62,913 38,162 Total derivative contracts $ 24,348 $ 26,600 $ 205,108 $ 86,211 1 Balance sheet location: Current and Long-term Unrealized gain on derivative instruments. 2 Balance sheet location: Current and Long-term Unrealized loss on derivative instruments. 3 Interest rate swap contracts are only held at Puget Energy. 4 PSE had a net derivative liability and an offsetting regulatory asset of $69.3 million at December 31, 2014 and $27.6 million at December 31, 2013 related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, due to the PGA mechanism. * Electric portfolio derivatives consist of electric generation fuel of 140.2 million One Million British Thermal Units (MMBtus) and purchased electricity of 5.4 million Megawatt Hours (MWhs) at December 31, 2014 and 145.6 million MMBtus and 8.6 million MWhs at December 31, 2013. For further details regarding the fair value of derivative instruments, see Note 10. 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; ISDA agreements which standardize financial gas and electric contracts; and NAESB agreements which standardize physical gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount. The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company’s derivative assets and liabilities: Puget Energy and Puget Sound Energy At December 31, 2014 (Dollars in Thousands) Gross Amounts 1 Gross Amounts Net of Amounts Gross Amounts Not Offset in the Net Amount Commodity Cash Collateral 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 Puget Energy and Puget Sound Energy At December 31, 2013 (Dollars in Thousands) Gross Amounts 1 Gross Amounts Net of Amounts Gross Amounts Not Offset in the Net Amount Commodity Cash Collateral Assets Energy Derivative Contracts $ 26,600 $ — $ 26,600 $ (19,491 ) $ — $ 7,109 Liabilities Energy Derivative Contracts $ 72,988 $ — $ 72,988 $ (19,491 ) $ — $ 53,497 Interest Rate Swaps 2 $ 13,223 $ — $ 13,223 $ — $ — $ 13,223 1. All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of Offset. 2 Interest Rate Swap Contracts are only held at Puget Energy. Due to the merger in 2009, Puget Energy recorded all derivative contracts at fair value as either assets or liabilities. Certain contracts meeting the criteria defined in ASC 815 were subsequently designated as NPNS or cash flow hedges, thereby causing differences in the derivative unrealized gains/losses to be recorded through earnings between Puget Energy and PSE. These differences will occur through February 2015. 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 Year Ended December 31, (Dollars in Thousands) Location 2014 2013 2012 Interest rate contracts: Other deductions $ (3,915 ) $ 2,420 $ (4,288 ) Interest expense 500 (5,904 ) (29,727 ) Commodity contracts: Electric derivatives Unrealized gain (loss) on derivative instruments, net 1 (84,146 ) 102,744 131,407 Electric generation fuel 6,511 (27,008 ) (66,762 ) Purchased electricity (4,212 ) (38,299 ) (138,551 ) Total gain (loss) recognized in income on derivatives $ (85,262 ) $ 33,953 $ (107,921 ) 1 For 2012, the amount differs from the amount stated in the statement of income as it does not include amortization related to contracts that were recorded at fair value at the time of the February 2009 merger and subsequently designated as NPNS of $2.2 million for the year ended December 31, 2012. Puget Sound Energy Year Ended December 31, (Dollars in Thousands) Location 2014 2013 2012 Commodity contracts: Electric derivatives Unrealized gain (loss) on derivative instruments, net $ (85,636 ) $ 98,880 $ 119,120 Electric generation fuel 6,511 (27,008 ) (66,762 ) Purchased electricity (4,212 ) (38,299 ) (138,551 ) Total gain (loss) recognized in income on derivatives $ (83,337 ) $ 33,573 $ (86,193 ) The unrealized gain or loss on derivative contracts is reported in the statement of cash flows under the operating activities section. However, at the time of the merger in 2009, 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 years ended December 31, 2014, 2013 and 2012, cash outflows related to financing activities of $16.3 million, $34.3 million and $92.7 million, respectively, were reported on Puget Energy’s statement of cash flows. For derivative instruments previously designated as cash flow hedges (including both commodity and interest rate swap contracts), the effective portion of the gain or loss on the derivative was recorded as a component of OCI, and then is reclassified into earnings in the same period(s) during which the hedged transaction affects earnings. Puget Energy and PSE expect $0.5 million and $1.1 million of losses, respectively, in accumulated OCI will be reclassified into earnings within the next twelve months. 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) on derivatives that were previously in a cash flow hedge relationship, and subsequently reclassified out of accumulated OCI into income: Puget Energy Year Ended December 31, (Dollars in Thousands) Location 2014 2013 2012 Interest rate contracts: Interest expense $ (144 ) $ (4,505 ) $ (17,811 ) Commodity contracts: Electric derivatives Electric generation fuel — — 100 Purchased electricity (572 ) (57 ) (671 ) Total $ (716 ) $ (4,562 ) $ (18,382 ) Puget Sound Energy Year Ended December 31, (Dollars in Thousands) Location 2014 2013 2012 Interest rate contracts: Interest expense $ (488 ) $ (488 ) $ (488 ) Commodity contracts: Electric derivatives Electric generation fuel — — 97 Purchased electricity (2,063 ) (3,922 ) (12,955 ) Total $ (2,551 ) $ (4,410 ) $ (13,346 ) The Company is exposed to credit risk primarily through buying and selling electricity and natural gas to serve its customers. Credit risk is the potential loss resulting from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for, among other things, counterparty credit analysis, exposure measurement, exposure monitoring and exposure mitigation. The Company monitors counterparties that have significant swings in credit default swap rates, have credit rating changes by external rating agencies, have changes in ownership or are experiencing financial distress. Where deemed appropriate, the Company may request collateral or other security from its counterparties to mitigate potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of December 31, 2014, approximately 99.3% of the Company’s energy portfolio exposure, excluding NPNS transactions, is with counterparties that are rated at least investment grade by the major rating agencies and 0.7% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated. As the Company generally enters into transactions using the WSPP, ISDA and NAESB master agreements, it believes that such agreements reduce credit risk exposure because they provide for the netting and offsetting of monthly payments and, in the event of counterparty default, termination payments. The Company computes credit reserves at a master agreement level by counterparty (i.e., WSPP, ISDA, or NAESB). The Company considers external credit ratings and market factors, such as credit default swaps and bond spreads, in the determination of reserves. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty’s risk of default. The Company uses both default factors published by Standard & Poor’s and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted-average default tenor for that counterparty’s deals. The default tenor is determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels. The Company applies the counterparty’s default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against unrealized gain (loss) positions. As of December 31, 2014, the Company was in a net liability position with the majority of counterparties, so the default factors of counterparties did not have a significant impact on reserves for the quarter. The majority of the Company’s derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. As of December 31, 2014, 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 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 December 31, 2014: Puget Energy and Puget Sound Energy Contingent Feature (Dollars in Thousands) Fair Value 1 Posted Contingent Credit rating 2 $ (37,398 ) $ — $ 37,398 Requested credit for adequate assurance (66,468 ) — — Forward value of contract 3 (2,490 ) — — Total $ (106,356 ) $ — $ 37,398 1 Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable. 2 Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral. 3 Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair Value Measurements	(10) Fair Value Measurements ASC 820 established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy categorizes the inputs into three levels with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority given to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows: Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Equity securities that are also classified as cash equivalents are considered Level 1 if there are unadjusted quoted prices in active markets for identical assets or liabilities. Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options. Level 3—Pricing inputs include significant inputs that have little or no observability as of the reporting date. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service. For interest rate swaps, the Company obtains monthly mark-to-market values from an independent external pricing service for LIBOR forward rates, which is a significant input. Some of the inputs of the interest rate swap valuations, which are less significant, include the credit standing of the counterparties, assumptions for time value and the impact of the Company’s nonperformance risk of its liabilities. The Company classifies cash and cash equivalents, and restricted cash as Level 1 financial instruments due to cash being at stated value, and cash equivalents at quoted market prices. The Company considers its electric, natural gas and interest rate swap contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. Management’s assessment was based on the trading activity in real-time and forward electric and natural gas markets. Each quarter, the Company confirms the validity of pricing-service quoted prices (e.g., Level 2 in the fair value hierarchy) used to value commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes are classified as Level 3 in the fair value hierarchy. Assets and Liabilities with Estimated Fair Value The following table presents the carrying value for cash, cash equivalents, restricted cash, notes receivable and short-term debt by level, within the fair value hierarchy. The carrying values below are representative of fair values due to the short-term nature of these financial instruments. Puget Energy Carrying / Fair Value Carrying / Fair Value At December 31, 2014 At December 31, 2013 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Cash and Cash Equivalents $ 37,527 $ — $ 37,527 $ 44,302 $ — $ 44,302 Restricted Cash 32,863 — 32,863 7,171 — 7,171 Notes Receivable and Other — 53,503 53,503 — 53,449 53,449 Total assets $ 70,390 $ 53,503 $ 123,893 $ 51,473 $ 53,449 $ 104,922 Liabilities: Short-term debt $ 85,000 $ — $ 85,000 $ 162,000 $ — $ 162,000 Total liabilities $ 85,000 $ — $ 85,000 $ 162,000 $ — $ 162,000 Puget Sound Energy Carrying / Fair Value Carrying / Fair Value At December 31, 2014 At December 31, 2013 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Cash and Cash Equivalents $ 37,466 $ — $ 37,466 $ 44,111 $ — $ 44,111 Restricted Cash 32,863 — 32,863 7,171 — 7,171 Notes Receivable and Other — 53,503 53,503 — 53,449 53,449 Total assets $ 70,329 $ 53,503 $ 123,832 $ 51,282 $ 53,449 $ 104,731 Liabilities: Short-term debt $ 85,000 $ — $ 85,000 $ 162,000 $ — $ 162,000 Short-term debt owed to parent — 28,933 28,933 — 29,598 29,598 Total liabilities $ 85,000 $ 28,933 $ 113,933 $ 162,000 $ 29,598 $ 191,598 The fair value of the junior subordinated and long-term notes were estimated using the discounted cash flow method with U.S. Treasury yields and Company credit spreads as inputs, interpolating to the maturity date of each issue. Carrying values and estimated fair values were as follows: Puget Energy December 31, 2014 December 31, 2013 (Dollars in Thousands) Level Carrying Fair Carrying Fair Liabilities: Junior subordinated notes 2 $ 250,000 $ 276,235 $ 250,000 $ 269,366 Long-term debt (fixed-rate), net of discount 2 4,694,608 6,083,554 4,683,476 5,594,314 Long-term debt (variable-rate) 2 299,000 299,000 299,000 299,000 Total $ 5,243,608 $ 6,658,789 $ 5,232,476 $ 6,162,680 Puget Sound Energy December 31, 2014 December 31, 2013 (Dollars in Thousands) Level Carrying Fair Carrying Fair Liabilities: Junior subordinated notes 2 $ 250,000 $ 276,235 $ 250,000 $ 269,366 Long-term debt (fixed-rate), net of discount 2 3,513,259 4,437,473 3,513,258 4,038,455 Total $ 3,763,259 $ 4,713,708 $ 3,763,258 $ 4,307,821 Assets and Liabilities Measured at Fair Value on a Recurring Basis The following tables present the Company’s financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis and the reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy Fair Value Fair Value (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Interest rate derivative instruments $ 9,073 $ — $ 9,073 $ 13,223 $ — $ 13,223 Total derivative liabilities $ 9,073 $ — $ 9,073 $ 13,223 $ — $ 13,223 Puget Energy and Puget Sound Energy Fair Value Fair Value (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 1,654 $ 3,168 $ 4,822 $ 14,661 $ 3,818 $ 18,479 Natural gas derivative instruments 18,064 1,462 19,526 5,448 2,673 8,121 Total assets $ 19,718 $ 4,630 $ 24,348 $ 20,109 $ 6,491 $ 26,600 Liabilities: Electric derivative instruments $ 91,998 $ 15,230 $ 107,228 $ 18,073 $ 19,239 $ 37,312 Natural gas derivative instruments 85,305 3,502 88,807 32,642 3,034 35,676 Total liabilities $ 177,303 $ 18,732 $ 196,035 $ 50,715 $ 22,273 $ 72,988 Puget Energy and Puget Sound Energy Year Ended December 31, Level 3 Roll-Forward Net 2014 2013 2012 (Dollars in Thousands) Electric Gas Total Electric Gas Total Electric Gas Total Balance at beginning of period $ (15,421 ) $ (361 ) $ (15,782 ) $ (33,924 ) $ (1,602 ) $ (35,526 ) $ (90,311 ) $ (5,041 ) $ (95,352 ) Changes during period Realized and unrealized energy derivatives: Included in earnings 1 (5,537 ) — (5,537 ) (10,491 ) — (10,491 ) (21,362 ) — (21,362 ) Included in regulatory assets / liabilities — 1,630 1,630 — (945 ) (945 ) — (1,937 ) (1,937 ) Settlements 2 1,036 (1,534 ) (498 ) 11,609 (754 ) 10,855 59,133 969 60,102 Transferred into Level 3 5,155 (585 ) 4,570 (7,799 ) — (7,799 ) (55,548 ) (297 ) (55,845 ) Transferred out of Level 3 2,705 (1,190 ) 1,515 25,184 2,940 28,124 74,164 4,704 78,868 Balance at end of period $ (12,062 ) $ (2,040 ) $ (14,102 ) $ (15,421 ) $ (361 ) $ (15,782 ) $ (33,924 ) $ (1,602 ) $ (35,526 ) 1 Income Statement location: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(9.6) million, $(13.4) million, and $(15.2) million for the years ended December 31, 2014, 2013 and 2012, respectively. 2 The Company had no purchases, sales or issuances during the reported periods. Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company’s consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company’s consolidated statements of income. In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company’s commodity contracts extend beyond what is considered observable as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next, and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month, and reported in the Level 3 Roll-forward table above. The Company did not have any transfers between Level 2 and Level 1 during the years ended December 31, 2014 and 2013. The Company does periodically transact at locations, or market price points, that are illiquid or for which no prices are available from the independent pricing service. In such circumstances the Company uses a more liquid price point and performs a 15-month regression against the illiquid locations to serve as a proxy for market prices. Such transactions are classified as Level 3. The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs. The only significant unobservable input into the fair value measurement of the Company’s Level 3 assets and liabilities is the forward price for electric and natural gas contracts. Below are the forward price ranges for the Company’s commodity contracts, as of December 31, 2014: (Dollars in Thousands) Fair Value Valuation Unobservable Range Weighted Derivative Instrument Assets 1 Liabilities 1 Low High Electric $ 3,168 $ 15,230 Discounted cash flow Power Prices $21.79 per $35.46 per $32.89 per MWh Natural gas $ 1,462 $ 3,502 Discounted cash flow Natural Gas Prices $3.11 per $3.83 per $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 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 $3.9 million. Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis At the time of merger, Puget Energy recorded the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle. ASC 360 requires long-lived assets to be tested for impairment on an annual basis, and upon the occurrence of any events or circumstances that would be more likely than not to reduce the fair value of the long-lived assets below their carrying value. One such triggering event is a significant decrease in the forward market prices of power. At December 31, 2014, Puget Energy completed a valuation and impairment test of its purchased power contracts classified as intangible assets. The valuation indicated a fair value of $437.6 million with an impairment to the Wells hydro contract. As of December 31, 2014, the carrying value for this contract was $65.3 million and its fair value on a discounted basis was $62.1 million, thereby requiring a write-down of $3.2 million to this intangible asset with a corresponding reduction in the regulatory liability. Below are significant unobservable inputs used in estimating the impaired long term power purchase contract’s fair value on December 31, 2014: Valuation Technique Unobservable Input Low High Average Discounted cash flow Power prices $19.30 per MWh $37.06 per MWh $29.53 per MWh Discounted cash flow Power contract costs $3,015 per qtr $4,783 per qtr $4,469 per qtr At June 30, 2013, Puget Energy completed a valuation and impairment test of its purchased power contracts classified as intangible assets. The valuation indicated a fair value of $484.1 million with an impairment to the Priest Rapids Reasonable Portion intangible asset contract. As of June 30, 2013, the carrying value for this intangible asset contract was $47.1 million and its fair value on a discounted basis was determined to be an asset of $33.6 million, thereby requiring a write-down of $13.5 million to the intangible asset with a corresponding reduction in the regulatory liability. Below are significant unobservable inputs used in estimating the impaired long term power purchase contract’s fair value on June 30, 2013: Valuation Technique Unobservable Input Low High Average Discounted cash flow Power prices $30.85 per MWh $65.35 per MWh $48.47 per MWh Discounted cash flow Power contract costs $389 per yr $6,845 per yr $4,110 per yr The valuations were measured using the income approach. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates which are classified as Level 3 within the fair value hierarchy. A less significant input is the discount rate reflective of PSE’s cost of capital used in the valuation.

Employee Investment Plans

Employee Investment Plans	12 Months Ended
	Dec. 31, 2014
Employee Investment Plans [Abstract]
Employee Investment Plans	(11) Employee Investment Plans The Company’s Investment Plan is a qualified employee 401(k) plan, under which employee salary deferrals and after-tax contributions are used to purchase several different investment fund options. PSE’s contributions to the employee Investment Plan were $14.9 million, $14.6 million and $14.5 million for the years 2014, 2013, and 2012, respectively. The employee Investment Plan eligibility requirements are set forth in the plan documents. Non-represented employees and United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry (UA) represented employees hired before January 1, 2014, and International Brotherhood of Electrical Workers Local Union 77 (IBEW) represented employees hired before December 12, 2014, have the following company contributions: • For employees under the Cash Balance retirement plan formula, PSE will match 100% of an employee’s contribution up to 6% of plan compensation each paycheck, and will make an additional year-end contribution equal to 1% of base pay. • For employees grandfathered under the Final Average Earning retirement plan formula, PSE will match 55% of an employee’s contribution up to 6% of plan compensation each paycheck. UA-represented employees hired on or after January 1, 2014 will have access to the 401k Plan. Non-represented employees hired on or after January 1, 2014, and IBEW-represented employees hired on or after December 12, 2014, will have access to the 401(k) plan and will choose how they want to accumulate funds for retirement, with two contribution sources from PSE: • 401(k) Company Matching: New non-represented, UA-represented and IBEW-represented employees will receive company match each paycheck based on a new schedule-100% match on the first 3% of pay contributed and 50% match on the next 3% of pay contributed. An employee who contributes 6% of pay will receive 4.5% of pay in company match. Company matching will be immediately vested. • Company Contribution: New UA-represented employees will receive an annual company contribution of 4% of eligible pay placed in the Cash Balance retirement plan. New non-represented and IBEW-represented employees will receive an annual company contribution of 4% of eligible pay, placed either in the Investment Plan 401(k) plan or in PSE’s Retirement Plan (Cash Balance retirement plan). New non-represented and IBEW-represented employees will make a one-time election within 30 days of hire and direct that PSE put the 4% contribution either into the 401(k) plan or into an account in the Cash Balance retirement plan. The Company’s 4% contribution will vest after three years of service.

Retirement Benefits

Retirement Benefits	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Retirement Benefits	(5) Retirement Benefits PSE has a defined benefit pension plan (Qualified Pension Benefits) covering the largest portion of PSE employees. Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates. Starting with January 1, 2014 all newly hired non-represented employees, United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry employees, and International Brotherhood of Electrical Workers Local Union 77 hired on or after December 12, 2014 who elect to accumulate the Company contribution in the cash balance formula portion of the pension plan, will receive annual pay credits of 4% each year. They will also receive interest credits like other participants in the cash balance pension formula of the pension plan, which are at least 1% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, he or she will have annuity and lump sum options for distribution. Those who select the lump sum option will receive their current cash balance amount. PSE also maintains a non-qualified Supplemental Executive Retirement Plan (SERP) for its key senior management employees. In addition to providing pension benefits, PSE provides legacy group health care and life insurance benefits (Other Benefits) for certain retired employees. These benefits are provided principally through an insurance company. The insurance premiums, paid primarily by retirees, are based on the benefits provided during the prior year. Puget Energy records purchase accounting adjustments associated with the re-measurement of the retirement plans. The following tables summarize the Company’s net periodic benefit cost for the three and nine months ended September 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 $ 5,322 $ 4,359 $ 277 $ 261 $ 28 $ 28 Interest cost 7,022 7,010 570 577 156 171 Expected return on plan assets (11,260 ) (10,616 ) — — (133 ) (134 ) Amortization of prior service cost (495 ) (495 ) 11 12 — — Amortization of net loss (gain) 972 — 410 228 (33 ) (228 ) Net periodic benefit cost $ 1,561 $ 258 $ 1,268 $ 1,078 $ 18 $ (163 ) Puget Energy Qualified SERP Other Nine Months Ended (Dollars in Thousands) 2015 2014 2015 2014 2015 2014 Components of net periodic benefit cost: Service cost $ 15,966 $ 13,077 $ 831 $ 782 $ 84 $ 84 Interest cost 21,066 21,030 1,710 1,732 467 513 Expected return on plan assets (33,779 ) (31,848 ) — — (399 ) (401 ) Amortization of prior service cost (1,485 ) (1,485 ) 33 33 — — Amortization of net loss (gain) 2,915 — 1,230 684 (99 ) (296 ) Net periodic benefit cost $ 4,683 $ 774 $ 3,804 $ 3,231 $ 53 $ (100 ) Puget Sound Energy Qualified SERP Other Three Months Ended (Dollars in Thousands) 2015 2014 2015 2014 2015 2014 Components of net periodic benefit cost: Service cost $ 5,322 $ 4,359 $ 277 $ 261 $ 28 $ 28 Interest cost 7,022 7,010 570 577 156 171 Expected return on plan assets (11,366 ) (10,813 ) — — (133 ) (134 ) Amortization of prior service cost (393 ) (393 ) 11 11 — 1 Amortization of net loss (gain) 5,139 3,298 530 365 (101 ) (175 ) Net periodic benefit cost $ 5,724 $ 3,461 $ 1,388 $ 1,214 $ (50 ) $ (109 ) Puget Sound Energy Qualified SERP Other Nine Months Ended (Dollars in Thousands) 2015 2014 2015 2014 2015 2014 Components of net periodic benefit cost: Service cost $ 15,966 $ 13,077 $ 831 $ 782 $ 84 $ 84 Interest cost 21,066 21,030 1,710 1,732 467 513 Expected return on plan assets (34,097 ) (32,439 ) — — (399 ) (401 ) Amortization of prior service cost (1,179 ) (1,179 ) 33 33 2 3 Amortization of net loss (gain) 15,416 9,895 1,590 1,095 (304 ) (527 ) Net periodic benefit cost $ 17,172 $ 10,384 $ 4,164 $ 3,642 $ (150 ) $ (328 ) The following table summarizes the Company’s change in benefit obligation for the periods ended September 30, 2015 and December 31, 2014: Puget Energy and Puget Sound Energy Qualified SERP Other (Dollars in Thousands) Nine Months Year Nine Months Year Nine Months Year Change in benefit obligation: Benefit obligation at beginning of period $ 690,194 $ 573,317 $ 55,855 $ 47,279 $ 15,688 $ 14,939 Service cost 15,966 17,437 831 1,042 84 112 Interest cost 21,066 28,039 1,710 2,310 467 684 Actuarial loss (gain) (588 ) 104,618 — 7,162 (540 ) 1,108 Benefits paid (41,804 ) (33,217 ) (3,026 ) (1,938 ) (1,045 ) (1,424 ) Medicare part D subsidy received — — — — 221 269 Benefit obligation at end of period $ 684,834 $ 690,194 $ 55,370 $ 55,855 $ 14,875 $ 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 September 30, 2015, the Company contributed $4.5 million, $0.5 million, and $0.1 million to fund the qualified pension plan, SERP and other postretirement plan, respectively. During the nine months ended September 30, 2015, the Company contributed $13.5 million, $3.0 million, and $0.5 million to fund the qualified pension plan, SERP and other postretirement plan, respectively.	(12) 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. Beginning in 2014, all new UA employees and those new non-represented employees who elect to accumulate the Company contribution in the Cash Balance pension, (effective January 1, 2014) and all new IBEW (effective December 12, 2014), will receive annual pay credits of 4% each year. They will also receive interest credits like other participants in the Cash Balance pension, which are at least 1% per quarter. When a newly-hired employee with a vested Cash Balance benefit leaves PSE, he or she will have annuity and lump sum options for distribution, with annuities calculated according to the Pension Protection Act. Those who select the lump sum option will receive their current cash balance amount. Participation by continuing employees in the Cash Balance pension plan is not affected. 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 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 year. The 2009 merger of Puget Energy with Puget Holdings triggered a new basis of accounting for PSE’s retirement benefit plans in the Puget Energy consolidated financial statements. Such purchase accounting adjustments associated with the re-measurement of the retirement plans are recorded at Puget Energy. The following tables summarize the Company’s change in benefit obligation, change in plan assets and amounts recognized in the Statements of Financial Position for the years ended December 31, 2014 and 2013: Puget Energy and Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2014 2013 2014 2013 2014 2013 Change in benefit obligation: Benefit obligation at beginning of period $ 573,317 $ 616,290 $ 47,279 $ 51,795 $ 14,939 $ 17,672 Service cost 17,437 19,285 1,042 1,498 112 134 Interest cost 28,039 24,754 2,310 2,045 684 664 Amendment — — — 478 — — Actuarial loss (gain) 104,618 (48,559 ) 7,162 (1,687 ) 1,108 (2,240 ) Benefits paid (33,217 ) (38,453 ) (1,938 ) (6,850 ) (1,424 ) (1,536 ) Medicare part D subsidy received — — — — 269 245 Benefit obligation at end of period $ 690,194 $ 573,317 $ 55,855 $ 47,279 $ 15,688 $ 14,939 Puget Energy and Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2014 2013 2014 2013 2014 2013 Change in plan assets: Fair value of plan assets at beginning of period $ 615,721 $ 531,183 $ — $ — $ 8,774 $ 7,541 Actual return on plan assets 25,669 102,591 — — 522 1,861 Employer contribution 18,000 20,400 1,938 6,850 488 908 Benefits paid (33,217 ) (38,453 ) (1,938 ) (6,850 ) (1,424 ) (1,536 ) Fair value of plan assets at end of period $ 626,173 $ 615,721 $ — $ — $ 8,360 $ 8,774 Funded status at end of period $ (64,021 ) $ 42,404 $ (55,855 ) $ (47,279 ) $ (7,328 ) $ (6,165 ) Puget Energy and Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2014 2013 2014 2013 2014 2013 Amounts recognized in Statement of Financial Position consist of: Noncurrent assets $ — $ 42,404 $ — $ — $ — $ — Current liabilities — — (4,386 ) (3,981 ) (355 ) (421 ) Noncurrent liabilities (64,021 ) — (51,469 ) (43,298 ) (6,973 ) (5,744 ) Net assets (liabilities) $ (64,021 ) $ 42,404 $ (55,855 ) $ (47,279 ) $ (7,328 ) $ (6,165 ) Puget Energy and Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2014 2013 2014 2013 2014 2013 Pension Plans with an Accumulated Benefit Obligation in excess of Plan Assets: Project benefit obligation $ 690,194 $ 573,317 $ 55,855 $ 47,279 $ 15,688 $ 14,939 Accumulated benefit obligation 681,745 566,689 50,137 40,892 15,553 14,794 Fair value of plan assets $ 626,173 $ 615,721 $ — $ — $ 8,360 $ 8,774 The following tables summarize Puget Energy and Puget Sound Energy’s pension benefit amounts recognized in Accumulated Other Comprehensive income for the years ended December 31, 2014 and 2013: Puget Energy Qualified SERP Other (Dollars in Thousands) 2014 2013 2014 2013 2014 2013 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 55,471 $ (65,943 ) $ 15,918 $ 9,670 $ (1,457 ) $ (2,972 ) Prior service cost (credit) (13,782 ) (15,762 ) 331 373 — — Total $ 41,689 $ (81,705 ) $ 16,249 $ 10,043 $ (1,457 ) $ (2,972 ) Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2014 2013 2014 2013 2014 2013 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 247,331 $ 138,324 $ 19,751 $ 14,050 $ (3,733 ) $ (5,556 ) Prior service cost (credit) (10,952 ) (12,525 ) 339 383 3 6 Total $ 236,379 $ 125,799 $ 20,090 $ 14,433 $ (3,730 ) $ (5,550 ) The following tables summarize Puget Energy’s and Puget Sound Energy’s net periodic benefit cost for the years ended December 31, 2014, 2013 and 2012: Puget Energy Qualified SERP Other (Dollars in Thousands) 2014 2013 2012 2014 2013 2012 2014 2013 2012 Components of net periodic benefit cost: Service cost $ 17,437 $ 19,285 $ 16,926 $ 1,042 $ 1,498 $ 1,073 $ 112 $ 134 $ 139 Interest cost 28,039 24,754 25,986 2,310 2,045 2,152 684 664 751 Expected return on plan assets (42,464 ) (39,095 ) (36,203 ) — — — (535 ) (436 ) (435 ) Amortization of prior service cost (credit) (1,980 ) (1,980 ) (1,980 ) 42 (17 ) — — — — Amortization of net loss — 2,889 768 913 1,461 702 (393 ) 69 53 Net periodic benefit cost $ 1,032 $ 5,853 $ 5,497 $ 4,307 $ 4,987 $ 3,927 $ (132 ) $ 431 $ 508 Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2014 2013 2012 2014 2013 2012 2014 2013 2012 Components of net periodic benefit cost: Service cost $ 17,437 $ 19,285 $ 16,926 $ 1,042 $ 1,498 $ 1,073 $ 112 $ 134 $ 139 Interest cost 28,039 24,753 25,986 2,310 2,045 2,152 684 664 751 Expected return on plan assets (43,252 ) (40,685 ) (41,533 ) — — — (535 ) (436 ) (435 ) Amortization of prior service cost (credit) (1,573 ) (1,573 ) (1,573 ) 44 (16 ) 293 3 30 35 Amortization of net loss (gain) 13,195 20,612 15,015 1,461 2,191 1,432 (702 ) (284 ) (245 ) Amortization of transition obligation — — — — — — — — 50 Net periodic benefit cost $ 13,846 $ 22,392 $ 14,821 $ 4,857 $ 5,718 $ 4,950 $ (438 ) $ 108 $ 295 The following tables summarize Puget Energy’s and Puget Sound Energy’s benefit obligations recognized in other comprehensive income for the years ended December 31, 2014 and 2013: Puget Energy Qualified SERP Other (Dollars in Thousands) 2014 2013 2014 2013 2014 2013 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 121,413 $ (112,055 ) $ 7,162 $ (1,687 ) $ 1,121 $ (3,665 ) Amortization of net loss (gain) — (2,889 ) (913 ) (1,461 ) 394 (70 ) Prior service credit — — — 478 — — Amortization of prior service credit 1,980 1,980 (42 ) 17 — — Total change in other comprehensive income for year $ 123,393 $ (112,964 ) $ 6,207 $ (2,653 ) $ 1,515 $ (3,735 ) Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2014 2013 2014 2013 2014 2013 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 122,202 $ (110,465 ) $ 7,162 $ (1,687 ) $ 1,121 $ (3,665 ) Amortization of net (loss) gain (13,195 ) (20,612 ) (1,461 ) (2,191 ) 702 284 Prior service cost (credit) — — — 477 — — Amortization of prior service cost (credit) 1,573 1,573 (44 ) 16 (3 ) (30 ) Amortization of transition obligation — — — — — — Total change in other comprehensive income for year $ 110,580 $ (129,504 ) $ 5,657 $ (3,385 ) $ 1,820 $ (3,411 ) The estimated prior service cost (credit) for the pension plans that will be amortized from accumulated OCI into net periodic benefit cost in 2015 by Puget Energy is $3.9 million. The estimated net (loss) gain for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2015 is $1.6 million. The estimated prior service cost (credit) for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2015 is immaterial. The estimated net (loss) gain, prior service cost (credit) and transition (obligation) asset for the other postretirement plans that will be amortized from accumulated OCI into net periodic benefit cost in 2015 are immaterial. The estimated net (loss) gain and prior service cost (credit) for the pension plans that will be amortized from accumulated OCI into net periodic benefit cost in 2015 by Puget Sound Energy are $20.5 million and $1.6 million, respectively. The estimated net loss (gain) and prior service cost (credit) for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2015 are $2.1 million. The estimated prior service cost (credit) for the SERP that will be amortized from accumulated OCI into net periodic benefit cost in 2015 is immaterial. The estimated net (loss) gain for the other postretirement plan that will be amortized from accumulated OCI into net periodic benefit cost in 2015 is $0.3 million and prior service cost (credit) and transition (obligation) asset for the other postretirement plans are immaterial. The aggregate expected contributions by the Company to fund the qualified pension plan, SERP and the other postretirement plans for the year ending December 31, 2015 are expected to be at least $18.0 million, $4.4 million and $0.5 million, respectively. Assumptions In accounting for pension and other benefit obligations and costs under the plans, the following weighted-average actuarial assumptions were used by the Company: Qualified SERP Other 2014 2013 2012 2014 2013 2012 2014 2013 2012 Benefit Obligation Assumptions Discount rate 1 4.25 % 5.10 % 4.15 % 4.25 % 5.10 % 4.15 % 4.25 % 5.10 % 4.15 % Rate of compensation increase 4.50 % 4.50 % 4.50 % 4.50 % 4.50 % 4.50 % 4.50 % 4.50 % 4.50 % Medical trend rate — — — — — — 5.70 % 6.80 % 7.50 % Benefit Cost Assumptions Discount rate 5.10 % 4.15 % 4.75 % 5.10 % 4.15 % 4.75 % 5.10 % 4.15 % 4.75 % Rate of plan assets 7.75 % 7.75 % 7.75 % — — — 7.00 % 6.90 % 7.50 % Rate of compensation increase 4.50 % 4.50 % 4.50 % 4.50 % 4.50 % 4.50 % 4.50 % 4.50 % 4.50 % Medical trend rate — — — — — — 6.70 % 8.20 % 7.50 % 1 The Company calculates the present value of the pension liability using a discount rate of 4.25% which represents the single-rate equivalent of the AA rated corporate bond yield curve. The assumed medical inflation rate used to determine benefit obligations is 6.70% in 2015 grading down to 4.30% in 2016. A 1.0% change in the assumed medical inflation rate would have the following effects: 2014 2013 (Dollars in Thousands) 1% Increase 1% Decrease 1% Increase 1% Decrease Effect on post-retirement benefit obligation $ 47 $ (47 ) $ 66 $ (66 ) Effect on service and interest cost components 2 (2 ) 3 (3 ) The Company has selected the expected return on plan assets based on a historical analysis of rates of return and the Company’s investment mix, market conditions, inflation and other factors. The expected rate of return is reviewed annually based on these factors. The Company’s accounting policy for calculating the market-related value of assets for the Company’s retirement plan is as follows. PSE market-related value of assets is based on a five-year smoothing of asset gains (losses) measured from the expected return on market-related assets. This is a calculated value that recognizes changes in fair value in a systematic and rational manner over five years. The same manner of calculating market-related value is used for all classes of assets, and is applied consistently from year to year. Puget Energy’s pension and other postretirement benefits income or costs depend on several factors and assumptions, including plan design, timing and amount of cash contributions to the plan, earnings on plan assets, discount rate, expected long-term rate of return, mortality and health care costs trends. Changes in any of these factors or assumptions will affect the amount of income or expense that Puget Energy records in its financial statements in future years and its projected benefit obligation. Puget Energy has selected an expected return on plan assets based on a historical analysis of rates of return and Puget Energy’s investment mix, market conditions, inflation and other factors. As required by merger accounting rules, market-related value was reset to market value effective with the merger. The discount rates were determined by using market interest rate data and the weighted-average discount rate from Citigroup Pension Liability Index Curve. The Company also takes into account in determining the discount rate the expected changes in market interest rates and anticipated changes in the duration of the plan liabilities. Plan Benefits The expected total benefits to be paid under the next five years and the aggregate total to be paid for the five years thereafter are as follows: (Dollars in Thousands) 2015 2016 2017 2018 2019 2020-2024 Qualified Pension total benefits $ 41,100 $ 41,400 $ 42,100 $ 43,300 $ 43,900 $ 237,300 SERP Pension total benefits $ 4,386 $ 2,595 1,940 5,346 5,811 18,759 Other Benefits total with Medicare Part D subsidy $ 1,080 $ 1,136 $ 1,113 $ 1,085 $ 1,062 $ 5,935 Other Benefits total without Medicare Part D subsidy $ 1,429 $ 1,414 $ 1,398 $ 1,380 $ 1,362 $ 6,340 Plan Assets Plan contributions and the actuarial present value of accumulated plan benefits are prepared based on certain assumptions pertaining to interest rates, inflation rates and employee demographics, all of which are subject to change. Due to uncertainties inherent in the estimations and assumptions process, changes in these estimates and assumptions in the near term may be material to the financial statements. The Company has a Retirement Plan Committee that establishes investment policies, objectives and strategies designed to balance expected return with a prudent level of risk. All changes to the investment policies are reviewed and approved by the Retirement Plan Committee prior to being implemented. The Retirement Plan Committee invests trust assets with investment managers who have historically achieved above-median long-term investment performance within the risk and asset allocation limits that have been established. Interim evaluations are routinely performed with the assistance of an outside investment consultant. To obtain the desired return needed to fund the pension benefit plans, the Retirement Plan Committee has established investment allocation percentages by asset classes as follows: Allocation Asset Class Minimum Target Maximum Domestic large cap equity 25 % 31 % 40 % Domestic small cap equity 0 % 9 % 15 % Non-U.S. equity 10 % 25 % 30 % Fixed income 15 % 25 % 30 % Real estate 0 % 0 % 10 % Absolute return 5 % 10 % 15 % Cash 0 % 0 % 5 % Plan Fair Value Measurements ASC 715, “Compensation—Retirement Benefits” (ASC 715) directs companies to provide additional disclosures about plan assets of a defined benefit pension or other postretirement plan. The objectives of the disclosures are to disclose the following: (1) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies; (2) major categories of plan assets; (3) inputs and valuation techniques used to measure the fair value of plan assets; (4) effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period; and (5) significant concentrations of risk within plan assets. ASC 820 allows the reporting entity, as a practical expedient, to measure the fair value of investments that do not have readily determinable fair values on the basis of the net asset value per share of the investment if the net asset value of the investment is calculated in a matter consistent with ASC 946, “Financial Services—Investment Companies.” The standard requires disclosures about the nature and risk of the investments and whether the investments are probable of being sold at amounts different from the net asset value per share. The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, 2014 and 2013: Recurring Fair Value Measures Recurring Fair Value Measures (Dollars in Thousands) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Equities: Non-US equity 1 $ 71,026 $ 74,131 $ — $ 145,157 $ 76,188 $ 78,816 $ — $ 155,004 Domestic large cap equity 2 134,765 68,336 — 203,101 157,874 35,851 — 193,725 Domestic small cap equity 3 59,657 — — 59,657 62,867 — — 62,867 Total equities 265,448 142,467 — 407,915 296,929 114,667 — 411,596 Tactical asset allocation 4 — — — — — — — — Fixed income securities 5 72,331 67,182 — 139,513 135,007 — — 135,007 Absolute return 6 — — 65,251 65,251 — — 62,278 62,278 Cash and cash equivalents 7 12,650 — — 12,650 — 7,054 — 7,054 Subtotal $ 350,429 $ 209,649 $ 65,251 $ 625,329 $ 431,936 $ 121,721 $ 62,278 $ 615,935 Net (payable) receivable — — — 844 — — — (417 ) Accrued income — — — — — — — 203 Total assets $ 626,173 $ 615,721 1 Non—US Equity investments are comprised of a (1) mutual fund; and a (2) commingled fund. The investment in the mutual fund is valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014. The investment in the commingled fund is valued at the net asset value per share multiplied by the number of shares held as of December 31, 2014. 2 Domestic large cap equity investments are comprised of (1) common stock, and a (2) commingled fund. Investments in common stock are valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014. The investment in the commingled fund is valued at the net asset value per share multiplied by the number of shares held as of December 31, 2014. 3 Domestic small cap equity investments are comprised of (1) common stock and a (2) mutual fund. The investments in common stock are valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014. The investment in the mutual fund is valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014. 4 The tactical asset allocation investment is comprised of a commingled fund, which is valued at the net asset value per share multiplied by the number of shares held as of the measurement date. 5 Fixed income securities consist of a mutual fund. The investment in the mutual fund is valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014. 6 As of December 31, 2014 absolute return investments consist of two partnerships. The partnerships are valued using the financial reports as of December 31, 2014. These investments are a Level 3 under ASC 820 because the significant valuation inputs are primarily internal to the partnerships with little third party involvement. 7 The investment consists of a money market fund, which is valued at the net asset value per share of $1.00 per unit as of December 31, 2014. The money market fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or short-term in nature. Level 3 Roll-Forward The following table sets forth a reconciliation of changes in the fair value of the plan’s Level 3 assets: As of December 31, 2014 As of December 31, 2013 (Dollars in Thousands) Partnership Mutual Total Partnership Mutual Total Balance at beginning of year $ 62,278 $ — $ 62,278 $ 55,614 $ — $ 55,614 Additional investments — — — — — — Distributions — — — — — — Realized losses on distributions — — — — — — Unrealized gains relating to instruments still held at the reporting date 2,973 — 2,973 6,664 — 6,664 Transferred out of level 3 1 — — — — — — Balance at end of year $ 65,251 $ — $ 65,251 $ 62,278 $ — $ 62,278 1 The plan had no transfers between level 2 and level 1 during the years ended December 31, 2014 or 2013. The following table sets forth by level, within the fair value hierarchy, the Other Benefits plan assets which consist of insurance benefits for retired employees, at fair value: Recurring Fair Value Measures Recurring Fair Value Measures (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual fund 1 $ 8,301 $ — $ 8,301 $ 8,703 $ — $ 8,703 Cash equivalents 2 59 — 59 — 71 71 Total assets $ 8,360 $ — $ 8,360 $ 8,703 $ 71 $ 8,774 1 This is a publicly traded balanced mutual fund. The fund seeks regular income, conservation of principal, and an opportunity for long-term growth of principal and income. The fair value is determined by taking the number of shares owned by the plan, and multiplying by the market price as of December 31, 2014. 2 This is a money market fund. The money market fund investments are valued at the net asset value per share of $1.00 per unit as of December 31, 2014. The money market fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or short-term in nature.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes	(13) Income Taxes The details of income tax (benefit) expense are as follows: Puget Energy Year Ended December 31, (Dollars in Thousands) 2014 2013 2012 Charged to operating expenses: Current: Federal $ — $ — $ 4,268 State — — — Deferred: Federal 57,152 122,559 100,701 State (167 ) (151 ) (244 ) Total income tax expense $ 56,985 $ 122,408 $ 104,725 Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2014 2013 2012 Charged to operating expenses: Current: Federal $ — $ — $ 4,268 State — — — Deferred: Federal 89,342 160,886 145,040 State — — — Total income tax expense $ 89,342 $ 160,886 $ 149,308 The following reconciliation compares pre-tax book income at the federal statutory rate of 35.0% to the actual income tax expense in the Statements of Income: Puget Energy Year Ended December 31, (Dollars in Thousands) 2014 2013 2012 Income taxes at the statutory rate $ 80,087 $ 142,847 $ 132,491 Increase (decrease): Production tax credit (23,073 ) (22,414 ) (22,188 ) AFUDC excluded from taxable income (3,790 ) (9,406 ) (16,543 ) Capitalized interest 2,947 7,294 9,757 Utility plant differences 7,090 9,527 8,674 Treasury grant amortization (8,808 ) (7,651 ) (1,007 ) Tenaska gas contract — 1 (4,687 ) Other—net 2,532 2,210 (1,772 ) Total income tax expense $ 56,985 $ 122,408 $ 104,725 Effective tax rate 24.9 % 30.0 % 27.7 % Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2014 2013 2012 Income taxes at the statutory rate $ 114,084 $ 180,955 $ 176,917 Increase (decrease): Production tax credit (23,073 ) (22,414 ) (22,188 ) AFUDC excluded from taxable income (3,790 ) (9,406 ) (16,543 ) Capitalized interest 2,947 7,294 9,757 Utility plant differences 7,090 9,527 8,674 Treasury grant amortization (8,808 ) (7,651 ) (1,007 ) Tenaska gas contract — 1 (4,687 ) Other—net 892 2,580 (1,615 ) Total income tax expense $ 89,342 $ 160,886 $ 149,308 Effective tax rate 27.4 % 31.1 % 29.5 % The Company’s deferred tax liability at December 31, 2014 and 2013 is composed of amounts related to the following types of temporary differences: Puget Energy At December 31, (Dollars in Thousands) 2014 2013 Utility plant and equipment $ 1,720,730 $ 1,625,107 Regulatory asset for income taxes 95,432 146,867 Fair value of debt instruments 73,606 76,991 Other deferred tax liabilities 200,124 202,189 Subtotal deferred tax liabilities 2,089,892 2,051,154 Net operating loss carryforward (417,684 ) (374,606 ) Production tax credit carryforward (158,604 ) (135,531 ) Regulatory liability on production tax credit (84,344 ) (71,880 ) Fair value of derivative instruments (36,227 ) (7,166 ) Other deferred tax assets (32,121 ) (60,970 ) Subtotal deferred tax assets (728,980 ) (650,153 ) Total $ 1,360,912 $ 1,401,001 Puget Sound Energy At December 31, (Dollars In Thousands) 2014 2013 Utility plant and equipment $ 1,720,730 $ 1,625,107 Regulatory asset for income taxes 94,913 146,350 Other deferred tax liabilities 171,380 131,977 Subtotal deferred tax liabilities 1,987,023 1,903,434 Net operating loss carryforward (181,514 ) (173,068 ) Production tax credit carryforward (158,604 ) (135,531 ) Regulatory liability on production tax credit (84,344 ) (71,880 ) Fair value of derivative instruments (39,067 ) (9,988 ) Other deferred tax assets (82,084 ) (69,175 ) Subtotal deferred tax assets (545,613 ) (459,642 ) Total $ 1,441,410 $ 1,443,792 The above amounts have been classified in the Consolidated Balance Sheets as follows: Puget Energy At December 31 (Dollars in Thousands) 2014 2013 Current deferred taxes $ (161,445 ) $ (86,004 ) Non-current deferred taxes 1,522,357 1,487,005 Total $ 1,360,912 $ 1,401,001 Puget Sound Energy At December 31 (Dollars in Thousands) 2014 2013 Current deferred taxes $ (208,447 ) $ (141,058 ) Non-current deferred taxes 1,649,857 1,584,850 Total $ 1,441,410 $ 1,443,792 The Company calculates its deferred tax assets and liabilities under ASC 740, “Income Taxes” (ASC 740). ASC 740 requires recording deferred tax balances, at the currently enacted tax rate, on assets and liabilities that are reported differently for income tax purposes than for financial reporting purposes. The utilization of deferred tax assets requires sufficient taxable income in future years. ASC 740 requires a valuation allowance on deferred tax assets when it is more likely than not that the deferred tax assets will not be realized. The Company’s PTC carryforwards expire from 2026 through 2034. The Company’s net operating loss carryforwards expire from 2029 through 2034. For ratemaking purposes, deferred taxes are not provided for certain temporary differences. PSE has established a regulatory asset for income taxes recoverable through future rates related to those temporary differences for which no deferred taxes have been provided, based on prior and expected future ratemaking treatment. The Company accounts for uncertain tax position under ASC 740, which clarifies the accounting for uncertainty in income taxes recognized in the financial statements. ASC 740 requires the use of a two-step approach for recognizing and measuring tax positions taken or expected to be taken in a tax return. First, a tax position should only be recognized when it is more likely than not, based on technical merits, that the position will be sustained upon challenge by the taxing authorities and taken by management to the court of last resort. Second, a tax position that meets the recognition threshold should be measured at the largest amount that has a greater than 50.0% likelihood of being sustained. As of December 31, 2014 and 2013, the Company had no material unrecognized tax benefits. As a result, no interest or penalties were accrued for unrecognized tax benefits during the year. For ASC 740 purposes, the Company has open tax years from 2010 through 2014. The Company classifies interest as interest expense and penalties as other expense in the financial statements.

Contingencies

Contingencies	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Contingencies	(8) 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 March 2016, 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 $0.4 million and $1.7 million relating to these claims as of September 30, 2015 and December 31, 2014, respectively.	(14) Litigation Colstrip PSE has a 50% ownership interest in Colstrip Units 1 and 2, and a 25% interest in Colstrip Units 3 and 4. On March 6, 2013, Sierra Club and Montana Environmental Information Center (MEIC) filed a Clean Air Act citizen suit against all Colstrip owners (including PSE) alleging numerous claims for relief, most of which relate to alleged prevention of significant deterioration (PSD) violations. One claim relates to the alleged failure to update the Title V permit to reflect the major modifications alleged in the first thirty-six claim, another claim alleges that the previous Title V compliance certifications have been incomplete because they did not address the alleged major modifications, and the last claim alleges opacity violations since 2007. The lawsuit was filed in U.S. District of Montana, Billings Division, requesting injunctive relief and civil penalties, including a request that the owners remediate environmental damage and that $100,000 of the civil penalties be used for beneficial mitigation projects. Discovery in the case is ongoing, and it 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 notices, 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 $1.7 million and $1.4 million relating to these claims as of December 31, 2014 and 2013, respectively.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	(15) Commitments and Contingencies For the year ended December 31, 2014, approximately 14.9% of the Company’s energy output was obtained at an average cost of approximately $0.021 per Kilowatt Hour (kWh) through long-term contracts with three of the Washington Public Utility Districts (PUDs) that own hydroelectric projects on the Columbia River. The purchase of power from the Columbia River projects is on a pro rata share basis under which the Company pays a proportionate share of the annual debt service, operating and maintenance costs and other expenses associated with each project in proportion to the contractual shares that PSE obtains from that project. In these instances, PSE’s payments are not contingent upon the projects being operable; therefore, PSE is required to make the payments even if power is not delivered. These projects are financed through substantially level debt service payments and their annual costs should not vary significantly over the term of the contracts unless additional financing is required to meet the costs of major maintenance, repairs or replacements, or license requirements. The Company’s share of the costs and the output of the projects is subject to reduction due to various withdrawal rights of the PUDs and others over the contract lives. The Company’s expenses under these PUD contracts were as follows for the years ended December 31: (Dollars in Thousands) 2014 2013 2012 PUD contract costs $ 69,661 $ 63,365 $ 70,188 As of December 31, 2014, the Company purchased portions of the power output of the PUDs’ projects as set forth in the following table: Company’s Current Share of (Dollars in Thousands) Contract Percent of Megawatt Estimated 2015 Debt Interest Debt Chelan County PUD: Rock Island Project 2031 25.0 % 156 $ 29,854 $ 11,009 $ 6,174 $ 98,191 Rocky Reach Project 2031 25.0 % 325 27,583 8,245 3,343 53,299 Douglas County PUD: Wells Project 2018 29.9 % 251 17,277 9,383 2,597 64,931 Grant County PUD: Priest Rapids Development 2052 0.6 % 8 3,689 2,087 1,245 19,828 Wanapum Development 2052 0.6 % 9 3,689 2,087 1,245 19,828 Total 749 $ 82,092 $ 32,811 $ 14,604 $ 256,077 The following table summarizes the Company’s estimated payment obligations for power purchases from the Columbia River projects, contracts with other utilities and contracts with non-utilities. These contracts have varying terms and may include escalation and termination provisions. (Dollars in Thousands) 2015 2016 2017 2018 2019 Thereafter Total Columbia River projects $ 73,023 $ 75,360 $ 74,851 $ 65,981 $ 53,837 $ 644,666 $ 987,718 Other utilities 16,136 18,884 11,823 1,257 890 — 48,990 Non-utility contracts 117,372 153,863 199,056 204,292 209,699 1,354,191 2,238,473 Total $ 206,531 $ 248,107 $ 285,730 $ 271,530 $ 264,426 $ 1,998,857 $ 3,275,181 Total purchased power contracts provided the Company with approximately 12.1 million, 10.7 million and 6.1 million MWhs of firm energy at a cost of approximately $401.4 million, $348.7 million and $203.1 million for the years 2014, 2013 and 2012, respectively. The Company has natural gas-fired generation facility obligations for natural gas supply amounting to an estimated $63.6 million in 2015. Longer term agreements for natural gas supply amount to an estimated $286.7 million for 2016 through 2019. PSE enters into short-term energy supply contracts to meet its core customer needs. These contracts are sometimes classified as NPNS, however in most cases recorded at fair value in accordance with ASC 815. Commitments under these contracts are $105.8 million, $32.4 million and $6.5 million in 2015, 2016 and 2017, respectively. Natural Gas Supply Obligations The Company has also entered into various firm supply, transportation and storage service contracts in order to ensure adequate availability of natural gas supply for its firm customers. The transportation and storage contracts, which have remaining terms from less than one year to 30 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. The Company contracts for its long-term natural gas supply on a firm basis, which means the Company has a 100% daily take obligation and the supplier has a 100% daily delivery obligation to ensure service to PSE’s customers and generation requirements. The Company incurred demand charges in 2014 for firm transportation service and firm storage and peaking service of $155.0 million and $6.6 million, respectively. The demand charge for firm natural gas supply was immaterial in 2014. The Company incurred demand charges in 2014 for firm transportation and firm storage service for the natural gas supply for its combustion turbines in the amount of $35.7 million, which is included in the total Company demand charges. The following table summarizes the Company’s obligations for future demand charges through the primary terms of its existing contracts. The quantified obligations are based on the FERC and NEB (National Energy Board) currently authorized rates, which are subject to change. Demand Charge Obligations (Dollars in Thousands) 2015 2016 2017 2018 2019 Thereafter Total Firm transportation service $ 154,121 $ 147,424 $ 144,751 $ 131,484 $ 112,249 $ 373,958 $ 1,063,987 Firm storage service 6,528 5,337 5,209 1,407 1,535 1,258 21,274 Total $ 160,649 $ 152,761 $ 149,960 $ 132,891 $ 113,784 $ 375,216 $ 1,085,261 Service Contracts The following table summarizes the Company’s estimated obligations for service contracts through the terms of its existing contracts. Service Contract Obligations (Dollars in Thousands) 2015 2016 2017 2018 2019 Thereafter Total Energy production service contracts $ 32,979 $ 15,650 $ 5,558 $ 4,064 $ 2,372 $ 23,443 $ 84,066 Automated meter reading system 25,402 16,081 13,362 13,996 14,602 51,986 135,429 Total $ 58,381 $ 31,731 $ 18,920 $ 18,060 $ 16,974 $ 75,429 $ 219,495 Other Contingencies For information regarding PSE’s environmental remediation obligations, see Note 3 Regulation and Rates.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transactions	(16) Related Party Transactions On October 10, 2014, U.S. Bancorp announced the appointment of Kimberly Harris to its board of directors effective October 20, 2014. Ms. Harris is the president and chief executive officer of both Puget Energy and PSE. U.S. Bancorp is the parent company of U.S. Bank N.A., which directly or through its subsidiaries or affiliates provides credit, banking, investment and trust services to both Puget Energy and PSE. For the year ended December 31, 2014, Puget Energy and PSE paid a total of approximately $1.0 million in fees and interest to U.S. Bank N.A. and its subsidiaries or affiliates. In 2006, PSE entered into a revolving credit facility with Puget Energy in the form of a Demand Promissory Note (Note). At December 31, 2014 and 2013, the outstanding balance of the Note was $28.9 million and $29.6 million, respectively, and the interest rate was 0.391% and 0.325%, respectively. (See Note 7).

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Segment Information	(17) Segment Information Puget Energy operates one reportable business segment referred to as the regulated utility segment. Puget Energy’s regulated utility operation generates, purchases and sells electricity and purchases, transports and sells natural gas. The service territory of PSE covers approximately 6,000 square miles in the state of Washington. In managing the business, management reviews the consolidated financial statements for Puget Energy and PSE during the year.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	(9) Accumulated Other Comprehensive Income (Loss) The following tables present the changes in the Company’s AOCI (loss) by component for the three and nine months ended September 30, 2015: Puget Energy Changes in AOCI, net of tax (Dollars in Thousands) Net unrealized Net unrealized Total Balance at June 30, 2015 $ (34,854 ) $ — $ (34,854 ) Other comprehensive income (loss) before reclassifications — — — Amounts reclassified from accumulated other comprehensive income (loss), net of tax 562 — 562 Net current-period other comprehensive income (loss) 562 — 562 Balance at September 30, 2015 $ (34,292 ) $ — $ (34,292 ) Puget Energy Changes in AOCI, net of tax (Dollars in Thousands) Net unrealized Net unrealized Total Balance at December 31, 2014 $ (36,710 ) $ (333 ) $ (37,043 ) Other comprehensive income (loss) before reclassifications 696 — 696 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 1,722 333 2,055 Net current-period other comprehensive income (loss) 2,418 333 2,751 Balance at September 30, 2015 $ (34,292 ) $ — $ (34,292 ) Puget Sound Energy Changes in AOCI, net of tax (Dollars in Thousands) Net unrealized Net unrealized Net unrealized Total Balance at June 30, 2015 $ (156,806 ) $ — $ (5,832 ) $ (162,638 ) Other comprehensive income (loss) before reclassifications — — — — Amounts reclassified from accumulated other comprehensive income (loss), net of tax 3,370 — 79 3,449 Net current-period other comprehensive income (loss) 3,370 — 79 3,449 Balance at September 30, 2015 $ (153,436 ) $ — $ (5,753 ) $ (159,189 ) Puget Sound Energy Changes in AOCI, net of tax (Dollars in Thousands) Net unrealized Net unrealized Net unrealized Total Balance at December 31, 2014 $ (164,281 ) $ (686 ) $ (5,990 ) $ (170,957 ) Other comprehensive income (loss) before reclassifications 712 — — 712 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 10,133 686 237 11,056 Net current-period other comprehensive income (loss) 10,845 686 237 11,768 Balance at September 30, 2015 $ (153,436 ) $ — $ (5,753 ) $ (159,189 ) Details about these reclassifications out of AOCI for the three and nine months ended September 30, 2015, and 2014, are as follows: Puget Energy (Dollars in Thousands) Details about accumulated other Affected line item in the income (loss) is presented Three Months Ended Nine Months Ended 2015 2014 2015 2014 Amount reclassified from accumulated Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 484 $ 483 $ 1,452 $ 1,452 Amortization of net gain (loss) (a) (1,349 ) — (5,172 ) (388 ) Total before tax (865 ) 483 (3,720 ) 1,064 Tax (expense) or benefit 303 (169 ) 1,302 (703 ) Net of Tax $ (562 ) $ 314 $ (2,418 ) $ 361 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 $ (562 ) $ 314 $ (2,751 ) $ (80 ) (a) These AOCI components are included in the computation of net periodic pension cost (see Note 5 for additional details). Puget Sound Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the income (loss) is presented Three Months Ended Nine Months Ended 2015 2014 2015 2014 Amount reclassified from accumulated other Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 383 $ 381 $ 1,145 $ 1,143 Amortization of net gain (loss) (a) (5,568 ) (3,488 ) (17,830 ) (10,463 ) Total before tax (5,185 ) (3,107 ) (16,685 ) (9,320 ) Tax (expense) or benefit 1,815 1,227 5,840 3,070 Net of Tax $ (3,370 ) $ (1,880 ) $ (10,845 ) $ (6,250 ) 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 ) (366 ) (366 ) Tax (expense) or benefit 43 43 129 129 Net of Tax $ (79 ) $ (79 ) $ (237 ) $ (237 ) Total reclassification for the period Net of Tax $ (3,449 ) $ (1,959 ) $ (11,768 ) $ (7,205 ) (a) These AOCI components are included in the computation of net periodic pension cost (see Note 5 for additional details).	(18) Accumulated Other Comprehensive Income (Loss The following tables present the changes in the Company’s accumulated other comprehensive income (loss) (AOCI) by component for the years ended December 31, 2014, 2013 and 2012, respectively. Puget Energy Changes in AOCI, net of tax (Dollars in Thousands) Net unrealized gain Net unrealized Net unrealized Total Balance at December 31, 2011 $ (15,195 ) $ (1,113 ) $ (14,599 ) $ (30,907 ) Other comprehensive income (loss) before reclassifications (13,574 ) — — (13,574 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax (296 ) 371 11,577 11,652 Net current-period other comprehensive income (loss) (13,870 ) 371 11,577 (1,922 ) Balance at December 31, 2012 $ (29,065 ) $ (742 ) $ (3,022 ) $ (32,829 ) Other comprehensive income (loss) before reclassifications 76,004 — — 76,004 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 1,575 37 2,928 4,540 Net current-period other comprehensive income (loss) 77,579 37 2,928 80,544 Balance at December 31, 2013 $ 48,514 $ (705 ) $ (94 ) $ 47,715 Other comprehensive income (loss) before reclassifications (84,301 ) — — (84,301 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax (923 ) 372 94 (457 ) Net current-period other comprehensive income (loss) (85,224 ) 372 94 (84,758 ) Balance at December 31, 2014 $ (36,710 ) $ (333 ) $ — $ (37,043 ) Puget Sound Energy Changes in AOCI, net of tax (Dollars in Thousands) Net unrealized gain Net unrealized gain Net unrealized gain Total Balance at December 31, 2011 $ (168,704 ) $ (12,934 ) $ (6,941 ) $ (188,579 ) Other comprehensive income (loss) before reclassifications (17,049 ) — — (17,049 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 9,755 8,358 317 18,430 Net current-period other comprehensive income (loss) (7,294 ) 8,358 317 1,381 Balance at December 31, 2012 $ (175,998 ) $ (4,576 ) $ (6,624 ) $ (187,198 ) Other comprehensive income (loss) before reclassifications 74,969 — — 74,969 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 13,624 2,549 317 16,490 Net current-period other comprehensive income (loss) 88,593 2,549 317 91,459 Balance at December 31, 2013 $ (87,405 ) $ (2,027 ) $ (6,307 ) $ (95,739 ) Other comprehensive income (loss) before reclassifications (84,955 ) — — (84,955 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 8,079 1,341 317 9,737 Net current-period other comprehensive income (loss) (76,876 ) 1,341 317 (75,218 ) Balance at December 31, 2014 $ (164,281 ) $ (686 ) $ (5,990 ) $ (170,957 ) Details about these reclassifications out of accumulated other comprehensive income (loss) for the years ended December 31, 2014, 2013 and 2012, respectively, are as follows: Puget Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the Amount reclassified from accumulated 2014 2013 2012 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) 1,938 1,997 1,980 Amortization of net gain (loss) (a) (519 ) (4,420 ) (1,524 ) Total before tax 1,419 (2,423 ) 456 Tax (expense) or benefit (496 ) 848 (160 ) Net of Tax $ 923 $ (1,575 ) $ 296 Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: Electric derivatives Electric generation fuel — — 100 Purchased electricity (572 ) (57 ) (671 ) Total before tax (572 ) (57 ) (571 ) Tax (expense) or benefit 200 20 200 Net of Tax $ (372 ) $ (37 ) $ (371 ) Net unrealized gain (loss) on interest rate swaps: Interest rate contracts Interest expense $ (144 ) $ (4,505 ) $ (17,811 ) Tax (expense) or benefit 50 1,577 6,234 Net of Tax $ (94 ) $ (2,928 ) $ (11,577 ) Total reclassification for the period Net of Tax $ 457 $ (4,540 ) $ (11,652 ) (a) These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 12 for additional details). Puget Sound Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the Amount reclassified from accumulated 2014 2013 2012 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,526 $ 1,559 $ 1,245 Amortization of net gain (loss) (a) (13,954 ) (22,519 ) (16,203 ) Amortization of transition obligation (a) — — (50 ) Total before tax (12,428 ) (20,960 ) (15,008 ) Tax (expense) or benefit 4,349 7,336 5,253 Net of tax $ (8,079 ) $ (13,624 ) $ (9,755 ) Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: Electric derivatives Electric generation fuel — — 97 Purchased electricity (2,063 ) (3,922 ) (12,955 ) Total before tax (2,063 ) (3,922 ) (12,858 ) Tax (expense) or benefit 722 1,373 4,500 Net of Tax $ (1,341 ) $ (2,549 ) $ (8,358 ) Net unrealized gain (loss) on treasury interest rate swaps: Interest rate contracts Interest expense (488 ) (488 ) (488 ) Tax (expense) or benefit 171 171 171 Net of Tax $ (317 ) $ (317 ) $ (317 ) Total reclassification for the period Net of Tax $ (9,737 ) $ (16,490 ) $ (18,430 ) (a ) These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 12 for additional details).

Summary of Consolidation Policy

Summary of Consolidation Policy	9 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
Summary of Consolidation Policy	(1) Summary of Consolidation Policy Basis of Presentation Puget Energy is an energy services holding company that owns PSE. PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region. Puget Energy is an indirect wholly-owned subsidiary of Puget Holdings (Puget Holdings LLC). 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 $47.6 million and $167.5 million for the three and nine months ended September 30, 2015, respectively, and $43.6 million and $172.1 million for the three and nine months ended September 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.

Fair Value Measurements28

Fair Value Measurements	9 Months Ended
	Sep. 30, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	(4) Fair Value Measurements ASC 820 established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy categorizes the inputs into three levels with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority given to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows: Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Equity securities that are also classified as cash equivalents are considered Level 1 if there are unadjusted quoted prices in active markets for identical assets or liabilities. Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options. Level 3—Pricing inputs include significant inputs that have little or no observability as of the reporting date. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves, contract terms and prices, credit-risk adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs as substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service. For interest rate swaps, the Company obtains monthly market values from an independent external pricing service using London Interbank Offered Rate (LIBOR) forward rates, which is a significant input. Some of the inputs of the interest rate swap valuations, which are less significant, include the credit standing of the counterparties, assumptions for time value and the impact of the Company’s nonperformance risk of its liabilities. The Company classifies cash and cash equivalents, and restricted cash as Level 1 financial instruments due to cash being at stated value, and cash equivalents at quoted market prices. The Company considers its electric, natural gas and interest rate swap contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes are classified as Level 3 in the fair value hierarchy. Management’s assessment is based on the trading activity in real-time and forward electric and natural gas markets. Each quarter, the Company confirms the validity of pricing-service quoted prices used to value Level 2 commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter. Assets and Liabilities with Estimated Fair Value The following table presents the carrying value for cash, cash equivalents, restricted cash, notes receivable and short-term debt by fair value hierarchy level. The carrying values below are representative of fair values due to the short-term nature of these financial instruments. Puget Energy Carrying / Fair Value Carrying / Fair Value (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Cash and cash equivalents $ 20,200 $ — $ 20,200 $ 37,527 $ — $ 37,527 Restricted cash 7,036 — 7,036 32,863 — 32,863 Notes receivable and other investments — 50,294 50,294 — 53,503 53,503 Total assets $ 27,236 $ 50,294 $ 77,530 $ 70,390 $ 53,503 $ 123,893 Liabilities: Short-term debt $ 79,500 $ — $ 79,500 $ 85,000 $ — $ 85,000 Total liabilities $ 79,500 $ — $ 79,500 $ 85,000 $ — $ 85,000 Puget Sound Energy Carrying / Fair Value Carrying / Fair Value (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Cash and cash equivalents $ 19,419 $ — $ 19,419 $ 37,466 $ — $ 37,466 Restricted cash 7,036 — 7,036 32,863 — 32,863 Notes receivable and other investments — 50,294 50,294 — 53,503 53,503 Total assets $ 26,455 $ 50,294 $ 76,749 $ 70,329 $ 53,503 $ 123,832 Liabilities: Short-term debt $ 79,500 $ — $ 79,500 $ 85,000 $ — $ 85,000 Short-term debt owed to parent — — — — 28,933 28,933 Total liabilities $ 79,500 $ — $ 79,500 $ 85,000 $ 28,933 $ 113,933 The fair value of the junior subordinated and long-term notes was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company’s credit spreads as inputs, interpolating to the maturity date of each issue. Carrying values and estimated fair values were as follows: Puget Energy September 30, 2015 December 31, 2014 (Dollars in Thousands) Level Carrying Fair Carrying Fair Liabilities: Junior subordinated notes 2 $ 250,000 $ 269,915 $ 250,000 $ 276,235 Long-term debt (fixed-rate), net of discount 2 5,113,717 6,364,901 4,694,608 6,083,554 Long-term debt (variable-rate) 2 — — 299,000 299,000 Total liabilities $ 5,363,717 $ 6,634,816 $ 5,243,608 $ 6,658,789 Puget Sound Energy September 30, 2015 December 31, 2014 (Dollars in Thousands) Level Carrying Fair Carrying Fair Liabilities: Junior subordinated notes 2 $ 250,000 $ 269,915 $ 250,000 $ 276,235 Long-term debt (fixed-rate), net of discount 2 3,524,369 4,358,964 3,513,259 4,437,473 Total liabilities $ 3,774,369 $ 4,628,879 $ 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 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Liabilities: Interest rate derivative instruments $ 7,622 $ — $ 7,622 $ 9,073 $ — $ 9,073 Total liabilities $ 7,622 $ — $ 7,622 $ 9,073 $ — $ 9,073 Puget Energy and Puget Sound Energy Fair Value Fair Value (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 9,369 $ 6,547 $ 15,916 $ 1,654 $ 3,168 $ 4,822 Natural gas derivative instruments 3,535 2,629 6,164 18,064 1,462 19,526 Total assets $ 12,904 $ 9,176 $ 22,080 $ 19,718 $ 4,630 $ 24,348 Liabilities: Electric derivative instruments $ 92,483 $ 18,989 $ 111,472 $ 91,998 $ 15,230 $ 107,228 Natural gas derivative instruments 66,560 3,009 69,569 85,305 3,502 88,807 Total liabilities $ 159,043 $ 21,998 $ 181,041 $ 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 (Dollars in Thousands) 2015 2014 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Total Electric Natural Total Balance at beginning of period $ (15,370 ) $ 823 $ (14,547 ) $ (4,693 ) $ (273 ) $ (4,966 ) Changes during period: Realized and unrealized energy derivatives: Included in earnings 1 (1,403 ) — (1,403 ) (3,116 ) — (3,116 ) Included in regulatory assets / liabilities — 1,295 1,295 — (725 ) (725 ) Settlements 3 1,017 (2,122 ) (1,105 ) (965 ) (680 ) (1,645 ) Transferred into Level 3 — — — 2,055 — 2,055 Transferred out of Level 3 3,314 (376 ) 2,938 (6,488 ) (60 ) (6,548 ) Balance at end of period $ (12,442 ) $ (380 ) $ (12,822 ) $ (13,207 ) $ (1,738 ) $ (14,945 ) Puget Energy and Puget Sound Energy Nine Months Ended (Dollars in Thousands) 2015 2014 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Total Electric Natural 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 (10,505 ) — (10,505 ) 1,939 — 1,939 Included in regulatory assets / liabilities — 4,233 4,233 — 1,654 1,654 Settlements 3 1,182 (2,420 ) (1,238 ) 1,114 (1,256 ) (142 ) Transferred into Level 3 (787 ) — (787 ) 5,155 (585 ) 4,570 Transferred out of Level 3 9,729 (154 ) 9,575 (5,994 ) (1,190 ) (7,184 ) Balance at end of period $ (12,442 ) $ (380 ) $ (12,822 ) $ (13,207 ) $ (1,738 ) $ (14,945 ) 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 $(1.5) million and $(3.3) million for the three months ended September 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 $(10.4) million and $(3.3) million for the nine months ended September 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 Level 3 commodity contracts as of September 30, 2015: Fair Value Valuation Unobservable Range Weighted (Dollars in Thousands) Assets 1 Liabilities 1 Low High Electric $ 6,547 $ 18,989 Discounted cash flow Power Prices $13.39 per $30.06 per $24.05 per MWh Natural gas $ 2,629 $ 3,009 Discounted cash flow Natural Gas Prices $1.56 per $3.13 per $2.40 per MMBtu 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. The following table presents the forward price ranges for the Company’s Level 3 commodity contracts as of December 31, 2014: Fair Value Valuation Unobservable Range Weighted (Dollars in Thousands) Assets 1 Liabilities 1 Low High Electric $ 3,168 $ 15,230 Discounted cash flow Power Prices $21.79 per $35.46 per $32.89 per MWh Natural gas $ 1,462 $ 3,502 Discounted cash flow Natural Gas Prices $3.11 per $3.83 per $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 September 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 $0.3 million and $3.9 million, respectively. Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis Puget Energy records fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle. ASC 360 requires long-lived assets to be tested for impairment on an annual basis, and upon the occurrence of any events or circumstances that would be more likely than not to reduce the fair value of the long-lived assets below their carrying value. One such triggering event is a significant decrease in the forward market prices of power. At September 30, 2015, Puget Energy completed a valuation and impairment test of its purchased power contracts classified as intangible assets. The valuation indicated an impairment to the Wells hydro contract. As of September 30, 2015, the carrying value for this contract was $42.4 million and its fair value on a discounted basis was $35.7 million, thereby requiring a write-down of $6.7 million to this intangible asset with a corresponding reduction in the regulatory liability. The forward market prices of power for the duration of the Wells hydro contract decreased on average 11% from March 31, 2015 to September 30, 2015, which caused the impairments. Below are significant unobservable inputs used in valuing the impaired long-term purchased power contract on September 30, 2015: Valuation Technique Unobservable Input Low High Average Discounted cash flow Power prices $18.38 per MWh $27.92 per MWh $24.88 per MWh Discounted cash flow Power contract costs $4,100 per qtr. $4,659 per qtr. $4,388 per qtr.

Asset Retirement Obligation

Asset Retirement Obligation	9 Months Ended
	Sep. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	(7) Asset Retirement Obligation The Company has recorded liabilities for steam generation sites, combustion turbine generation sites, combined cycle 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 U.S. Environmental Protection Agency (EPA) published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCR) under the Resource Conservation and Recovery Act, Subtitle D. The CCR rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments by establishing technical requirements for CCR landfills and surface impoundments. The rule also sets out recordkeeping and reporting requirements including requirements to post specific information to a publicly-accessible website. The CCR rule requires significant changes to the Company’s Colstrip operations and those changes were reviewed by the Company and the plant operator in the second quarter of 2015. PSE had previously recognized a legal obligation under the EPA rules to dispose of coal ash material at Colstrip, in 2003. Due to the CCR rule, additional disposal costs were added to the ARO. 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 the changes to the Company’s ARO for the nine months ended September 30, 2015: Puget Sound Energy Changes in ARO (Dollars in Thousands) Balance at December 31, 2014 $ 48,909 New asset retirement obligation recognized in the period 34,534 Liability adjustments (3,696 ) Revisions in estimated cash flows 450 Accretion expense 1,220 Balance at September 30, 2015 $ 81,417

Other

Other	9 Months Ended
	Sep. 30, 2015
Other [Abstract]
Other	(10) 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. Related Party Transactions Scott Armstrong serves on the Board of Directors of the Company, and is the president and Chief Executive Officer of Group Health Cooperative (Group Health). Group Health provides coverage to over 600,000 residents in Washington and Northern Idaho. Certain employees of PSE elect Group Health as their medical provider and as a result, PSE paid Group Health a total of $14.8 million and $17.7 million for medical coverage for the nine months ended September 30, 2015, and the year ended December 31, 2014, respectively.

Summary of Significant Accoun31

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Puget Energy, Inc. (Puget Energy) is an energy services holding company that owns Puget Sound Energy, Inc. (PSE). PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering 6,000 square miles, primarily in the Puget Sound region. In 2009, Puget Holdings LLC (Puget Holdings), owned by a consortium of long-term infrastructure investors, completed its merger with Puget Energy (the merger). As a result of the merger, all of Puget Energy’s common stock is indirectly owned by Puget Holdings. The acquisition of Puget Energy was accounted for in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 805, “Business Combinations” (ASC 805), as of the date of the merger. ASC 805 requires the acquirer to recognize and measure identifiable assets acquired and liabilities assumed at fair value as of the merger date. The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiary, PSE. PSE’s consolidated financial statements include the accounts of PSE and its subsidiary. Puget Energy and PSE are collectively referred to herein as “the Company.” The consolidated financial statements are presented after elimination of all significant intercompany items and transactions. PSE’s consolidated financial statements continue to be accounted for on a historical basis and PSE’s financial statements do not include any ASC 805 purchase accounting adjustments. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $231.7 million, $243.9 million and $244.2 million for 2014, 2013 and 2012, respectively. The Company reports the collection of such taxes on a gross basis in operation revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income. Beginning July 1, 2013, 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 are deferred to a regulatory asset for under recovery or regulatory liability for over recovery. Revenues associated with power costs under the Power Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA) rates are excluded from the decoupling mechanism.
Utility Plant	Utility Plant Puget Energy and PSE capitalize, at original cost, additions to utility plant, including renewals and betterments. Costs include indirect costs such as engineering, supervision, certain taxes, pension and other employee benefits and an Allowance for Funds Used During Construction (AFUDC). Replacements of minor items of property are included in maintenance expense. When the utility plant is retired and removed from service, the original cost of the property is charged to accumulated depreciation and costs associated with removal of the property, less salvage, are charged to the cost of removal regulatory liability. Planned Major Maintenance Planned major maintenance is an activity that typically occurs when PSE overhauls or substantially upgrades various systems and equipment on its natural gas fired combustion turbines on a scheduled basis. Costs related to planned major maintenance are deferred and amortized to the next scheduled major maintenance. This accounting method also follows the Washington Utilities and Transportation Commission (Washington Commission) regulatory treatment related to these generating facilities.
Depreciation and Amortization	Non-Utility Property, Plant and Equipment For PSE, the costs of other property, plant and equipment are stated at historical cost. Expenditures for refurbishment and improvements that significantly add to productive capacity or extend useful life of an asset are capitalized. Replacement of minor items are expensed on a current basis. Gains and losses on assets sold or retired are reflected in earnings. Depreciation and Amortization For financial statement purposes, the Company provides for depreciation and amortization on a straight-line basis. Amortization is recorded for intangibles such as regulatory assets and liabilities, computer software and franchises. The depreciation of vehicles and equipment is allocated to the asset and expense accounts based on usage. The annual depreciation provision stated as a percent of a depreciable electric utility plant was 2.8%, 2.8% and 2.9% in 2014, 2013 and 2012, respectively; depreciable gas utility plant was 3.4%, 3.4% and 3.4% in 2014, 2013 and 2012, respectively; and depreciable common utility plant was 8.5%, 11.4% and 11.6% in 2014, 2013 and 2012, respectively. The decrease in depreciable common utility plant that occurred between 2014 and 2013 was primarily due to asset retirement. Depreciation on other property, plant and equipment is calculated primarily on a straight-line basis over the useful lives of the assets. The cost of removal is collected from PSE’s customers through depreciation expense and any excess is recorded as a regulatory liability.
Goodwill	Goodwill In 2009, Puget Holdings completed its merger with Puget Energy. Puget Energy remeasured the carrying amount of all its assets and liabilities to fair value, which resulted in recognition of approximately $1.7 billion in goodwill. ASC 350, “Intangibles—Goodwill and Other” (ASC 350), requires that goodwill be tested for impairment at the reporting unit level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. These events or circumstances could include a significant change in the Company’s business or regulatory outlook, legal factors, a sale or disposition of a significant portion of a reporting unit or significant changes in the financial markets which could influence the Company’s access to capital and interest rates. Application of the goodwill impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, assignment of goodwill to reporting units and the determination of the fair value of the reporting units. Management has determined Puget Energy has only one reporting unit. The goodwill recorded by Puget Energy represents the potential long-term return to the Company’s investors. Goodwill is tested for impairment annually using a two-step process. The first step compares the carrying amount of the reporting unit with its fair value, with a carrying value higher than fair value indicating potential impairment. If the first step test fails, the second step is performed. This would entail a full valuation of Puget Energy’s assets and liabilities and comparing the valuation to its carrying amounts, with the aggregate difference indicating the amount of impairment. Goodwill of a reporting unit is required to be tested for impairment on an interim basis if an event occurs or circumstances change that would cause the fair value of a reporting unit to fall below its carrying amount. Puget Energy conducted its annual impairment test in 2014 using an October 1, 2014 measurement date. The fair value of Puget Energy’s reporting unit was estimated using both discounted cash flow and market approach. Such approaches are considered methodologies that market participants would use. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term rate of growth for Puget Energy business, estimation of the useful life over which cash flows will occur, the selection of utility holding companies determined to be comparable to Puget Energy and determination of an appropriate weighted-average cost of capital or discount rate. The market approach estimates the fair value of the business based on market prices of stocks of comparable companies engaged in the same or similar lines of business. In addition, indications of market value are estimated by deriving multiples of equity or invested capital to various measures of revenue, earnings or cash flow. Changes in these estimates and/or assumptions could materially affect the determination of fair value and goodwill impairment of the reporting unit. Based on the test performed, management has determined that there was no indication of impairment of Puget Energy’s goodwill as of October 1, 2014. There were no known events or circumstances from the date of the assessment through December 31, 2014 that would impact management’s conclusion.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents consist of demand bank deposits and short-term highly liquid investments with original maturities of three months or less at the time of purchase. The cash and cash equivalents balance at Puget Energy was $37.5 million and $44.3 million as of December 31, 2014 and 2013, respectively. The 2014 and 2013 balance consisted of cash equivalents, which are reported at cost and approximate fair value, and were $1.8 million and $2.6 million, respectively.
Materials and Supplies	Materials and Supplies Materials and supplies are used primarily in the operation and maintenance of electric and natural gas distribution and transmission systems as well as spare parts for combustion turbines used for the generation of electricity. Puget Energy and PSE record these items at weighted-average cost.
Fuel and Gas Inventory	Fuel and Gas Inventory Fuel and gas inventory is used in the generation of electricity and for future sales to the Company’s natural gas customers. Fuel inventory consists of coal, diesel and natural gas used for generation. Gas inventory consists of natural gas and Liquefied Natural Gas (LNG) held in storage for future sales. Puget Energy and PSE record these items at the lower of cost or market value using the weighted-average cost method.
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities PSE accounts for its regulated operations in accordance with ASC 980 “Regulated Operations” (ASC 980). ASC 980 requires PSE to defer certain costs that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. It similarly requires deferral of revenues or gains and losses that are expected to be returned to customers in the future. Accounting under ASC 980 is appropriate as long as rates are established by or subject to approval by independent third-party regulators; rates are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that rates set at levels that will recover costs can be charged to and collected from customers. In most cases, PSE classifies regulatory assets and liabilities as long-term due to the length of the amortization. For further details regarding regulatory assets and liabilities, see Note 3.
Allowance for Funds Used During Construction	Allowance for Funds Used During Construction AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. The amount of AFUDC recorded in each accounting period varies depending principally upon the level of construction work in progress and the AFUDC rate used. AFUDC is capitalized as a part of the cost of utility plant and is credited to interest expense and as a non-cash item to other income. Cash inflow related to AFUDC does not occur until these charges are reflected in rates. The AFUDC rates authorized by the Washington Commission for natural gas and electric utility plant additions based on the effective dates are as follows: Effective Date Washington Commission July 1, 2013 - present 7.77 % May 14, 2012 - June 30, 2013 7.80 April 8, 2010 - May 13, 2012 8.10 The Washington Commission authorized the Company to calculate AFUDC using its allowed rate of return. To the extent amounts calculated using this rate exceed the AFUDC calculated rate using the Federal Energy Regulatory Commission (FERC) formula, PSE capitalizes the excess as a deferred asset, crediting other income. The deferred asset is being amortized over the average useful life of PSE’s non-project electric utility plant which is approximately 30 years.
Revenue Recognition	Revenue Recognition Operating utility revenue is recognized when the basis of services is rendered, which includes estimated unbilled revenue, in accordance with ASC 605, “Revenue Recognition” (ASC 605). PSE’s estimate of unbilled revenue is based on a calculation using meter readings from its automated meter reading (AMR) system. The estimate calculates unbilled usage at the end of each month as the difference between the customer meter readings on the last day of the month and the last customer meter readings billed. The unbilled usage is then priced at published rates for each schedule to estimate the unbilled revenues by customer. The non-utility subsidiary recognizes revenue when services are performed or upon the sale of assets. Revenue from retail sales is billed based on tariff rates approved by the Washington Commission. Sales of Renewable Energy Credits (RECs) are deferred as a regulatory liability. Beginning July 1, 2013, 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 are deferred to a regulatory asset for under recovery or regulatory liability for over recovery. Revenues associated with power costs under the PCA mechanism and PGA rates are excluded from the decoupling mechanism. The decoupling mechanism reduces earnings volatility, but does not materially affect the timing of cash flow due to the timing difference between the recognition of decoupling revenue and resulting impacts on rates.
Allowance for Doubtful Accounts	Allowance for Doubtful Accounts Allowance for doubtful accounts are provided for electric and natural gas customer accounts based upon a historical experience rate of write-offs of energy accounts receivable along with information on future economic outlook. The allowance account is adjusted monthly for this experience rate. The allowance account is maintained until either receipt of payment or the likelihood of collection is considered remote at which time the allowance account and corresponding receivable balance are written off. The Company’s allowance for doubtful accounts at December 31, 2014 and 2013 was $7.5 million and $7.4 million, respectively.
Self Insurance	Self-Insurance PSE is self-insured for storm damage and environmental contamination occurring on PSE-owned property. In addition, PSE is required to meet a deductible for a portion of the risk associated with comprehensive liability, workers’ compensation claims and catastrophic property losses other than those which are storm related. The Washington Commission has approved the deferral of certain uninsured qualifying storm damage costs that exceed $8.0 million which will be requested for collection in future rates. Additionally, costs may only be deferred if the outage meets the Institute of Electrical and Electronics Engineers (IEEE) outage criteria for system average interruption duration index.
Federal Income Taxes	Federal Income Taxes For presentation in Puget Energy and PSE’s separate financial statements, income taxes are allocated to the subsidiaries on the basis of separate company computations of tax, modified by allocating certain consolidated group limitations which are attributed to the separate company. Taxes payable or receivable are settled with Puget Holdings.
Natural Gas Off System Sales and Capacity Release	Natural Gas Off-System Sales and Capacity Release PSE contracts for firm natural gas supplies and holds firm transportation and storage capacity sufficient to meet the expected peak winter demand for natural gas by its firm customers. Due to the variability in weather, winter peaking consumption of natural gas by most of its customers and other factors, PSE holds contractual rights to natural gas supplies and transportation and storage capacity in excess of its average annual requirements to serve firm customers on its distribution system. For much of the year, there is excess capacity available for third-party natural gas sales, exchanges and capacity releases. PSE sells excess natural gas supplies, enters into natural gas supply exchanges with third parties outside of its distribution area and releases to third parties excess interstate natural gas pipeline capacity and natural gas storage rights on a short-term basis to mitigate the costs of firm transportation and storage capacity for its core natural gas customers. The proceeds from such activities, net of transactional costs, are accounted for as reductions in the cost of purchased natural gas and passed on to customers through the PGA mechanism, with no direct impact on net income. As a result, PSE nets the sales revenue and associated cost of sales for these transactions in purchased natural gas.
Non-Core Gas Sales	Non-Core Gas Sales As part of the Company’s electric operations, PSE provides natural gas to its gas-fired generation facilities. The projected volume of natural gas for power is relative to the price of natural gas. Based on the market prices for natural gas, PSE may use the gas it has already purchased to generate power or PSE may sell the already purchased natural gas. The net proceeds from selling natural gas, previously purchased for power generation, are accounted for in other electric operating revenue and are included in the PCA mechanism.
Production Tax Credit	Production Tax Credit Production Tax Credits (PTCs) represent federal income tax incentives available to taxpayers that generate energy from qualifying renewable sources. PSE records the benefit of the PTCs as a regulatory liability until such time as PSE utilizes the tax credit on its tax return. Once utilized, PSE will pass the benefit to customers.
Accounting for Derivatives	Accounting for Derivatives ASC 815 requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair value unless the contracts qualify for an exception. PSE enters into derivative contracts to manage its energy resource portfolio and interest rate exposure including forward physical and financial contracts and swaps. Some of PSE’s physical electric supply contracts qualify for the Normal Purchase Normal Sale (NPNS) exception to derivative accounting rules. PSE may enter into financial fixed price contracts to economically hedge the variability of certain index-based contracts. Those contracts that do not meet the NPNS exception are marked-to-market to current earnings in the statements of income, subject to deferral under ASC 980, for energy related derivatives due to the PCA mechanism and PGA mechanism. Puget Energy and PSE elected to de-designate all energy related derivative contracts previously recorded as cash flow hedges for the purpose of simplifying its financial reporting in 2009. The contracts that were de-designated related to physical electric supply contracts and natural gas swap contracts used to fix the price of natural gas for electric generation. For these contracts and for contracts initiated after such date, all mark-to-market adjustments are recognized through earnings. The amount previously recorded in accumulated OCI is transferred to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if management determines that the forecasted transaction is probable of not occurring. As a result, the Company will continue to experience the earnings impact of these reversals from OCI in future periods. When these contracts are settled, the contract price becomes part of purchased electricity or electric generation fuel which becomes part of PSE’s PCA mechanism and the unrealized gain or loss is listed separately under energy costs, as it represents the non-rate treatment of energy costs. The Company may enter into swap instruments or other financial derivative instruments to manage the interest rate risk associated with its long-term debt financing and debt instruments. As of December 31, 2014, Puget Energy has interest rate swap contracts outstanding related to its long-term debt. For additional information, see Note 9 Accounting for Derivative Instruments and Hedging Activities.
Fair Value Measurements of Derivatives	Fair Value Measurements of Derivatives ASC 820, “Fair Value Measurements and Disclosures” (ASC 820), defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). As permitted under ASC 820, the Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and liabilities measured and reported at fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements as it believes that the approach is used by market participants for these types of assets and liabilities. Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company values derivative instruments based on daily quoted prices from an independent external pricing service. When external quoted market prices are not available for derivative contracts, the Company uses a valuation model that uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves. All derivative instruments are sensitive to market price fluctuations that can occur on a daily basis. For additional information, see Note 10 Fair Value Measurements.
Debt Related Costs	Debt Related Costs Debt premiums, discounts, expenses and amounts received or incurred to settle hedges are amortized over the life of the related debt for the Company. The premiums and costs associated with reacquired debt are deferred and amortized over the life of the related new issuance, in accordance with ratemaking treatment for PSE.

Summary of Significant Accoun32

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Schedule of Authorized AFUDC Rates	The AFUDC rates authorized by the Washington Commission for natural gas and electric utility plant additions based on the effective dates are as follows: Effective Date Washington Commission July 1, 2013 - present 7.77 % May 14, 2012 - June 30, 2013 7.80 April 8, 2010 - May 13, 2012 8.10

Regulation and Rates (Tables)

Regulation and Rates (Tables)	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Schedule of Allowed Return on the Net Regulatory Assets and Liabilities		Below is a chart with the allowed return on the net regulatory assets and liabilities and the associated time periods: Period Rate of Return After-Tax Return July 1, 2013 - present 7.77 % 6.69 % May 14, 2012 - June 30, 2013 7.80 6.71 April 8, 2010 - May 13, 2012 8.10 6.90
Schedule of Net Regulatory Assets and Liabilities		The net regulatory assets and liabilities at December 31, 2014 and 2013 included the following: Puget Sound Energy Remaining Amortization December 31, (Dollars in Thousands) 2014 2013 PGA deferral of unrealized losses on derivative instruments (a) $ 69,280 $ 27,555 Chelan PUD contract initiation 16.8 Years 119,316 126,404 Storm damage costs electric 1 to 4 years 118,824 116,328 Environmental remediation (a) 66,018 57,342 Baker Dam licensing operating and maintenance costs 44 years 61,577 57,270 Snoqualmie licensing operating and maintenance costs 30 years 9,202 10,881 Colstrip common property 9.5 years 6,764 7,479 Deferred income taxes (a) 94,913 146,350 Deferred Washington Commission AFUDC 35 years 53,709 55,495 Energy conservation costs 1 to 2 years 42,374 35,987 Unamortized loss on reacquired debt 1 to 21.5 years 35,667 37,832 White River relicensing and other costs 17.9 years 26,685 28,190 Mint Farm ownership and operating costs 10.3 years 20,320 22,320 Investment in Bonneville Exchange power contract 2.5 years 8,816 12,343 Ferndale 4.8 years 19,232 22,811 Lower Snake River 1.3 to 22.3 years 86,275 92,924 Snoqualmie 3.8 years 6,798 8,009 Property tax tracker Less than 2 years 32,253 22,134 PGA receivable 1 year 21,073 — PCA mechanism (a) 4,623 — Electron unrecovered loss 4 years 14,008 — Decoupling under-collection Less than 2 years 55,363 — Various other regulatory assets Varies 14,312 8,078 Total PSE regulatory assets $ 987,402 $ 895,732 Cost of removal (b) $ (313,088 ) $ (269,536 ) Production tax credits (c) (93,616 ) (93,618 ) PGA payable 1 year — (5,938 ) PCA mechanism (a) — (5,345 ) Decoupling over-collection Less than 2 years (12,582 ) (20,535 ) Summit purchase option buy-out 5.8 years (9,188 ) (10,763 ) Deferred gain on Jefferson County sale Less than 1 year (4,731 ) (60,844 ) Deferred credit on Biogas sale 1 year (1,445 ) (10,908 ) Deferred credit on gas pipeline capacity Varies up to 3.8 years (3,564 ) (4,508 ) Renewable energy credits 1 year (2,383 ) (5,820 ) Treasury grants 5 to 44 years (180,496 ) (203,889 ) Deferral of treasury grant amortization Less than 4 years (8,197 ) — Various other regulatory liabilities Up to 4 years (6,092 ) (5,755 ) Total PSE regulatory liabilities $ (635,382 ) $ (697,459 ) PSE net regulatory assets (liabilities) $ 352,020 $ 198,273 (a) Amortization periods vary depending on timing of underlying transactions or awaiting regulatory approval in a future Washington Commission rate proceeding. (b) The balance is dependent upon the cost of removal of underlying assets and the life of utility plant. (c) Amortization will begin once PTCs are utilized by PSE on its tax return. Puget Energy Remaining Amortization December 31, (Dollars in Thousands) 2014 2013 Total PSE regulatory assets (a) $ 987,402 $ 895,732 Puget Energy acquisition adjustments: Regulatory assets related to power contracts 1 to 22 years 29,816 33,753 Various other regulatory assets Varies 561 517 Total Puget Energy regulatory assets $ 1,017,779 $ 930,002 Total PSE regulatory liabilities (a) $ (635,382 ) $ (697,459 ) Puget Energy acquisition adjustments: Regulatory liabilities related to power contracts 1 to 37 years (391,389 ) (443,065 ) Various other regulatory liabilities Varies (2,820 ) (2,884 ) Total Puget Energy regulatory liabilities $ (1,029,591 ) $ (1,143,408 ) Puget Energy net regulatory asset (liabilities) $ (11,812 ) $ (213,406 ) (a) Puget Energy’s regulatory assets and liabilities include purchase accounting adjustments under ASC 805 as a result of the merger.
Schedule of Graduated Scale of Rate Adjustment Mechanisms	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	The graduated scale is as follows: Annual Power Cost Variability Customers’ Company’s +/- $20 million 0 % 100 % +/- $20 million - $40 million 50 % 50 % +/- $40 million - $120 million 90 % 10 % +/- $120 + million 95 % 5 %
Electric [Member]
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments		The following table sets forth electric rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates: Type of Rate Adjustment Effective Date Average Increase (Decrease) PCORC December 1, 2014 (0.9 )% $ (19.4 ) Conservation Rider May 1, 2014 0.5 % 12.2 Decoupling Rate Filing May 1, 2014 0.5 10.6 Property Tax Tracker May 1, 2014 0.5 11.0 PCORC November 1, 2013 0.5 10.5 Decoupling Rate Filing July 1, 2013 1.0 21.4 Expedited Rate Filing July 1, 2013 1.5 30.7 Electric General Rate Case May 14, 2012 3.2 63.3
Natural Gas [Member]
Schedule of Effects on Annual Revenue Due to Approved Rate Adjustments		The following table sets forth natural gas rate adjustments that were approved by the Washington Commission and the corresponding impact to PSE’s annual revenue based on the effective dates: Type of Rate Adjustment Effective Date Average Annual Purchased Gas Adjustment November 1, 2014 (2.5 )% $ (23.3 ) Decoupling Rate Filing May 1, 2014 (0.1 ) (1.0 ) Purchased Gas Adjustment November 1, 2013 0.4 4.0 Decoupling Rate Filing July 1, 2013 1.1 10.8 Expedited Rate Filing July 1, 2013 (0.2 ) (2.0 ) Purchased Gas Adjustment November 1, 2012 (7.7 ) (77.0 ) Natural Gas General Rate Case May 14, 2012 1.3 13.4 Purchased Gas Adjustment November 1, 2011 (4.3 ) (43.5 ) Natural Gas General Tariff Adjustment April 1, 2011 1.8 19.0

Utility Plant (Tables)

Utility Plant (Tables)	12 Months Ended
	Dec. 31, 2014
Regulated Operations [Abstract]
Schedule of Utility Plant	Estimated Puget Energy Puget Sound Energy Utility Plant At December 31, At December 31, (Dollars In Thousands) 2014 2013 2014 2013 Electric, gas and common utility plant classified by prescribed accounts: Distribution plant 10-50 $ 4,748,988 $ 4,448,451 $ 6,417,551 $ 6,127,732 Production plant 25-125 2,973,853 2,966,223 3,907,224 3,948,270 Transmission plant 45-65 1,189,296 1,043,605 1,306,009 1,162,929 General plant 5-35 481,116 504,965 553,130 599,156 Intangible plant (including capitalized software) 3-50 311,959 316,614 304,135 309,972 Plant acquisition adjustment 7-30 242,826 242,826 282,792 282,792 Underground storage 25-60 28,859 27,857 42,494 41,501 Liquefied natural gas storage 25-45 12,628 12,622 14,498 14,492 Plant held for future use NA 54,996 28,742 55,148 28,895 Recoverable Cushion Gas NA 8,655 8,655 8,655 8,655 Plant not classified 1-100 91,519 124,589 91,519 124,589 Grant NA (105,659 ) — (105,659 ) — Capital leases, net of accumulated amortization 1 5 9,473 17,051 9,473 17,051 Less: accumulated provision for depreciation (1,611,220 ) (1,373,178 ) (4,449,680 ) (4,297,012 ) Subtotal $ 8,437,289 $ 8,369,022 $ 8,437,289 $ 8,369,022 Construction work in progress NA 239,690 310,318 239,690 310,318 Net utility plant $ 8,676,979 $ 8,679,340 $ 8,676,979 $ 8,679,340 1 Accumulated amortization of capital leases at Puget Energy was $28.4 million in 2014 and $20.8 million in 2013. Accumulated amortization of capital leases at PSE was $28.4 million in 2014 and $20.8 million in 2013.
Schedule of Jointly Owned Utility Plants	The following table indicates the Company’s percentage ownership and the extent of the Company’s investment in jointly owned generating plants in service at December 31, 2014. These amounts are also included in the Utility Plant table above. Jointly Owned Generating Plants (Dollars in Thousands) Energy Company’s Puget Energy’s Share Puget Sound Energy’s Share Plant in Accumulated Plant in Accumulated Colstrip Units 1 & 2 Coal 50 % $ 158,516 $ (12,047 ) $ 293,103 $ (146,635 ) Colstrip Units 3 & 4 Coal 25 % 234,787 (28,763 ) 509,619 (303,594 ) Colstrip Units 1 – 4 Common Facilities 1 Coal various 83 (21 ) 252 (189 ) Frederickson 1 Gas 49.85 % 61,771 (5,750 ) 70,719 (14,698 ) Jackson Prairie Gas Storage 33.34 % 28,185 (4,099 ) 42,494 (18,409 ) 1 The Company’s ownership is 50% for Colstrip 1&2 and 25% for Colstrip Units 3 &4.

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations	Puget Sound Energy Changes in ARO (Dollars in Thousands) Balance at December 31, 2014 $ 48,909 New asset retirement obligation recognized in the period 34,534 Liability adjustments (3,696 ) Revisions in estimated cash flows 450 Accretion expense 1,220 Balance at September 30, 2015 $ 81,417	The following table describes all changes to the Company’s ARO liability: At December 31, (Dollars in Thousands) 2014 2013 Asset retirement obligation at beginning of period $ 48,687 $ 45,496 New asset retirement obligation recognized in the period — 350 Liability settled in the period (602 ) (1,188 ) Revisions in estimated cash flows (480 ) 2,769 Accretion expense 1,304 1,260 Asset retirement obligation at end of period $ 48,909 $ 48,687

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Schedule of Long-Term Debt Instruments	(Dollars in Thousands) At December 31, Series Type Due 2014 2013 Puget Sound Energy: 7.350% First Mortgage Bond 2015 $ 10,000 $ 10,000 7.360% First Mortgage Bond 2015 2,000 2,000 5.197% Senior Secured Note 2015 150,000 150,000 6.750% Senior Secured Note 2016 250,000 250,000 5.500% Promissory Note 1 2017 2,412 2,412 6.740% Senior Secured Note 2018 200,000 200,000 7.150% First Mortgage Bond 2025 15,000 15,000 7.200% First Mortgage Bond 2025 2,000 2,000 7.020% Senior Secured Note 2027 300,000 300,000 7.000% Senior Secured Note 2029 100,000 100,000 3.900% Pollution Control Bond 2031 138,460 138,460 4.000% Pollution Control Bond 2031 23,400 23,400 5.483% Senior Secured Note 2035 250,000 250,000 6.724% Senior Secured Note 2036 250,000 250,000 6.274% Senior Secured Note 2037 300,000 300,000 5.757% Senior Secured Note 2039 350,000 350,000 5.795% Senior Secured Note 2040 325,000 325,000 5.764% Senior Secured Note 2040 250,000 250,000 4.434% Senior Secured Note 2041 250,000 250,000 5.638% Senior Secured Note 2041 300,000 300,000 4.700% Senior Secured Note 2051 45,000 45,000 6.974% Junior Subordinated Note 2067 250,000 250,000 Unamortized discount on senior notes (13 ) (14 ) PSE long-term debt $ 3,763,259 $ 3,763,258 Puget Energy: Fair value adjustment of PSE long-term debt $ (218,619 ) $ (229,746 ) Credit Facility 2017 — 299,000 Term-Loan 2016 100,000 — Term-Loan 2017 100,000 — Term-Loan 2016 99,000 — 6.500% Senior Secured Note 2020 450,000 450,000 6.000% Senior Secured Note 2021 500,000 500,000 5.625% Senior Secured Note 2022 450,000 450,000 Unamortized discount on senior notes (32 ) (36 ) Total Puget Energy long-term debt $ 5,243,608 $ 5,232,476 1 Puget Western, Inc., a wholly owned subsidiary of PSE, Promissory Note.
Schedule of Maturities of Long-Term Debt	The principal amounts of long-term debt maturities for the next five years and thereafter are as follows: (Dollars in Thousands) 2015 2016 2017 2018 2019 Thereafter Total Maturities of: PSE long-term debt $ 162,000 $ 250,000 $ 2,412 $ 200,000 $ — $ 3,148,860 $ 3,763,272 Puget Energy long-term debt — 199,000 100,000 — — 1,400,000 1,699,000 Puget Energy long-term debt $ 162,000 $ 449,000 $ 102,412 $ 200,000 $ — $ 4,548,860 $ 5,462,272

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2014
Leases [Abstract]
Schedule of Operating Lease Expense	Operating lease expenses net of sublease receipts were: (Dollars in Thousands) At December 31, 2014 $ 30,737 2013 29,392 2012 29,661
Schedule of Future Minimum Lease Payments for Non-cancellable Leases	Future minimum lease payments for non-cancelable leases net of sublease receipts are: (Dollars in Thousands) At December 31, Operating Capital 2015 $ 17,677 $ 8,160 2016 21,454 2,178 2017 22,179 — 2018 20,423 — 2019 15,180 — Thereafter 120,791 — Total minimum lease payments $ 217,704 $ 10,338

Accounting for Derivative Ins38

Accounting for Derivative Instruments and Hedging Activities (Tables)	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
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 September 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 $ — $ 7,622 $ 450 million $ — $ 9,073 Electric portfolio derivatives * 15,916 111,472 * 4,822 107,228 Natural gas derivatives (MMBtus) 4 345.6 million 6,164 69,569 360.4 million 19,526 88,807 Total derivative contracts $ 22,080 $ 188,663 $ 24,348 $ 205,108 Current $ 18,771 $ 133,061 $ 21,178 $ 142,195 Long-term 3,309 55,602 3,170 62,913 Total derivative contracts $ 22,080 $ 188,663 $ 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 ASC 980, “Regulated Operations,” due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. * Electric portfolio derivatives consist of electric generation fuel of 175.1 million One Million British Thermal Units (MMBtu) and purchased electricity of 1.1 million Megawatt Hours (MWhs) at September 30, 2015, and 140.2 million MMBtus and 5.4 million MWhs at December 31, 2014.	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 Year Ended December 31, (Dollars in Thousands) Volumes (millions) Assets 1 Liabilities 2 2014 2013 2014 2013 2014 2013 Interest rate swap derivatives 3 $ 450.0 $ 450.0 $ — $ — $ 9,073 $ 13,223 Electric portfolio derivatives * * 4,822 18,479 107,228 37,312 Natural gas derivatives (MMBtus) 4 360.4 423.5 19,526 8,121 88,807 35,676 Total derivative contracts $ 24,348 $ 26,600 $ 205,108 $ 86,211 Current $ 21,178 $ 18,867 $ 142,195 $ 48,049 Long-term 3,170 7,733 62,913 38,162 Total derivative contracts $ 24,348 $ 26,600 $ 205,108 $ 86,211 1 Balance sheet location: Current and Long-term Unrealized gain on derivative instruments. 2 Balance sheet location: Current and Long-term Unrealized loss on derivative instruments. 3 Interest rate swap contracts are only held at Puget Energy. 4 PSE had a net derivative liability and an offsetting regulatory asset of $69.3 million at December 31, 2014 and $27.6 million at December 31, 2013 related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, due to the PGA mechanism. * Electric portfolio derivatives consist of electric generation fuel of 140.2 million One Million British Thermal Units (MMBtus) and purchased electricity of 5.4 million Megawatt Hours (MWhs) at December 31, 2014 and 145.6 million MMBtus and 8.6 million MWhs at December 31, 2013.
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 September 30, 2015 (Dollars in Thousands) Gross Amount 1 Gross Amounts Net of Amounts Gross Amounts Not Offset in the Net Commodity Cash Collateral Assets: Energy derivative contracts $ 22,080 $ — $ 22,080 $ (18,416 ) $ — $ 3,664 Liabilities: Energy derivative contracts 181,041 — 181,041 (18,416 ) — 162,625 Interest rate swaps 2 7,622 — 7,622 — — 7,622 Puget Energy and Puget Sound Energy December 31, 2014 (Dollars in Thousands) Gross Amount 1 Gross Amounts Net of Amounts Gross Amounts Not Offset in the Net Commodity Cash Collateral 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 potential effect of netting arrangements, including rights of set-off associated with the Company’s derivative assets and liabilities: Puget Energy and Puget Sound Energy At December 31, 2014 (Dollars in Thousands) Gross Amounts 1 Gross Amounts Net of Amounts Gross Amounts Not Offset in the Net Amount Commodity Cash Collateral 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 Puget Energy and Puget Sound Energy At December 31, 2013 (Dollars in Thousands) Gross Amounts 1 Gross Amounts Net of Amounts Gross Amounts Not Offset in the Net Amount Commodity Cash Collateral Assets Energy Derivative Contracts $ 26,600 $ — $ 26,600 $ (19,491 ) $ — $ 7,109 Liabilities Energy Derivative Contracts $ 72,988 $ — $ 72,988 $ (19,491 ) $ — $ 53,497 Interest Rate Swaps 2 $ 13,223 $ — $ 13,223 $ — $ — $ 13,223 1. All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of Offset. 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 Nine 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 December 31, 2014: Puget Energy and Puget Sound Energy Contingent Feature (Dollars in Thousands) Fair Value 1 Posted Contingent Credit rating 2 $ (37,398 ) $ — $ 37,398 Requested credit for adequate assurance (66,468 ) — — Forward value of contract 3 (2,490 ) — — Total $ (106,356 ) $ — $ 37,398 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.
Subsidiaries [Member]
Schedule of Derivative Instruments Gain (Loss) in Statement of Financial Performance	Puget Sound Energy Three Months Ended Nine Months Ended (Dollars in Thousands) Location 2015 2014 2015 2014 Commodity contracts: Electric derivatives Unrealized gain (loss) on derivative instruments, net 1 $ (5,588 ) $ (32,648 ) $ 5,795 $ (8,284 ) Electric generation fuel (11,768 ) (420 ) (27,512 ) 8,271 Purchased electricity (8,344 ) 972 (34,489 ) 2,687 Total gain (loss) recognized in income on derivatives $ (25,700 ) $ (32,096 ) $ (56,206 ) $ 2,674 1 Differences between Puget Energy and PSE for the nine months ending September 30, 2015 and September 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.	Puget Sound Energy Year Ended December 31, (Dollars in Thousands) Location 2014 2013 2012 Commodity contracts: Electric derivatives Unrealized gain (loss) on derivative instruments, net $ (85,636 ) $ 98,880 $ 119,120 Electric generation fuel 6,511 (27,008 ) (66,762 ) Purchased electricity (4,212 ) (38,299 ) (138,551 ) Total gain (loss) recognized in income on derivatives $ (83,337 ) $ 33,573 $ (86,193 )
Schedule of Derivative Instruments, Effect on Other Comprehensive Income (Loss)	Puget Sound Energy Three Months Ended Nine Months Ended (Dollars in Thousands) Location 2015 2014 2015 2014 Interest rate contracts: Interest expense 1 $ (122 ) $ (122 ) $ (366 ) $ (366 ) Commodity contracts: Electric derivatives Purchased electricity — — (1,055 ) (1,104 ) Total $ (122 ) $ (122 ) $ (1,421 ) $ (1,470 ) 1 Within the next twelve months, $0.5 million of losses in AOCI will be reclassified into earnings.	Puget Sound Energy Year Ended December 31, (Dollars in Thousands) Location 2014 2013 2012 Interest rate contracts: Interest expense $ (488 ) $ (488 ) $ (488 ) Commodity contracts: Electric derivatives Electric generation fuel — — 97 Purchased electricity (2,063 ) (3,922 ) (12,955 ) Total $ (2,551 ) $ (4,410 ) $ (13,346 )
Parent Company [Member]
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 Nine Months Ended (Dollars in Thousands) Location 2015 2014 2015 2014 Interest rate contracts: Non-hedged interest rate swap (expense) income $ (1,156 ) $ (323 ) $ (4,571 ) $ (2,430 ) Interest expense — 1,241 560 398 Commodity contracts: Electric derivatives Unrealized gain (loss) on derivative instruments, net 1 (5,588 ) (32,648 ) 6,339 (7,714 ) Electric generation fuel (11,768 ) (420 ) (27,512 ) 8,271 Purchased electricity (8,344 ) 972 (34,489 ) 2,687 Total gain (loss) recognized in income on derivatives $ (26,856 ) $ (31,178 ) $ (59,673 ) $ 1,212	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 Year Ended December 31, (Dollars in Thousands) Location 2014 2013 2012 Interest rate contracts: Other deductions $ (3,915 ) $ 2,420 $ (4,288 ) Interest expense 500 (5,904 ) (29,727 ) Commodity contracts: Electric derivatives Unrealized gain (loss) on derivative instruments, net 1 (84,146 ) 102,744 131,407 Electric generation fuel 6,511 (27,008 ) (66,762 ) Purchased electricity (4,212 ) (38,299 ) (138,551 ) Total gain (loss) recognized in income on derivatives $ (85,262 ) $ 33,953 $ (107,921 ) 1 For 2012, the amount differs from the amount stated in the statement of income as it does not include amortization related to contracts that were recorded at fair value at the time of the February 2009 merger and subsequently designated as NPNS of $2.2 million for the year ended December 31, 2012.
Schedule of Derivative Instruments, Effect on Other Comprehensive Income (Loss)		The following tables present the Company’s pre-tax gain (loss) on derivatives that were previously in a cash flow hedge relationship, and subsequently reclassified out of accumulated OCI into income: Puget Energy Year Ended December 31, (Dollars in Thousands) Location 2014 2013 2012 Interest rate contracts: Interest expense $ (144 ) $ (4,505 ) $ (17,811 ) Commodity contracts: Electric derivatives Electric generation fuel — — 100 Purchased electricity (572 ) (57 ) (671 ) Total $ (716 ) $ (4,562 ) $ (18,382 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis		The carrying values below are representative of fair values due to the short-term nature of these financial instruments. Puget Energy Carrying / Fair Value Carrying / Fair Value At December 31, 2014 At December 31, 2013 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Cash and Cash Equivalents $ 37,527 $ — $ 37,527 $ 44,302 $ — $ 44,302 Restricted Cash 32,863 — 32,863 7,171 — 7,171 Notes Receivable and Other — 53,503 53,503 — 53,449 53,449 Total assets $ 70,390 $ 53,503 $ 123,893 $ 51,473 $ 53,449 $ 104,922 Liabilities: Short-term debt $ 85,000 $ — $ 85,000 $ 162,000 $ — $ 162,000 Total liabilities $ 85,000 $ — $ 85,000 $ 162,000 $ — $ 162,000
Fair Value Inputs, Liabilities, Quantitative Information	The fair value of the junior subordinated and long-term notes was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company’s credit spreads as inputs, interpolating to the maturity date of each issue. Carrying values and estimated fair values were as follows: Puget Energy September 30, 2015 December 31, 2014 (Dollars in Thousands) Level Carrying Fair Carrying Fair Liabilities: Junior subordinated notes 2 $ 250,000 $ 269,915 $ 250,000 $ 276,235 Long-term debt (fixed-rate), net of discount 2 5,113,717 6,364,901 4,694,608 6,083,554 Long-term debt (variable-rate) 2 — — 299,000 299,000 Total liabilities $ 5,363,717 $ 6,634,816 $ 5,243,608 $ 6,658,789 Puget Sound Energy September 30, 2015 December 31, 2014 (Dollars in Thousands) Level Carrying Fair Carrying Fair Liabilities: Junior subordinated notes 2 $ 250,000 $ 269,915 $ 250,000 $ 276,235 Long-term debt (fixed-rate), net of discount 2 3,524,369 4,358,964 3,513,259 4,437,473 Total liabilities $ 3,774,369 $ 4,628,879 $ 3,763,259 $ 4,713,708	The fair value of the junior subordinated and long-term notes were estimated using the discounted cash flow method with U.S. Treasury yields and Company credit spreads as inputs, interpolating to the maturity date of each issue. Carrying values and estimated fair values were as follows: Puget Energy December 31, 2014 December 31, 2013 (Dollars in Thousands) Level Carrying Fair Carrying Fair Liabilities: Junior subordinated notes 2 $ 250,000 $ 276,235 $ 250,000 $ 269,366 Long-term debt (fixed-rate), net of discount 2 4,694,608 6,083,554 4,683,476 5,594,314 Long-term debt (variable-rate) 2 299,000 299,000 299,000 299,000 Total $ 5,243,608 $ 6,658,789 $ 5,232,476 $ 6,162,680 Puget Sound Energy December 31, 2014 December 31, 2013 (Dollars in Thousands) Level Carrying Fair Carrying Fair Liabilities: Junior subordinated notes 2 $ 250,000 $ 276,235 $ 250,000 $ 269,366 Long-term debt (fixed-rate), net of discount 2 3,513,259 4,437,473 3,513,258 4,038,455 Total $ 3,763,259 $ 4,713,708 $ 3,763,258 $ 4,307,821
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 (Dollars in Thousands) 2015 2014 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Total Electric Natural Total Balance at beginning of period $ (15,370 ) $ 823 $ (14,547 ) $ (4,693 ) $ (273 ) $ (4,966 ) Changes during period: Realized and unrealized energy derivatives: Included in earnings 1 (1,403 ) — (1,403 ) (3,116 ) — (3,116 ) Included in regulatory assets / liabilities — 1,295 1,295 — (725 ) (725 ) Settlements 3 1,017 (2,122 ) (1,105 ) (965 ) (680 ) (1,645 ) Transferred into Level 3 — — — 2,055 — 2,055 Transferred out of Level 3 3,314 (376 ) 2,938 (6,488 ) (60 ) (6,548 ) Balance at end of period $ (12,442 ) $ (380 ) $ (12,822 ) $ (13,207 ) $ (1,738 ) $ (14,945 ) Puget Energy and Puget Sound Energy Nine Months Ended (Dollars in Thousands) 2015 2014 Level 3 Roll-Forward Net Asset/(Liability) Electric Natural Total Electric Natural 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 (10,505 ) — (10,505 ) 1,939 — 1,939 Included in regulatory assets / liabilities — 4,233 4,233 — 1,654 1,654 Settlements 3 1,182 (2,420 ) (1,238 ) 1,114 (1,256 ) (142 ) Transferred into Level 3 (787 ) — (787 ) 5,155 (585 ) 4,570 Transferred out of Level 3 9,729 (154 ) 9,575 (5,994 ) (1,190 ) (7,184 ) Balance at end of period $ (12,442 ) $ (380 ) $ (12,822 ) $ (13,207 ) $ (1,738 ) $ (14,945 ) 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 $(1.5) million and $(3.3) million for the three months ended September 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 $(10.4) million and $(3.3) million for the nine months ended September 30, 2015 and 2014, respectively. 3 The Company had no purchases, sales or issuances during the reported periods.	Puget Energy and Puget Sound Energy Year Ended December 31, Level 3 Roll-Forward Net 2014 2013 2012 (Dollars in Thousands) Electric Gas Total Electric Gas Total Electric Gas Total Balance at beginning of period $ (15,421 ) $ (361 ) $ (15,782 ) $ (33,924 ) $ (1,602 ) $ (35,526 ) $ (90,311 ) $ (5,041 ) $ (95,352 ) Changes during period Realized and unrealized energy derivatives: Included in earnings 1 (5,537 ) — (5,537 ) (10,491 ) — (10,491 ) (21,362 ) — (21,362 ) Included in regulatory assets / liabilities — 1,630 1,630 — (945 ) (945 ) — (1,937 ) (1,937 ) Settlements 2 1,036 (1,534 ) (498 ) 11,609 (754 ) 10,855 59,133 969 60,102 Transferred into Level 3 5,155 (585 ) 4,570 (7,799 ) — (7,799 ) (55,548 ) (297 ) (55,845 ) Transferred out of Level 3 2,705 (1,190 ) 1,515 25,184 2,940 28,124 74,164 4,704 78,868 Balance at end of period $ (12,062 ) $ (2,040 ) $ (14,102 ) $ (15,421 ) $ (361 ) $ (15,782 ) $ (33,924 ) $ (1,602 ) $ (35,526 ) 1 Income Statement location: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(9.6) million, $(13.4) million, and $(15.2) million for the years ended December 31, 2014, 2013 and 2012, respectively. 2 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 Level 3 commodity contracts as of September 30, 2015: Fair Value Valuation Unobservable Range Weighted (Dollars in Thousands) Assets 1 Liabilities 1 Low High Electric $ 6,547 $ 18,989 Discounted cash flow Power Prices $13.39 per $30.06 per $24.05 per MWh Natural gas $ 2,629 $ 3,009 Discounted cash flow Natural Gas Prices $1.56 per $3.13 per $2.40 per MMBtu 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions. The following table presents the forward price ranges for the Company’s Level 3 commodity contracts as of December 31, 2014: Fair Value Valuation Unobservable Range Weighted (Dollars in Thousands) Assets 1 Liabilities 1 Low High Electric $ 3,168 $ 15,230 Discounted cash flow Power Prices $21.79 per $35.46 per $32.89 per MWh Natural gas $ 1,462 $ 3,502 Discounted cash flow Natural Gas Prices $3.11 per $3.83 per $3.28 per MMBtu 1 The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.	The only significant unobservable input into the fair value measurement of the Company’s Level 3 assets and liabilities is the forward price for electric and natural gas contracts. Below are the forward price ranges for the Company’s commodity contracts, as of December 31, 2014: (Dollars in Thousands) Fair Value Valuation Unobservable Range Weighted Derivative Instrument Assets 1 Liabilities 1 Low High Electric $ 3,168 $ 15,230 Discounted cash flow Power Prices $21.79 per $35.46 per $32.89 per MWh Natural gas $ 1,462 $ 3,502 Discounted cash flow Natural Gas Prices $3.11 per $3.83 per $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 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 $3.9 million. Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis At the time of merger, Puget Energy recorded the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle. ASC 360 requires long-lived assets to be tested for impairment on an annual basis, and upon the occurrence of any events or circumstances that would be more likely than not to reduce the fair value of the long-lived assets below their carrying value. One such triggering event is a significant decrease in the forward market prices of power. At December 31, 2014, Puget Energy completed a valuation and impairment test of its purchased power contracts classified as intangible assets. The valuation indicated a fair value of $437.6 million with an impairment to the Wells hydro contract. As of December 31, 2014, the carrying value for this contract was $65.3 million and its fair value on a discounted basis was $62.1 million, thereby requiring a write-down of $3.2 million to this intangible asset with a corresponding reduction in the regulatory liability. Below are significant unobservable inputs used in estimating the impaired long term power purchase contract’s fair value on December 31, 2014: Valuation Technique Unobservable Input Low High Average Discounted cash flow Power prices $19.30 per MWh $37.06 per MWh $29.53 per MWh Discounted cash flow Power contract costs $3,015 per qtr $4,783 per qtr $4,469 per qtr At June 30, 2013, Puget Energy completed a valuation and impairment test of its purchased power contracts classified as intangible assets. The valuation indicated a fair value of $484.1 million with an impairment to the Priest Rapids Reasonable Portion intangible asset contract. As of June 30, 2013, the carrying value for this intangible asset contract was $47.1 million and its fair value on a discounted basis was determined to be an asset of $33.6 million, thereby requiring a write-down of $13.5 million to the intangible asset with a corresponding reduction in the regulatory liability. Below are significant unobservable inputs used in estimating the impaired long term power purchase contract’s fair value on June 30, 2013: Valuation Technique Unobservable Input Low High Average Discounted cash flow Power prices $30.85 per MWh $65.35 per MWh $48.47 per MWh Discounted cash flow Power contract costs $389 per yr $6,845 per yr $4,110 per yr The valuations were measured using the income approach. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates which are classified as Level 3 within the fair value hierarchy. A less significant input is the discount rate reflective of PSE’s cost of capital used in the valuation.
Fair Value, by Balance Sheet Grouping	The following table presents the carrying value for cash, cash equivalents, restricted cash, notes receivable and short-term debt by fair value hierarchy level. The carrying values below are representative of fair values due to the short-term nature of these financial instruments. Puget Energy Carrying / Fair Value Carrying / Fair Value (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Cash and cash equivalents $ 20,200 $ — $ 20,200 $ 37,527 $ — $ 37,527 Restricted cash 7,036 — 7,036 32,863 — 32,863 Notes receivable and other investments — 50,294 50,294 — 53,503 53,503 Total assets $ 27,236 $ 50,294 $ 77,530 $ 70,390 $ 53,503 $ 123,893 Liabilities: Short-term debt $ 79,500 $ — $ 79,500 $ 85,000 $ — $ 85,000 Total liabilities $ 79,500 $ — $ 79,500 $ 85,000 $ — $ 85,000 Puget Sound Energy Carrying / Fair Value Carrying / Fair Value (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Cash and cash equivalents $ 19,419 $ — $ 19,419 $ 37,466 $ — $ 37,466 Restricted cash 7,036 — 7,036 32,863 — 32,863 Notes receivable and other investments — 50,294 50,294 — 53,503 53,503 Total assets $ 26,455 $ 50,294 $ 76,749 $ 70,329 $ 53,503 $ 123,832 Liabilities: Short-term debt $ 79,500 $ — $ 79,500 $ 85,000 $ — $ 85,000 Short-term debt owed to parent — — — — 28,933 28,933 Total liabilities $ 79,500 $ — $ 79,500 $ 85,000 $ 28,933 $ 113,933
Subsidiaries [Member]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	Puget Energy and Puget Sound Energy Fair Value Fair Value (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 9,369 $ 6,547 $ 15,916 $ 1,654 $ 3,168 $ 4,822 Natural gas derivative instruments 3,535 2,629 6,164 18,064 1,462 19,526 Total assets $ 12,904 $ 9,176 $ 22,080 $ 19,718 $ 4,630 $ 24,348 Liabilities: Electric derivative instruments $ 92,483 $ 18,989 $ 111,472 $ 91,998 $ 15,230 $ 107,228 Natural gas derivative instruments 66,560 3,009 69,569 85,305 3,502 88,807 Total liabilities $ 159,043 $ 21,998 $ 181,041 $ 177,303 $ 18,732 $ 196,035	Puget Sound Energy Carrying / Fair Value Carrying / Fair Value At December 31, 2014 At December 31, 2013 (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Cash and Cash Equivalents $ 37,466 $ — $ 37,466 $ 44,111 $ — $ 44,111 Restricted Cash 32,863 — 32,863 7,171 — 7,171 Notes Receivable and Other — 53,503 53,503 — 53,449 53,449 Total assets $ 70,329 $ 53,503 $ 123,832 $ 51,282 $ 53,449 $ 104,731 Liabilities: Short-term debt $ 85,000 $ — $ 85,000 $ 162,000 $ — $ 162,000 Short-term debt owed to parent — 28,933 28,933 — 29,598 29,598 Total liabilities $ 85,000 $ 28,933 $ 113,933 $ 162,000 $ 29,598 $ 191,598
Parent Company [Member]
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 (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Liabilities: Interest rate derivative instruments $ 7,622 $ — $ 7,622 $ 9,073 $ — $ 9,073 Total liabilities $ 7,622 $ — $ 7,622 $ 9,073 $ — $ 9,073
Fair Value, Measurements, Recurring
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis		The following tables present the Company’s financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis and the reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy: Puget Energy Fair Value Fair Value (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Interest rate derivative instruments $ 9,073 $ — $ 9,073 $ 13,223 $ — $ 13,223 Total derivative liabilities $ 9,073 $ — $ 9,073 $ 13,223 $ — $ 13,223 Puget Energy and Puget Sound Energy Fair Value Fair Value (Dollars in Thousands) Level 2 Level 3 Total Level 2 Level 3 Total Assets: Electric derivative instruments $ 1,654 $ 3,168 $ 4,822 $ 14,661 $ 3,818 $ 18,479 Natural gas derivative instruments 18,064 1,462 19,526 5,448 2,673 8,121 Total assets $ 19,718 $ 4,630 $ 24,348 $ 20,109 $ 6,491 $ 26,600 Liabilities: Electric derivative instruments $ 91,998 $ 15,230 $ 107,228 $ 18,073 $ 19,239 $ 37,312 Natural gas derivative instruments 85,305 3,502 88,807 32,642 3,034 35,676 Total liabilities $ 177,303 $ 18,732 $ 196,035 $ 50,715 $ 22,273 $ 72,988

Retirement Benefits (Tables)

Retirement Benefits (Tables)	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Schedule of Changes in Projected Benefit Obligations	The following table summarizes the Company’s change in benefit obligation for the periods ended September 30, 2015 and December 31, 2014: Puget Energy and Puget Sound Energy Qualified SERP Other (Dollars in Thousands) Nine Months Year Nine Months Year Nine Months Year Change in benefit obligation: Benefit obligation at beginning of period $ 690,194 $ 573,317 $ 55,855 $ 47,279 $ 15,688 $ 14,939 Service cost 15,966 17,437 831 1,042 84 112 Interest cost 21,066 28,039 1,710 2,310 467 684 Actuarial loss (gain) (588 ) 104,618 — 7,162 (540 ) 1,108 Benefits paid (41,804 ) (33,217 ) (3,026 ) (1,938 ) (1,045 ) (1,424 ) Medicare part D subsidy received — — — — 221 269 Benefit obligation at end of period $ 684,834 $ 690,194 $ 55,370 $ 55,855 $ 14,875 $ 15,688	The following tables summarize the Company’s change in benefit obligation, change in plan assets and amounts recognized in the Statements of Financial Position for the years ended December 31, 2014 and 2013: Puget Energy and Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2014 2013 2014 2013 2014 2013 Change in benefit obligation: Benefit obligation at beginning of period $ 573,317 $ 616,290 $ 47,279 $ 51,795 $ 14,939 $ 17,672 Service cost 17,437 19,285 1,042 1,498 112 134 Interest cost 28,039 24,754 2,310 2,045 684 664 Amendment — — — 478 — — Actuarial loss (gain) 104,618 (48,559 ) 7,162 (1,687 ) 1,108 (2,240 ) Benefits paid (33,217 ) (38,453 ) (1,938 ) (6,850 ) (1,424 ) (1,536 ) Medicare part D subsidy received — — — — 269 245 Benefit obligation at end of period $ 690,194 $ 573,317 $ 55,855 $ 47,279 $ 15,688 $ 14,939
Schedule of Changes in Fair Value of Plan Assets		Puget Energy and Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2014 2013 2014 2013 2014 2013 Change in plan assets: Fair value of plan assets at beginning of period $ 615,721 $ 531,183 $ — $ — $ 8,774 $ 7,541 Actual return on plan assets 25,669 102,591 — — 522 1,861 Employer contribution 18,000 20,400 1,938 6,850 488 908 Benefits paid (33,217 ) (38,453 ) (1,938 ) (6,850 ) (1,424 ) (1,536 ) Fair value of plan assets at end of period $ 626,173 $ 615,721 $ — $ — $ 8,360 $ 8,774 Funded status at end of period $ (64,021 ) $ 42,404 $ (55,855 ) $ (47,279 ) $ (7,328 ) $ (6,165 )
Schedule of Amounts Recognized in Balance Sheet and Accumulated Other Comprehensive Income		Puget Energy and Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2014 2013 2014 2013 2014 2013 Amounts recognized in Statement of Financial Position consist of: Noncurrent assets $ — $ 42,404 $ — $ — $ — $ — Current liabilities — — (4,386 ) (3,981 ) (355 ) (421 ) Noncurrent liabilities (64,021 ) — (51,469 ) (43,298 ) (6,973 ) (5,744 ) Net assets (liabilities) $ (64,021 ) $ 42,404 $ (55,855 ) $ (47,279 ) $ (7,328 ) $ (6,165 )
Schedule of Amounts Recognized in Other Comprehensive Income (Loss)		The following tables summarize Puget Energy’s and Puget Sound Energy’s benefit obligations recognized in other comprehensive income for the years ended December 31, 2014 and 2013: Puget Energy Qualified SERP Other (Dollars in Thousands) 2014 2013 2014 2013 2014 2013 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 121,413 $ (112,055 ) $ 7,162 $ (1,687 ) $ 1,121 $ (3,665 ) Amortization of net loss (gain) — (2,889 ) (913 ) (1,461 ) 394 (70 ) Prior service credit — — — 478 — — Amortization of prior service credit 1,980 1,980 (42 ) 17 — — Total change in other comprehensive income for year $ 123,393 $ (112,964 ) $ 6,207 $ (2,653 ) $ 1,515 $ (3,735 )
Schedule of Assumptions Used		In accounting for pension and other benefit obligations and costs under the plans, the following weighted-average actuarial assumptions were used by the Company: Qualified SERP Other 2014 2013 2012 2014 2013 2012 2014 2013 2012 Benefit Obligation Assumptions Discount rate 1 4.25 % 5.10 % 4.15 % 4.25 % 5.10 % 4.15 % 4.25 % 5.10 % 4.15 % Rate of compensation increase 4.50 % 4.50 % 4.50 % 4.50 % 4.50 % 4.50 % 4.50 % 4.50 % 4.50 % Medical trend rate — — — — — — 5.70 % 6.80 % 7.50 % Benefit Cost Assumptions Discount rate 5.10 % 4.15 % 4.75 % 5.10 % 4.15 % 4.75 % 5.10 % 4.15 % 4.75 % Rate of plan assets 7.75 % 7.75 % 7.75 % — — — 7.00 % 6.90 % 7.50 % Rate of compensation increase 4.50 % 4.50 % 4.50 % 4.50 % 4.50 % 4.50 % 4.50 % 4.50 % 4.50 % Medical trend rate — — — — — — 6.70 % 8.20 % 7.50 % 1 The Company calculates the present value of the pension liability using a discount rate of 4.25% which represents the single-rate equivalent of the AA rated corporate bond yield curve.
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates		A 1.0% change in the assumed medical inflation rate would have the following effects: 2014 2013 (Dollars in Thousands) 1% Increase 1% Decrease 1% Increase 1% Decrease Effect on post-retirement benefit obligation $ 47 $ (47 ) $ 66 $ (66 ) Effect on service and interest cost components 2 (2 ) 3 (3 )
Schedule of Expected Benefit Payments		The expected total benefits to be paid under the next five years and the aggregate total to be paid for the five years thereafter are as follows: (Dollars in Thousands) 2015 2016 2017 2018 2019 2020-2024 Qualified Pension total benefits $ 41,100 $ 41,400 $ 42,100 $ 43,300 $ 43,900 $ 237,300 SERP Pension total benefits $ 4,386 $ 2,595 1,940 5,346 5,811 18,759 Other Benefits total with Medicare Part D subsidy $ 1,080 $ 1,136 $ 1,113 $ 1,085 $ 1,062 $ 5,935 Other Benefits total without Medicare Part D subsidy $ 1,429 $ 1,414 $ 1,398 $ 1,380 $ 1,362 $ 6,340
Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets		To obtain the desired return needed to fund the pension benefit plans, the Retirement Plan Committee has established investment allocation percentages by asset classes as follows: Allocation Asset Class Minimum Target Maximum Domestic large cap equity 25 % 31 % 40 % Domestic small cap equity 0 % 9 % 15 % Non-U.S. equity 10 % 25 % 30 % Fixed income 15 % 25 % 30 % Real estate 0 % 0 % 10 % Absolute return 5 % 10 % 15 % Cash 0 % 0 % 5 %
Schedule of Allocation of Plan Assets		To obtain the desired return needed to fund the pension benefit plans, the Retirement Plan Committee has established investment allocation percentages by asset classes as follows: Allocation Asset Class Minimum Target Maximum Domestic large cap equity 25 % 31 % 40 % Domestic small cap equity 0 % 9 % 15 % Non-U.S. equity 10 % 25 % 30 % Fixed income 15 % 25 % 30 % Real estate 0 % 0 % 10 % Absolute return 5 % 10 % 15 % Cash 0 % 0 % 5 % The following table sets forth by level, within the fair value hierarchy, the qualified pension plan as of December 31, 2014 and 2013: Recurring Fair Value Measures Recurring Fair Value Measures (Dollars in Thousands) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets: Equities: Non-US equity 1 $ 71,026 $ 74,131 $ — $ 145,157 $ 76,188 $ 78,816 $ — $ 155,004 Domestic large cap equity 2 134,765 68,336 — 203,101 157,874 35,851 — 193,725 Domestic small cap equity 3 59,657 — — 59,657 62,867 — — 62,867 Total equities 265,448 142,467 — 407,915 296,929 114,667 — 411,596 Tactical asset allocation 4 — — — — — — — — Fixed income securities 5 72,331 67,182 — 139,513 135,007 — — 135,007 Absolute return 6 — — 65,251 65,251 — — 62,278 62,278 Cash and cash equivalents 7 12,650 — — 12,650 — 7,054 — 7,054 Subtotal $ 350,429 $ 209,649 $ 65,251 $ 625,329 $ 431,936 $ 121,721 $ 62,278 $ 615,935 Net (payable) receivable — — — 844 — — — (417 ) Accrued income — — — — — — — 203 Total assets $ 626,173 $ 615,721 1 Non—US Equity investments are comprised of a (1) mutual fund; and a (2) commingled fund. The investment in the mutual fund is valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014. The investment in the commingled fund is valued at the net asset value per share multiplied by the number of shares held as of December 31, 2014. 2 Domestic large cap equity investments are comprised of (1) common stock, and a (2) commingled fund. Investments in common stock are valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014. The investment in the commingled fund is valued at the net asset value per share multiplied by the number of shares held as of December 31, 2014. 3 Domestic small cap equity investments are comprised of (1) common stock and a (2) mutual fund. The investments in common stock are valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014. The investment in the mutual fund is valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014. 4 The tactical asset allocation investment is comprised of a commingled fund, which is valued at the net asset value per share multiplied by the number of shares held as of the measurement date. 5 Fixed income securities consist of a mutual fund. The investment in the mutual fund is valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014. 6 As of December 31, 2014 absolute return investments consist of two partnerships. The partnerships are valued using the financial reports as of December 31, 2014. These investments are a Level 3 under ASC 820 because the significant valuation inputs are primarily internal to the partnerships with little third party involvement. 7 The investment consists of a money market fund, which is valued at the net asset value per share of $1.00 per unit as of December 31, 2014. The money market fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or short-term in nature. The following table sets forth by level, within the fair value hierarchy, the Other Benefits plan assets which consist of insurance benefits for retired employees, at fair value: Recurring Fair Value Measures Recurring Fair Value Measures (Dollars in Thousands) Level 1 Level 2 Total Level 1 Level 2 Total Assets: Mutual fund 1 $ 8,301 $ — $ 8,301 $ 8,703 $ — $ 8,703 Cash equivalents 2 59 — 59 — 71 71 Total assets $ 8,360 $ — $ 8,360 $ 8,703 $ 71 $ 8,774 1 This is a publicly traded balanced mutual fund. The fund seeks regular income, conservation of principal, and an opportunity for long-term growth of principal and income. The fair value is determined by taking the number of shares owned by the plan, and multiplying by the market price as of December 31, 2014. 2 This is a money market fund. The money market fund investments are valued at the net asset value per share of $1.00 per unit as of December 31, 2014. The money market fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or short-term in nature.
Subsidiaries [Member]
Schedule of Amounts Recognized in Balance Sheet and Accumulated Other Comprehensive Income		Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2014 2013 2014 2013 2014 2013 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 247,331 $ 138,324 $ 19,751 $ 14,050 $ (3,733 ) $ (5,556 ) Prior service cost (credit) (10,952 ) (12,525 ) 339 383 3 6 Total $ 236,379 $ 125,799 $ 20,090 $ 14,433 $ (3,730 ) $ (5,550 )
Schedule of Net Benefit Costs	Puget Sound Energy Qualified SERP Other Three Months Ended (Dollars in Thousands) 2015 2014 2015 2014 2015 2014 Components of net periodic benefit cost: Service cost $ 5,322 $ 4,359 $ 277 $ 261 $ 28 $ 28 Interest cost 7,022 7,010 570 577 156 171 Expected return on plan assets (11,366 ) (10,813 ) — — (133 ) (134 ) Amortization of prior service cost (393 ) (393 ) 11 11 — 1 Amortization of net loss (gain) 5,139 3,298 530 365 (101 ) (175 ) Net periodic benefit cost $ 5,724 $ 3,461 $ 1,388 $ 1,214 $ (50 ) $ (109 ) Puget Sound Energy Qualified SERP Other Nine Months Ended (Dollars in Thousands) 2015 2014 2015 2014 2015 2014 Components of net periodic benefit cost: Service cost $ 15,966 $ 13,077 $ 831 $ 782 $ 84 $ 84 Interest cost 21,066 21,030 1,710 1,732 467 513 Expected return on plan assets (34,097 ) (32,439 ) — — (399 ) (401 ) Amortization of prior service cost (1,179 ) (1,179 ) 33 33 2 3 Amortization of net loss (gain) 15,416 9,895 1,590 1,095 (304 ) (527 ) Net periodic benefit cost $ 17,172 $ 10,384 $ 4,164 $ 3,642 $ (150 ) $ (328 )	Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2014 2013 2012 2014 2013 2012 2014 2013 2012 Components of net periodic benefit cost: Service cost $ 17,437 $ 19,285 $ 16,926 $ 1,042 $ 1,498 $ 1,073 $ 112 $ 134 $ 139 Interest cost 28,039 24,753 25,986 2,310 2,045 2,152 684 664 751 Expected return on plan assets (43,252 ) (40,685 ) (41,533 ) — — — (535 ) (436 ) (435 ) Amortization of prior service cost (credit) (1,573 ) (1,573 ) (1,573 ) 44 (16 ) 293 3 30 35 Amortization of net loss (gain) 13,195 20,612 15,015 1,461 2,191 1,432 (702 ) (284 ) (245 ) Amortization of transition obligation — — — — — — — — 50 Net periodic benefit cost $ 13,846 $ 22,392 $ 14,821 $ 4,857 $ 5,718 $ 4,950 $ (438 ) $ 108 $ 295
Schedule of Amounts Recognized in Other Comprehensive Income (Loss)		Puget Sound Energy Qualified SERP Other (Dollars in Thousands) 2014 2013 2014 2013 2014 2013 Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income: Net loss (gain) $ 122,202 $ (110,465 ) $ 7,162 $ (1,687 ) $ 1,121 $ (3,665 ) Amortization of net (loss) gain (13,195 ) (20,612 ) (1,461 ) (2,191 ) 702 284 Prior service cost (credit) — — — 477 — — Amortization of prior service cost (credit) 1,573 1,573 (44 ) 16 (3 ) (30 ) Amortization of transition obligation — — — — — — Total change in other comprehensive income for year $ 110,580 $ (129,504 ) $ 5,657 $ (3,385 ) $ 1,820 $ (3,411 )
Parent Company [Member]
Schedule of Amounts Recognized in Balance Sheet and Accumulated Other Comprehensive Income		Puget Energy Qualified SERP Other (Dollars in Thousands) 2014 2013 2014 2013 2014 2013 Amounts recognized in Accumulated Other Comprehensive Income consist of: Net loss (gain) $ 55,471 $ (65,943 ) $ 15,918 $ 9,670 $ (1,457 ) $ (2,972 ) Prior service cost (credit) (13,782 ) (15,762 ) 331 373 — — Total $ 41,689 $ (81,705 ) $ 16,249 $ 10,043 $ (1,457 ) $ (2,972 )
Schedule of Net Benefit Costs	The following tables summarize the Company’s net periodic benefit cost for the three and nine months ended September 30, 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 $ 5,322 $ 4,359 $ 277 $ 261 $ 28 $ 28 Interest cost 7,022 7,010 570 577 156 171 Expected return on plan assets (11,260 ) (10,616 ) — — (133 ) (134 ) Amortization of prior service cost (495 ) (495 ) 11 12 — — Amortization of net loss (gain) 972 — 410 228 (33 ) (228 ) Net periodic benefit cost $ 1,561 $ 258 $ 1,268 $ 1,078 $ 18 $ (163 ) Puget Energy Qualified SERP Other Nine Months Ended (Dollars in Thousands) 2015 2014 2015 2014 2015 2014 Components of net periodic benefit cost: Service cost $ 15,966 $ 13,077 $ 831 $ 782 $ 84 $ 84 Interest cost 21,066 21,030 1,710 1,732 467 513 Expected return on plan assets (33,779 ) (31,848 ) — — (399 ) (401 ) Amortization of prior service cost (1,485 ) (1,485 ) 33 33 — — Amortization of net loss (gain) 2,915 — 1,230 684 (99 ) (296 ) Net periodic benefit cost $ 4,683 $ 774 $ 3,804 $ 3,231 $ 53 $ (100 )	The following tables summarize Puget Energy’s and Puget Sound Energy’s net periodic benefit cost for the years ended December 31, 2014, 2013 and 2012: Puget Energy Qualified SERP Other (Dollars in Thousands) 2014 2013 2012 2014 2013 2012 2014 2013 2012 Components of net periodic benefit cost: Service cost $ 17,437 $ 19,285 $ 16,926 $ 1,042 $ 1,498 $ 1,073 $ 112 $ 134 $ 139 Interest cost 28,039 24,754 25,986 2,310 2,045 2,152 684 664 751 Expected return on plan assets (42,464 ) (39,095 ) (36,203 ) — — — (535 ) (436 ) (435 ) Amortization of prior service cost (credit) (1,980 ) (1,980 ) (1,980 ) 42 (17 ) — — — — Amortization of net loss — 2,889 768 913 1,461 702 (393 ) 69 53 Net periodic benefit cost $ 1,032 $ 5,853 $ 5,497 $ 4,307 $ 4,987 $ 3,927 $ (132 ) $ 431 $ 508

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Schedule of Components of Income Tax Expense (Benefit)	The details of income tax (benefit) expense are as follows: Puget Energy Year Ended December 31, (Dollars in Thousands) 2014 2013 2012 Charged to operating expenses: Current: Federal $ — $ — $ 4,268 State — — — Deferred: Federal 57,152 122,559 100,701 State (167 ) (151 ) (244 ) Total income tax expense $ 56,985 $ 122,408 $ 104,725
Schedule of Effective Income Tax Rate Reconciliation	Puget Energy Year Ended December 31, (Dollars in Thousands) 2014 2013 2012 Income taxes at the statutory rate $ 80,087 $ 142,847 $ 132,491 Increase (decrease): Production tax credit (23,073 ) (22,414 ) (22,188 ) AFUDC excluded from taxable income (3,790 ) (9,406 ) (16,543 ) Capitalized interest 2,947 7,294 9,757 Utility plant differences 7,090 9,527 8,674 Treasury grant amortization (8,808 ) (7,651 ) (1,007 ) Tenaska gas contract — 1 (4,687 ) Other—net 2,532 2,210 (1,772 ) Total income tax expense $ 56,985 $ 122,408 $ 104,725 Effective tax rate 24.9 % 30.0 % 27.7 %
Schedule of Deferred Tax Assets and Liabilities	The Company’s deferred tax liability at December 31, 2014 and 2013 is composed of amounts related to the following types of temporary differences: Puget Energy At December 31, (Dollars in Thousands) 2014 2013 Utility plant and equipment $ 1,720,730 $ 1,625,107 Regulatory asset for income taxes 95,432 146,867 Fair value of debt instruments 73,606 76,991 Other deferred tax liabilities 200,124 202,189 Subtotal deferred tax liabilities 2,089,892 2,051,154 Net operating loss carryforward (417,684 ) (374,606 ) Production tax credit carryforward (158,604 ) (135,531 ) Regulatory liability on production tax credit (84,344 ) (71,880 ) Fair value of derivative instruments (36,227 ) (7,166 ) Other deferred tax assets (32,121 ) (60,970 ) Subtotal deferred tax assets (728,980 ) (650,153 ) Total $ 1,360,912 $ 1,401,001
Schedule of Deferred Income Taxes by Balance Sheet Location	The above amounts have been classified in the Consolidated Balance Sheets as follows: Puget Energy At December 31 (Dollars in Thousands) 2014 2013 Current deferred taxes $ (161,445 ) $ (86,004 ) Non-current deferred taxes 1,522,357 1,487,005 Total $ 1,360,912 $ 1,401,001
Subsidiaries [Member]
Schedule of Components of Income Tax Expense (Benefit)	Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2014 2013 2012 Charged to operating expenses: Current: Federal $ — $ — $ 4,268 State — — — Deferred: Federal 89,342 160,886 145,040 State — — — Total income tax expense $ 89,342 $ 160,886 $ 149,308
Schedule of Effective Income Tax Rate Reconciliation	Puget Sound Energy Year Ended December 31, (Dollars in Thousands) 2014 2013 2012 Income taxes at the statutory rate $ 114,084 $ 180,955 $ 176,917 Increase (decrease): Production tax credit (23,073 ) (22,414 ) (22,188 ) AFUDC excluded from taxable income (3,790 ) (9,406 ) (16,543 ) Capitalized interest 2,947 7,294 9,757 Utility plant differences 7,090 9,527 8,674 Treasury grant amortization (8,808 ) (7,651 ) (1,007 ) Tenaska gas contract — 1 (4,687 ) Other—net 892 2,580 (1,615 ) Total income tax expense $ 89,342 $ 160,886 $ 149,308 Effective tax rate 27.4 % 31.1 % 29.5 %
Schedule of Deferred Tax Assets and Liabilities	Puget Sound Energy At December 31, (Dollars In Thousands) 2014 2013 Utility plant and equipment $ 1,720,730 $ 1,625,107 Regulatory asset for income taxes 94,913 146,350 Other deferred tax liabilities 171,380 131,977 Subtotal deferred tax liabilities 1,987,023 1,903,434 Net operating loss carryforward (181,514 ) (173,068 ) Production tax credit carryforward (158,604 ) (135,531 ) Regulatory liability on production tax credit (84,344 ) (71,880 ) Fair value of derivative instruments (39,067 ) (9,988 ) Other deferred tax assets (82,084 ) (69,175 ) Subtotal deferred tax assets (545,613 ) (459,642 ) Total $ 1,441,410 $ 1,443,792
Schedule of Deferred Income Taxes by Balance Sheet Location	Puget Sound Energy At December 31 (Dollars in Thousands) 2014 2013 Current deferred taxes $ (208,447 ) $ (141,058 ) Non-current deferred taxes 1,649,857 1,584,850 Total $ 1,441,410 $ 1,443,792

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Schedule of Long-term Contracts for Purchase of Electric Power	The Company’s expenses under these PUD contracts were as follows for the years ended December 31: (Dollars in Thousands) 2014 2013 2012 PUD contract costs $ 69,661 $ 63,365 $ 70,188 As of December 31, 2014, the Company purchased portions of the power output of the PUDs’ projects as set forth in the following table: Company’s Current Share of (Dollars in Thousands) Contract Percent of Megawatt Estimated 2015 Debt Interest Debt Chelan County PUD: Rock Island Project 2031 25.0 % 156 $ 29,854 $ 11,009 $ 6,174 $ 98,191 Rocky Reach Project 2031 25.0 % 325 27,583 8,245 3,343 53,299 Douglas County PUD: Wells Project 2018 29.9 % 251 17,277 9,383 2,597 64,931 Grant County PUD: Priest Rapids Development 2052 0.6 % 8 3,689 2,087 1,245 19,828 Wanapum Development 2052 0.6 % 9 3,689 2,087 1,245 19,828 Total 749 $ 82,092 $ 32,811 $ 14,604 $ 256,077
Schedule of Long-term Purchase Commitments	These contracts have varying terms and may include escalation and termination provisions. (Dollars in Thousands) 2015 2016 2017 2018 2019 Thereafter Total Columbia River projects $ 73,023 $ 75,360 $ 74,851 $ 65,981 $ 53,837 $ 644,666 $ 987,718 Other utilities 16,136 18,884 11,823 1,257 890 — 48,990 Non-utility contracts 117,372 153,863 199,056 204,292 209,699 1,354,191 2,238,473 Total $ 206,531 $ 248,107 $ 285,730 $ 271,530 $ 264,426 $ 1,998,857 $ 3,275,181 The quantified obligations are based on the FERC and NEB (National Energy Board) currently authorized rates, which are subject to change. Demand Charge Obligations (Dollars in Thousands) 2015 2016 2017 2018 2019 Thereafter Total Firm transportation service $ 154,121 $ 147,424 $ 144,751 $ 131,484 $ 112,249 $ 373,958 $ 1,063,987 Firm storage service 6,528 5,337 5,209 1,407 1,535 1,258 21,274 Total $ 160,649 $ 152,761 $ 149,960 $ 132,891 $ 113,784 $ 375,216 $ 1,085,261 The following table summarizes the Company’s estimated obligations for service contracts through the terms of its existing contracts. Service Contract Obligations (Dollars in Thousands) 2015 2016 2017 2018 2019 Thereafter Total Energy production service contracts $ 32,979 $ 15,650 $ 5,558 $ 4,064 $ 2,372 $ 23,443 $ 84,066 Automated meter reading system 25,402 16,081 13,362 13,996 14,602 51,986 135,429 Total $ 58,381 $ 31,731 $ 18,920 $ 18,060 $ 16,974 $ 75,429 $ 219,495

Accumulated Other Comprehensi43

Accumulated Other Comprehensive Income (Loss) (Tables)	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Schedule of Accumulated Other Comprehensive Income (Loss)	The following tables present the changes in the Company’s AOCI (loss) by component for the three and nine months ended September 30, 2015: Puget Energy Changes in AOCI, net of tax (Dollars in Thousands) Net unrealized Net unrealized Total Balance at June 30, 2015 $ (34,854 ) $ — $ (34,854 ) Other comprehensive income (loss) before reclassifications — — — Amounts reclassified from accumulated other comprehensive income (loss), net of tax 562 — 562 Net current-period other comprehensive income (loss) 562 — 562 Balance at September 30, 2015 $ (34,292 ) $ — $ (34,292 ) Puget Energy Changes in AOCI, net of tax (Dollars in Thousands) Net unrealized Net unrealized Total Balance at December 31, 2014 $ (36,710 ) $ (333 ) $ (37,043 ) Other comprehensive income (loss) before reclassifications 696 — 696 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 1,722 333 2,055 Net current-period other comprehensive income (loss) 2,418 333 2,751 Balance at September 30, 2015 $ (34,292 ) $ — $ (34,292 )	The following tables set forth the components of the Company’s accumulated other comprehensive income (loss) at: Puget Energy December 31, (Dollars in Thousands) 2014 2013 Net unrealized loss on energy derivative instruments $ (333 ) $ (705 ) Net unrealized loss on interest rate swaps — (94 ) Net unrealized loss and prior service cost on pension plans (36,710 ) 48,514 Total Puget Energy, net of tax $ (37,043 ) $ 47,715 Puget Sound Energy December 31, (Dollars in Thousands) 2014 2013 Net unrealized loss on energy derivative instruments $ (686 ) $ (2,027 ) Net unrealized loss on treasury interest rate swaps (5,990 ) (6,307 ) Net unrealized loss and prior service cost on pension plans (164,281 ) (87,405 ) Total PSE, net of tax $ (170,957 ) $ (95,739 ) The following tables present the changes in the Company’s accumulated other comprehensive income (loss) (AOCI) by component for the years ended December 31, 2014, 2013 and 2012, respectively. Puget Energy Changes in AOCI, net of tax (Dollars in Thousands) Net unrealized gain Net unrealized Net unrealized Total Balance at December 31, 2011 $ (15,195 ) $ (1,113 ) $ (14,599 ) $ (30,907 ) Other comprehensive income (loss) before reclassifications (13,574 ) — — (13,574 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax (296 ) 371 11,577 11,652 Net current-period other comprehensive income (loss) (13,870 ) 371 11,577 (1,922 ) Balance at December 31, 2012 $ (29,065 ) $ (742 ) $ (3,022 ) $ (32,829 ) Other comprehensive income (loss) before reclassifications 76,004 — — 76,004 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 1,575 37 2,928 4,540 Net current-period other comprehensive income (loss) 77,579 37 2,928 80,544 Balance at December 31, 2013 $ 48,514 $ (705 ) $ (94 ) $ 47,715 Other comprehensive income (loss) before reclassifications (84,301 ) — — (84,301 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax (923 ) 372 94 (457 ) Net current-period other comprehensive income (loss) (85,224 ) 372 94 (84,758 ) Balance at December 31, 2014 $ (36,710 ) $ (333 ) $ — $ (37,043 ) Puget Sound Energy Changes in AOCI, net of tax (Dollars in Thousands) Net unrealized gain Net unrealized gain Net unrealized gain Total Balance at December 31, 2011 $ (168,704 ) $ (12,934 ) $ (6,941 ) $ (188,579 ) Other comprehensive income (loss) before reclassifications (17,049 ) — — (17,049 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 9,755 8,358 317 18,430 Net current-period other comprehensive income (loss) (7,294 ) 8,358 317 1,381 Balance at December 31, 2012 $ (175,998 ) $ (4,576 ) $ (6,624 ) $ (187,198 ) Other comprehensive income (loss) before reclassifications 74,969 — — 74,969 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 13,624 2,549 317 16,490 Net current-period other comprehensive income (loss) 88,593 2,549 317 91,459 Balance at December 31, 2013 $ (87,405 ) $ (2,027 ) $ (6,307 ) $ (95,739 ) Other comprehensive income (loss) before reclassifications (84,955 ) — — (84,955 ) Amounts reclassified from accumulated other comprehensive income (loss), net of tax 8,079 1,341 317 9,737 Net current-period other comprehensive income (loss) (76,876 ) 1,341 317 (75,218 ) Balance at December 31, 2014 $ (164,281 ) $ (686 ) $ (5,990 ) $ (170,957 )
Reclassification out of Accumulated Other Comprehensive Income		Details about these reclassifications out of accumulated other comprehensive income (loss) for the years ended December 31, 2014, 2013 and 2012, respectively, are as follows: Puget Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the Amount reclassified from accumulated 2014 2013 2012 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) 1,938 1,997 1,980 Amortization of net gain (loss) (a) (519 ) (4,420 ) (1,524 ) Total before tax 1,419 (2,423 ) 456 Tax (expense) or benefit (496 ) 848 (160 ) Net of Tax $ 923 $ (1,575 ) $ 296 Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: Electric derivatives Electric generation fuel — — 100 Purchased electricity (572 ) (57 ) (671 ) Total before tax (572 ) (57 ) (571 ) Tax (expense) or benefit 200 20 200 Net of Tax $ (372 ) $ (37 ) $ (371 ) Net unrealized gain (loss) on interest rate swaps: Interest rate contracts Interest expense $ (144 ) $ (4,505 ) $ (17,811 ) Tax (expense) or benefit 50 1,577 6,234 Net of Tax $ (94 ) $ (2,928 ) $ (11,577 ) Total reclassification for the period Net of Tax $ 457 $ (4,540 ) $ (11,652 ) (a) These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 12 for additional details). Puget Sound Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the Amount reclassified from accumulated 2014 2013 2012 Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 1,526 $ 1,559 $ 1,245 Amortization of net gain (loss) (a) (13,954 ) (22,519 ) (16,203 ) Amortization of transition obligation (a) — — (50 ) Total before tax (12,428 ) (20,960 ) (15,008 ) Tax (expense) or benefit 4,349 7,336 5,253 Net of tax $ (8,079 ) $ (13,624 ) $ (9,755 ) Net unrealized gain (loss) on energy derivative instruments: Commodity contracts: Electric derivatives Electric generation fuel — — 97 Purchased electricity (2,063 ) (3,922 ) (12,955 ) Total before tax (2,063 ) (3,922 ) (12,858 ) Tax (expense) or benefit 722 1,373 4,500 Net of Tax $ (1,341 ) $ (2,549 ) $ (8,358 ) Net unrealized gain (loss) on treasury interest rate swaps: Interest rate contracts Interest expense (488 ) (488 ) (488 ) Tax (expense) or benefit 171 171 171 Net of Tax $ (317 ) $ (317 ) $ (317 ) Total reclassification for the period Net of Tax $ (9,737 ) $ (16,490 ) $ (18,430 ) (a ) These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 12 for additional details).
Subsidiaries [Member]
Schedule of Accumulated Other Comprehensive Income (Loss)	Puget Sound Energy Changes in AOCI, net of tax (Dollars in Thousands) Net unrealized Net unrealized Net unrealized Total Balance at June 30, 2015 $ (156,806 ) $ — $ (5,832 ) $ (162,638 ) Other comprehensive income (loss) before reclassifications — — — — Amounts reclassified from accumulated other comprehensive income (loss), net of tax 3,370 — 79 3,449 Net current-period other comprehensive income (loss) 3,370 — 79 3,449 Balance at September 30, 2015 $ (153,436 ) $ — $ (5,753 ) $ (159,189 ) Puget Sound Energy Changes in AOCI, net of tax (Dollars in Thousands) Net unrealized Net unrealized Net unrealized Total Balance at December 31, 2014 $ (164,281 ) $ (686 ) $ (5,990 ) $ (170,957 ) Other comprehensive income (loss) before reclassifications 712 — — 712 Amounts reclassified from accumulated other comprehensive income (loss), net of tax 10,133 686 237 11,056 Net current-period other comprehensive income (loss) 10,845 686 237 11,768 Balance at September 30, 2015 $ (153,436 ) $ — $ (5,753 ) $ (159,189 )
Reclassification out of Accumulated Other Comprehensive Income	Puget Sound Energy (Dollars in Thousands) Details about accumulated other comprehensive income (loss) components Affected line item in the income (loss) is presented Three Months Ended Nine Months Ended 2015 2014 2015 2014 Amount reclassified from accumulated other Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 383 $ 381 $ 1,145 $ 1,143 Amortization of net gain (loss) (a) (5,568 ) (3,488 ) (17,830 ) (10,463 ) Total before tax (5,185 ) (3,107 ) (16,685 ) (9,320 ) Tax (expense) or benefit 1,815 1,227 5,840 3,070 Net of Tax $ (3,370 ) $ (1,880 ) $ (10,845 ) $ (6,250 ) 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 ) (366 ) (366 ) Tax (expense) or benefit 43 43 129 129 Net of Tax $ (79 ) $ (79 ) $ (237 ) $ (237 ) Total reclassification for the period Net of Tax $ (3,449 ) $ (1,959 ) $ (11,768 ) $ (7,205 ) (a) These AOCI components are included in the computation of net periodic pension cost (see Note 5 for additional details).
Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income	Details about these reclassifications out of AOCI for the three and nine months ended September 30, 2015, and 2014, are as follows: Puget Energy (Dollars in Thousands) Details about accumulated other Affected line item in the income (loss) is presented Three Months Ended Nine Months Ended 2015 2014 2015 2014 Amount reclassified from accumulated Net unrealized gain (loss) and prior service cost on pension plans: Amortization of prior service cost (a) $ 484 $ 483 $ 1,452 $ 1,452 Amortization of net gain (loss) (a) (1,349 ) — (5,172 ) (388 ) Total before tax (865 ) 483 (3,720 ) 1,064 Tax (expense) or benefit 303 (169 ) 1,302 (703 ) Net of Tax $ (562 ) $ 314 $ (2,418 ) $ 361 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 $ (562 ) $ 314 $ (2,751 ) $ (80 ) (a) These AOCI components are included in the computation of net periodic pension cost (see Note 5 for additional details).

Summary of Consolidation Accoun

Summary of Consolidation Accounting Policy (Detail) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015USD ($)mi²	Sep. 30, 2014USD ($)	Sep. 30, 2015USD ($)mi²	Sep. 30, 2014USD ($)	Dec. 31, 2014USD ($)mi²Unit	Dec. 31, 2013USD ($)	Dec. 31, 2012USD ($)	Jan. 01, 2015	Dec. 31, 2011USD ($)	Feb. 06, 2009USD ($)
Revenue Recognition
Excise taxes collected					$ 231,700	$ 243,900	$ 244,200
Goodwill	$ 1,656,513		$ 1,656,513		$ 1,656,513	1,656,513				$ 1,700,000
Number of reportable segments | Unit					1
Cash and Cash Equivalents, at Carrying Value	20,200	$ 26,470	20,200	$ 26,470	$ 37,527	44,302	$ 135,542		$ 37,235
Cash equivalents					1,800	2,600
Allowance for doubtful accounts	$ 11,488		$ 11,488		7,472	$ 7,385
Self Insurance [Abstract]
Public Utilities, Rate Case, Deferred Storm Costs Threshold					$ 8,000
Electric Transmission
Revenue Recognition
Annual depreciation provision					2.80%	2.80%	2.90%
Gas Transmission Equipment
Revenue Recognition
Annual depreciation provision					3.40%	3.40%	3.40%
Common Plant
Revenue Recognition
Annual depreciation provision					8.50%	11.40%	11.60%
Maximum
Self Insurance [Abstract]
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)								3.00%
Subsidiaries [Member]
Accounting Policies [Line Items]
Area of service territory | mi²	6,000		6,000		6,000
Revenue Recognition
Excise taxes collected	$ 47,600	$ 43,600	$ 167,500	$ 172,100
Allowance for doubtful accounts					$ 7,472	$ 7,385

Summary of Significant Accoun45

Summary of Significant Accounting Policies - AFUDC (Detail)	6 Months Ended	12 Months Ended	14 Months Ended	25 Months Ended
	Dec. 31, 2013	Dec. 31, 2014	Jun. 30, 2013	May. 13, 2012
Regulatory Assets [Line Items]
Washington Commission AFUDC Rates	7.77%		7.80%	8.10%
Public Utilities, Property, Plant and Equipment, Non-project Electric Utility Plant, Estimated Useful Life Average		30 years

Summary of Significant Accoun46

Summary of Significant Accounting Policies - Accumulated Other Comprehensive Income (Loss) (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Jun. 29, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Summary of Consolidation Policy
Net unrealized loss on energy derivative instruments			$ (333)	$ (705)
Net unrealized loss on interest rate swaps			0	(94)
Net unrealized loss and prior service cost on pension plans			(36,710)	48,514
Accumulated other comprehensive income (loss), net of tax	$ (34,292)		(37,043)	47,715
Subsidiaries [Member]
Summary of Consolidation Policy
Net unrealized loss on energy derivative instruments			(686)	(2,027)
Net unrealized loss on interest rate swaps			(5,990)	(6,307)
Net unrealized loss and prior service cost on pension plans			(164,281)	(87,405)
Accumulated other comprehensive income (loss), net of tax	$ (159,189)	$ (162,638)	$ (170,957)	$ (95,739)	$ (187,198)	$ (188,579)

Regulation and Rates Schedule o

Regulation and Rates Schedule of Allowed Return on the Net Regulatory Assets and Liabilities (Detail)	6 Months Ended	14 Months Ended	25 Months Ended
	Dec. 31, 2013	Jun. 30, 2013	May. 13, 2012
Regulated Operations [Abstract]
Regulated Utility, Allowed Rate of Return on Net Regulatory Assets and Liabilities	7.77%	7.80%	8.10%
Regulated Utility, After-tax Allowed Rate of Return on Net Regulatory Assets and Liabilities	6.69%	6.71%	6.90%

Regulation and Rates Net regula

Regulation and Rates Net regulatory assets and liabilities (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2014	Sep. 30, 2015	Dec. 31, 2013
Regulatory Assets [Line Items]
Regulatory Liabilities		$ (633,471)	$ (637,195)	$ (689,060)
Subsidiaries [Member] | Cost of removal
Regulatory Assets [Line Items]
Regulatory Liabilities	[1]	(313,088)		(269,536)
Subsidiaries [Member] | Deferred income taxes
Regulatory Assets [Line Items]
Regulatory Liabilities	[2]	$ (93,616)		(93,618)
Subsidiaries [Member] | PGA payable
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		1 year
Regulatory Liabilities		$ 0		(5,938)
Subsidiaries [Member] | PCA mechanism
Regulatory Assets [Line Items]
Regulatory Liabilities	[3]	$ 0		(5,345)
Subsidiaries [Member] | Decoupling over-collection
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		2 years
Regulatory Liabilities		$ (12,582)		(20,535)
Subsidiaries [Member] | Summit purchase option buy-out
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		5 years 9 months 18 days
Regulatory Liabilities		$ (9,188)		(10,763)
Subsidiaries [Member] | Deferred gain on Jefferson County sale
Regulatory Assets [Line Items]
Regulatory Liabilities		$ (4,731)		(60,844)
Subsidiaries [Member] | Deferred credit on Biogas sale
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		1 year
Regulatory Liabilities		$ (1,445)		(10,908)
Subsidiaries [Member] | Deferred credit on gas pipeline capacity
Regulatory Assets [Line Items]
Regulatory Liabilities		$ (3,564)		(4,508)
Net Regulatory Assets, Remaining Amortization Period, Max		3 years 9 months 18 days
Subsidiaries [Member] | Renewable energy credits
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		1 year
Regulatory Liabilities		$ (2,383)		(5,820)
Subsidiaries [Member] | Treasury grants
Regulatory Assets [Line Items]
Regulatory Liabilities		$ (180,496)		(203,889)
Net Regulatory Assets, Remaining Amortization Period, Max		44 years
Subsidiaries [Member] | Treasury grant amortization deferral [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities		$ (8,197)		0
Net Regulatory Assets, Remaining Amortization Period, Max		4 years
Subsidiaries [Member] | Various other regulatory liabilities
Regulatory Assets [Line Items]
Regulatory Liabilities		$ (6,092)		(5,755)
Net Regulatory Assets, Remaining Amortization Period, Max		4 years
Subsidiaries [Member] | Liabilities, Total
Regulatory Assets [Line Items]
Regulatory Liabilities		$ (635,382)		(697,459)
Subsidiaries [Member] | Net Regulatory Assets
Regulatory Assets [Line Items]
Net Regulatory Assets		352,020		198,273
Subsidiaries [Member] | PGA deferral of unrealized losses on derivative instruments
Regulatory Assets [Line Items]
Regulatory Assets	[3]	$ 69,280		27,555
Subsidiaries [Member] | Chelan PUD contract initiation
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		16 years 9 months 18 days
Regulatory Assets		$ 119,316		126,404
Subsidiaries [Member] | Storm damage costs electric
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Max		4 years
Regulatory Assets		$ 118,824		116,328
Subsidiaries [Member] | Environmental remediation
Regulatory Assets [Line Items]
Regulatory Assets	[3]	$ 66,018		57,342
Subsidiaries [Member] | Baker Dam Licensing Operating Maintenance Costs [Member]
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		44 years
Regulatory Assets		$ 61,577		57,270
Subsidiaries [Member] | Snoqualmie Licensing Operating Maintenance Costs
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		30 years
Regulatory Assets		$ 9,202		10,881
Subsidiaries [Member] | Colstrip common property
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		9 years 6 months
Regulatory Assets		$ 6,764		7,479
Subsidiaries [Member] | Deferred income taxes
Regulatory Assets [Line Items]
Regulatory Assets	[3]	$ 94,913		146,350
Subsidiaries [Member] | Deferred Washington Commission AFUDC
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Max		35 years
Regulatory Assets		$ 53,709		55,495
Subsidiaries [Member] | Energy Conservation Costs [Member]
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Max		2 years
Regulatory Assets		$ 42,374		35,987
Subsidiaries [Member] | Unamortized loss on reacquired debt
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Max		21 years 6 months
Regulatory Assets		$ 35,667		37,832
Subsidiaries [Member] | White River relicensing and other costs
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		17 years 10 months 24 days
Regulatory Assets		$ 26,685		28,190
Subsidiaries [Member] | Mint Farm ownership and operating costs
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		10 years 3 months 18 days
Regulatory Assets		$ 20,320		22,320
Subsidiaries [Member] | Investment in Bonneville Exchange power contract
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		2 years 6 months
Regulatory Assets		$ 8,816		12,343
Subsidiaries [Member] | Ferndale
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		4 years 9 months 18 days
Regulatory Assets		$ 19,232		22,811
Subsidiaries [Member] | Lower Snake River
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Max		22 years 3 months 18 days
Regulatory Assets		$ 86,275		92,924
Subsidiaries [Member] | Snoqualmie
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		3 years 9 months 18 days
Regulatory Assets		$ 6,798		8,009
Subsidiaries [Member] | Property tax tracker
Regulatory Assets [Line Items]
Regulatory Assets		$ 32,253		22,134
Subsidiaries [Member] | PGA receivable [Domain]
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		1 year
Regulatory Assets		$ 21,073		0
Subsidiaries [Member] | PCA mechanism
Regulatory Assets [Line Items]
Regulatory Assets	[3]	$ 4,623		0
Subsidiaries [Member] | Electron Unrecovered Loss
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		4 years
Regulatory Assets		$ 14,008		0
Subsidiaries [Member] | Decoupling Under-Collection
Regulatory Assets [Line Items]
Regulatory Assets		55,363		0
Subsidiaries [Member] | Various other regulatory assets
Regulatory Assets [Line Items]
Regulatory Assets		14,312		8,078
Subsidiaries [Member] | Assets, Total
Regulatory Assets [Line Items]
Regulatory Assets		$ 987,402		895,732
Subsidiaries [Member] | Maximum | Deferred gain on Jefferson County sale
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		1 year
Subsidiaries [Member] | Maximum | Property tax tracker
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		2 years
Subsidiaries [Member] | Maximum | Decoupling Under-Collection
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period		2 years
Parent Company [Member] | Various other regulatory liabilities
Regulatory Assets [Line Items]
Regulatory Liabilities		$ (2,820)		(2,884)
Parent Company [Member] | Liabilities, Total
Regulatory Assets [Line Items]
Regulatory Liabilities		(1,029,591)		(1,143,408)
Parent Company [Member] | Net Regulatory Assets
Regulatory Assets [Line Items]
Net Regulatory Assets		(11,812)		(213,406)
Parent Company [Member] | Regulatory liabilities related to power contracts
Regulatory Assets [Line Items]
Regulatory Liabilities		$ (391,389)		(443,065)
Net Regulatory Assets, Remaining Amortization Period, Max		37 years
Parent Company [Member] | Various other regulatory assets
Regulatory Assets [Line Items]
Regulatory Assets		$ 561		517
Parent Company [Member] | Assets, Total
Regulatory Assets [Line Items]
Regulatory Assets		$ 1,017,779		930,002
Parent Company [Member] | Requlatory Assets Related to Power Contracts
Regulatory Assets [Line Items]
Net Regulatory Assets, Remaining Amortization Period, Max		22 years
Regulatory Assets		$ 29,816		$ 33,753
[1]	The balance is dependent upon the cost of removal of underlying assets and the life of utility plant.
[2]	Amortization will begin once PTCs are utilized by PSE on its tax return.
[3]	Amortization periods vary depending on timing of underlying transactions or awaiting regulatory approval in a future Washington Commission rate proceeding.

Regulation and Rates (Detail)

Regulation and Rates (Detail)	11 Months Ended	12 Months Ended
	Dec. 31, 2013USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2012USD ($)	Jan. 31, 2013USD ($)	Feb. 28, 2012MW	Dec. 22, 2009USD ($)	Nov. 09, 2009MW	Nov. 08, 2009MW
Regulatory Assets [Line Items]
Public Utilities, Rate Case, Deferred Storm Costs Threshold		$ 8,000,000
Facility Power Capacity | MW						343		273	229
Accrual for Environmental Loss Contingencies		25,200,000
Electric [Member]
Regulatory Assets [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Losses, Low Estimate		5,700,000
Environmental Expense and Liabilities		13,400,000	$ 12,300,000	$ 10,900,000
Gas Plant [Member]
Regulatory Assets [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Losses, Low Estimate		35,400,000
Environmental Expense and Liabilities		52,600,000	45,100,000	66,400,000
Subsidiaries [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities Reclassified from Accumulated Depreciation		313,100,000	269,500,000
Storm Damage Costs Incurred During Period		29,700,000	9,400,000
Storm Damage Costs Deferred During Period		$ 18,000,000	$ 0
American Recovery and Reinvestment Tax Act of 2009, Grant Approved Amount				$ 205,300,000	$ 2,400,000		$ 28,700,000
American Recovery and Reinvestment Tax Act of 2009, Grant, Amortization Period Included in Customer Pass Through	11 months
American Recovery and Reinvestment Tax Act of 2009, Grant, Overall Average Rate Reduction	2.76%	0.26%
American Recovery and Reinvestment Tax Act of 2009, Grant Amortization Period	10 years
American Recovery and Reinvestment Tax Act of 2009, Grant Pass Through Amount	$ 34,600,000	$ 37,800,000
American Recovery and Reinvestment Tax Act of 2009, Grant Pass Through Interest Amount	$ 23,800,000	20,600,000
American Recovery and Reinvestment Tax Act of 2009, Total Grant Pass Through Amount		$ 58,500,000

Regulation and Rates Rate Adjus

Regulation and Rates Rate Adjustments (Detail) - USD ($) $ in Thousands	Sep. 11, 2014	Mar. 28, 2014	Mar. 30, 2013	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 18, 2015	Jun. 29, 2015	Jun. 01, 2015	May. 01, 2015	Jan. 01, 2015	Dec. 01, 2014	Nov. 01, 2014	Oct. 30, 2014	May. 23, 2014	May. 01, 2014	Jan. 02, 2014	Nov. 01, 2013	Jul. 01, 2013	Jun. 25, 2013	Nov. 01, 2012	Jun. 28, 2012	May. 14, 2012	Nov. 01, 2011	Apr. 01, 2011
Regulation and Rates [Line Items]
Treasury grant payment received				$ 0	$ 107,876	$ 107,876	$ 0	$ 205,261
Deferral Trigger [Member]
Regulation and Rates [Line Items]
Annual Power Cost Variability, Amount				20,000																		$ 30,000
Jefferson County Public Utility District
Regulation and Rates [Line Items]
Property, Plant and Equipment, Net			$ 46,700
Significant Acquisitions and Disposals, Gain (Loss) on Sale or Disposal, Pretax			60,000
Decoupling Mechanism | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)													2.20%
Subsidiaries [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Weighted Cost of Capital										7.77%											7.77%
Public Utilities, Rate Case, Approved Effective Common Equity in Capital Structure										48.00%											48.00%
Public Utilities, Rate Case, Approved Effective Return on Equity										9.80%											9.80%
Treasury grant payment received						107,876
Subsidiaries [Member] | Jefferson County Public Utility District
Regulation and Rates [Line Items]
Significant Acquisitions and Disposals, Gain (Loss) on Sale or Disposal, Pretax	$ 7,500	$ 3,000	45,000
Subsidiaries [Member] | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Weighted Cost of Capital																									7.80%
Public Utilities, Rate Case, Approved Effective Common Equity in Capital Structure																									48.00%
Public Utilities, Rate Case, Approved Effective Return on Equity																									9.80%
Subsidiaries [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Weighted Cost of Capital																									7.80%
Public Utilities, Rate Case, Approved Effective Common Equity in Capital Structure																									48.00%
Public Utilities, Rate Case, Approved Effective Return on Equity																									9.80%
Accounting Petition, Approved Effective Increase (Decrease) to Revenue																								$ 6,900
Accounting Petition, Approved Effective Increase (Decrease) to Conservation Amortization Expense																								$ 6,600
Subsidiaries [Member] | Power Cost Only Rate Case (PCORC) [Member] | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)														$ (19,400)			$ (9,600)			$ 10,500
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)														(0.90%)			(0.50%)			0.50%
Subsidiaries [Member] | Decoupling Mechanism
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)												$ (12,000)
Subsidiaries [Member] | Decoupling Mechanism | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)												$ 53,800						$ 10,600			$ 21,400
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)												2.60%						0.50%			1.00%
Subsidiaries [Member] | Decoupling Mechanism | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)						(1,300)						$ 22,000						$ (1,000)			$ 10,800
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)												2.10%						(0.10%)			1.10%
Subsidiaries [Member] | Property tax tracker | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)																		$ 11,000
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)																		0.50%
Subsidiaries [Member] | Property tax tracker | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)																		$ 5,600
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)																		0.60%
Subsidiaries [Member] | Energy Conservation Costs [Member] | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)																		$ 12,200
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)																		0.50%
Subsidiaries [Member] | Energy Conservation Costs [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)																		$ 300
Subsidiaries [Member] | Expedited Rate Filing | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)																					$ 30,700
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)																			3.00%		1.50%
Subsidiaries [Member] | Expedited Rate Filing | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)																					$ (2,000)
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)																			2.20%		(0.20%)
Subsidiaries [Member] | General Rate Case [Member] | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)																									$ 63,300
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)																									3.20%
Subsidiaries [Member] | General Rate Case [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)																									$ 13,400		$ 19,000
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)																									1.30%		1.80%
Subsidiaries [Member] | Purchased Gas Adjustment (PGA) [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)									$ (185,900)						$ (23,300)	$ 23,300				$ 4,000			$ (77,000)			$ (43,500)
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)									(17.40%)						(2.50%)	2.50%				0.40%			(7.70%)			(4.30%)
Subsidiaries [Member] | Property tax tracker [Member] [Domain] [Domain] | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)												$ 6,500						$ 11,000
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)												0.30%						0.50%
Subsidiaries [Member] | Property tax tracker [Member] [Domain] [Domain] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)											$ (2,300)							$ 5,600
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)											(0.20%)							0.60%
Subsidiaries [Member] | Conservation Rider [Member] | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)																		$ 12,200
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)																		0.60%
Subsidiaries [Member] | Conservation Rider [Member] | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)																		$ 300
Customers | Jefferson County Public Utility District
Regulation and Rates [Line Items]
Significant Acquisitions and Disposals, Gain (Loss) on Sale or Disposal, Pretax	$ 52,700	$ 57,000	$ 15,000
Maximum
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)													3.00%
Maximum | Decoupling Mechanism
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)													3.00%
Deferred Revenue [Domain] | Subsidiaries [Member] | Decoupling Mechanism | Electric [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)						$ 1,900
Deferred Revenue [Domain] | Subsidiaries [Member] | Decoupling Mechanism | Natural Gas [Member]
Regulation and Rates [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)				$ 8,200

Regulation and Rates Power Cost

Regulation and Rates Power Cost Adjustment Mechanism (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Plus/Minus $20 million
Regulation and Rates [Line Items]
Annual Power Cost Variability, Amount		$ 20
Plus/Minus $20 million | Customers' Share
Regulation and Rates [Line Items]
Annual Power Cost Variability		0.00%
Plus/Minus $20 million | Company's Share
Regulation and Rates [Line Items]
Annual Power Cost Variability		100.00%
Plus/Minus $20 million - $40 million | Customers' Share
Regulation and Rates [Line Items]
Annual Power Cost Variability		50.00%
Plus/Minus $20 million - $40 million | Company's Share
Regulation and Rates [Line Items]
Annual Power Cost Variability		50.00%
Plus/Minus $40 million - $120 million | Customers' Share
Regulation and Rates [Line Items]
Annual Power Cost Variability		90.00%
Plus/Minus $40 million - $120 million | Company's Share
Regulation and Rates [Line Items]
Annual Power Cost Variability		10.00%
Plus/Minus $120 million
Regulation and Rates [Line Items]
Annual Power Cost Variability, Amount		$ 120
Plus/Minus $120 million | Customers' Share
Regulation and Rates [Line Items]
Annual Power Cost Variability		95.00%
Plus/Minus $120 million | Company's Share
Regulation and Rates [Line Items]
Annual Power Cost Variability		5.00%
Plus/Minus $17 million
Regulation and Rates [Line Items]
Annual Power Cost Variability, Amount	$ 17
Plus/Minus $17 million | Customers' Share | Over Recovery [Member]
Regulation and Rates [Line Items]
Annual Power Cost Variability, Percentage	0.00%
Plus/Minus $17 million | Customers' Share | Under Recovery [Member]
Regulation and Rates [Line Items]
Annual Power Cost Variability, Percentage	0.00%
Plus/Minus $17 million | Company's Share | Over Recovery [Member]
Regulation and Rates [Line Items]
Annual Power Cost Variability, Percentage	100.00%
Plus/Minus $17 million | Company's Share | Under Recovery [Member]
Regulation and Rates [Line Items]
Annual Power Cost Variability, Percentage	100.00%
Plus/Minus $17 million - $40 million | Customers' Share | Over Recovery [Member]
Regulation and Rates [Line Items]
Annual Power Cost Variability, Percentage	65.00%
Plus/Minus $17 million - $40 million | Customers' Share | Under Recovery [Member]
Regulation and Rates [Line Items]
Annual Power Cost Variability, Percentage	50.00%
Plus/Minus $17 million - $40 million | Company's Share | Over Recovery [Member]
Regulation and Rates [Line Items]
Annual Power Cost Variability, Percentage	35.00%
Plus/Minus $17 million - $40 million | Company's Share | Under Recovery [Member]
Regulation and Rates [Line Items]
Annual Power Cost Variability, Percentage	50.00%
Plus/Minus $40 million
Regulation and Rates [Line Items]
Annual Power Cost Variability, Amount	$ 40
Plus/Minus $40 million | Customers' Share | Over Recovery [Member]
Regulation and Rates [Line Items]
Annual Power Cost Variability, Percentage	90.00%
Plus/Minus $40 million | Customers' Share | Under Recovery [Member]
Regulation and Rates [Line Items]
Annual Power Cost Variability, Percentage	90.00%
Plus/Minus $40 million | Company's Share | Over Recovery [Member]
Regulation and Rates [Line Items]
Annual Power Cost Variability, Percentage	10.00%
Plus/Minus $40 million | Company's Share | Under Recovery [Member]
Regulation and Rates [Line Items]
Annual Power Cost Variability, Percentage	10.00%
Minimum | Plus/Minus $20 million - $40 million
Regulation and Rates [Line Items]
Annual Power Cost Variability, Amount		$ 20
Minimum | Plus/Minus $40 million - $120 million
Regulation and Rates [Line Items]
Annual Power Cost Variability, Amount		40
Minimum | Plus/Minus $17 million - $40 million
Regulation and Rates [Line Items]
Annual Power Cost Variability, Amount	$ 17
Maximum | Plus/Minus $20 million - $40 million
Regulation and Rates [Line Items]
Annual Power Cost Variability, Amount		40
Maximum | Plus/Minus $40 million - $120 million
Regulation and Rates [Line Items]
Annual Power Cost Variability, Amount		$ 120
Maximum | Plus/Minus $17 million - $40 million
Regulation and Rates [Line Items]
Annual Power Cost Variability, Amount	$ 40

Dividend Payment Restrictions (

Dividend Payment Restrictions (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2014USD ($)
Parent [Line Items]
Retained Earnings, Unappropriated	$ 438.4
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio, Threshold For Dividend Payment	2
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End	3.1
Subsidiaries [Member]
Parent [Line Items]
Dividends, Common Equity Ratio, Threshold For Dividend Payment	44.00%
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio, Threshold For Dividend Payment	3
Dividends, Common Equity Ratio at Period End	47.70%
Dividends, Earnings Before Interest, Tax, Deprecation and Amortization Ratio at Period End	4.3

Utility Plant (Detail)

Utility Plant (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2014	Sep. 30, 2015	Dec. 31, 2013
Utility Plant
Distribution plant		$ 4,748,988		$ 4,448,451
Production plant		2,973,853		2,966,223
Transmission plant		1,189,296		1,043,605
General plant		481,116		504,965
Intangible plant (including capitalized software)		311,959		316,614
Plant acquisition adjustment		242,826		242,826
Underground storage		28,859		27,857
Liquefied natural gas storage		12,628		12,622
Plant held for future use		54,996		28,742
Recoverable cushion gas		8,655		8,655
Public Utilities, Property, Plant and Equipment, Other Property, Plant and Equipment		91,519		124,589
Public Utilities, Property, Plant and Equipment Grant		(105,659)		0
Capital leases, net of accumulated amortization	[1]	9,473		17,051
Less: Accumulated depreciation and amortization		(1,611,220)	$ (1,804,201)	(1,373,178)
Subtotal		8,437,289		8,369,022
Construction work in progress		239,690	353,388	310,318
Net utility plant		8,676,979	$ 8,834,916	8,679,340
Accumulated amortization of capital leases		$ 28,400		20,800
Minimum
Utility Plant
Distribution plant, Estimated Useful Life		10 years
Production plant, Estimated Useful Life		25 years
Transmission plant, Estimated Useful Life		45 years
General plant, Estimated Useful Life		5 years
Intangible plant (including capitalized software), Estimated Useful Life		3 years
Plant acquisition adjustment, Estimated Useful Life		7 years
Underground storage, Estimated Useful Life		25 years
Liquefied natural gas storage, Estimated Useful Life		25 years
Public Utilities, Property, Plant and Equipment, Plant Not Classified, Estimated Useful Life		1 year
Capital leases, net of accumulated amortization, Estimated Useful Life	[1]	1 year
Maximum
Utility Plant
Distribution plant, Estimated Useful Life		50 years
Production plant, Estimated Useful Life		125 years
Transmission plant, Estimated Useful Life		65 years
General plant, Estimated Useful Life		35 years
Intangible plant (including capitalized software), Estimated Useful Life		50 years
Plant acquisition adjustment, Estimated Useful Life		30 years
Underground storage, Estimated Useful Life		60 years
Liquefied natural gas storage, Estimated Useful Life		45 years
Public Utilities, Property, Plant and Equipment, Plant Not Classified, Estimated Useful Life		100 years
Capital leases, net of accumulated amortization, Estimated Useful Life	[1]	5 years
Subsidiaries [Member]
Utility Plant
Distribution plant		$ 6,417,551		6,127,732
Production plant		3,907,224		3,948,270
Transmission plant		1,306,009		1,162,929
General plant		553,130		599,156
Intangible plant (including capitalized software)		304,135		309,972
Plant acquisition adjustment		282,792		282,792
Underground storage		42,494		41,501
Liquefied natural gas storage		14,498		14,492
Plant held for future use		55,148		28,895
Recoverable cushion gas		8,655		8,655
Public Utilities, Property, Plant and Equipment, Other Property, Plant and Equipment		91,519		124,589
Public Utilities, Property, Plant and Equipment Grant		(105,659)		0
Capital leases, net of accumulated amortization	[1]	9,473		17,051
Less: Accumulated depreciation and amortization		(4,449,680)		(4,297,012)
Subtotal		8,437,289		8,369,022
Construction work in progress		239,690		310,318
Net utility plant		8,676,979		8,679,340
Accumulated amortization of capital leases		$ 28,400		$ 20,800
[1]	Accumulated amortization of capital leases at Puget Energy was $28.4 million in 2014 and $20.8 million in 2013. Accumulated amortization of capital leases at PSE was $28.4 million in 2014 and $20.8 million in 2013.

Utility Plant - Jointly Owned U

Utility Plant - Jointly Owned Utility Plant (Detail) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2013
Jointly Owned Utility Plant Interests
Asset Retirement Obligation, Liabilities Incurred		$ 0	$ 350
Colstrip Units 1 & 2
Jointly Owned Utility Plant Interests
Company's Ownership Share		50.00%
Plant in Service at Cost		$ 158,516
Accumulated Depreciation		$ (12,047)
Colstrip Units 3 & 4
Jointly Owned Utility Plant Interests
Company's Ownership Share		25.00%
Plant in Service at Cost		$ 234,787
Accumulated Depreciation		(28,763)
Colstrip Units 1 - 4 Common Facilities
Jointly Owned Utility Plant Interests
Plant in Service at Cost		83
Accumulated Depreciation		$ (21)
Frederickson 1
Jointly Owned Utility Plant Interests
Company's Ownership Share		49.85%
Plant in Service at Cost		$ 61,771
Accumulated Depreciation		$ (5,750)
Jackson Prairie [Member]
Jointly Owned Utility Plant Interests
Company's Ownership Share		33.34%
Plant in Service at Cost		$ 28,185
Accumulated Depreciation		(4,099)
Subsidiaries [Member]
Jointly Owned Utility Plant Interests
Asset Retirement Obligation, Liabilities Incurred	$ (3,696)
Subsidiaries [Member] | Colstrip Units 1 & 2
Jointly Owned Utility Plant Interests
Plant in Service at Cost		293,103
Accumulated Depreciation		(146,635)
Subsidiaries [Member] | Colstrip Units 3 & 4
Jointly Owned Utility Plant Interests
Plant in Service at Cost		509,619
Accumulated Depreciation		(303,594)
Subsidiaries [Member] | Colstrip Units 1 - 4 Common Facilities
Jointly Owned Utility Plant Interests
Plant in Service at Cost		252
Accumulated Depreciation		(189)
Subsidiaries [Member] | Frederickson 1
Jointly Owned Utility Plant Interests
Plant in Service at Cost		70,719
Accumulated Depreciation		(14,698)
Subsidiaries [Member] | Jackson Prairie [Member]
Jointly Owned Utility Plant Interests
Plant in Service at Cost		42,494
Accumulated Depreciation		$ (18,409)

Utility Plant - Asset Retiremen

Utility Plant - Asset Retirement Obligation (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of period	$ 48,687	$ 45,496
New asset retirement obligation recognized in the period	0	350
Liability settled in the period	(602)	(1,188)
Revisions in estimated cash flows	(480)	2,769
Accretion expense	1,304	1,260
Asset retirement obligation at end of period	$ 48,909	$ 48,687

Long-Term Debt (Schedule of Lon

Long-Term Debt (Schedule of Long-Term Debt Instruments) (Detail) - USD ($) $ in Thousands	May. 26, 2015	May. 12, 2015	Dec. 31, 2014	Jun. 29, 2014	Dec. 31, 2013	Feb. 28, 2009
Debt Instrument [Line Items]
Total PSE long-term debt		$ 400,000	$ 5,462,272	$ 299,100
Net PSE long-term debt			5,243,608		$ 5,232,476
Long Term Debt, Reconciliation, Fair Value Adjustment			(218,619)		(229,746)
Senior secured credit facility
Debt Instrument [Line Items]
Total PSE long-term debt					299,000
Term Loan
Debt Instrument [Line Items]
Total PSE long-term debt				$ 299,000		$ 1,225,000
Term Loan | Term Loan
Debt Instrument [Line Items]
Total PSE long-term debt			100,000
Term Loan | Term Loan series due 2017 [Member]
Debt Instrument [Line Items]
Total PSE long-term debt			100,000
Term Loan | Term Loanseriesdue 2016 [Member]
Debt Instrument [Line Items]
Total PSE long-term debt			99,000
Senior Secured Note
Debt Instrument [Line Items]
Unamortized discount on senior notes			(32)		(36)
Senior Secured Note | 6.500% Senior Secured Note Due 2020
Debt Instrument [Line Items]
Total PSE long-term debt			450,000		450,000
Senior Secured Note | 6.000% Senior Secured Note Due 2021
Debt Instrument [Line Items]
Total PSE long-term debt			500,000		500,000
Senior Secured Note | 5.625% Senior Secured Note Due 2022
Debt Instrument [Line Items]
Total PSE long-term debt			450,000		450,000
Subsidiaries [Member]
Debt Instrument [Line Items]
Stated interest rate percent	4.30%	3.65%
Total PSE long-term debt	$ 425,000		3,763,272
Unamortized discount on senior notes			(13)		(14)
Net PSE long-term debt			$ 3,763,259		3,763,258
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 7.350% Series Due 2015
Debt Instrument [Line Items]
Stated interest rate percent			7.35%
Total PSE long-term debt			$ 10,000		10,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 7.360% Series Due 2015
Debt Instrument [Line Items]
Stated interest rate percent			7.36%
Total PSE long-term debt			$ 2,000		2,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 5.197% Series Due 2015
Debt Instrument [Line Items]
Stated interest rate percent			5.197%
Total PSE long-term debt			$ 150,000		150,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 6.750% Series Due 2016
Debt Instrument [Line Items]
Stated interest rate percent			6.75%
Total PSE long-term debt			$ 250,000		250,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 5.500% Secured Promissory Note Due 2017
Debt Instrument [Line Items]
Stated interest rate percent			5.50%
Total PSE long-term debt			$ 2,412		2,412
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 6.740% Series Due 2018
Debt Instrument [Line Items]
Stated interest rate percent			6.74%
Total PSE long-term debt			$ 200,000		200,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 7.150% Series Due 2025
Debt Instrument [Line Items]
Stated interest rate percent			7.15%
Total PSE long-term debt			$ 15,000		15,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 7.200% Series Due 2025
Debt Instrument [Line Items]
Stated interest rate percent			7.20%
Total PSE long-term debt			$ 2,000		2,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 7.020% Series Due 2027
Debt Instrument [Line Items]
Stated interest rate percent			7.02%
Total PSE long-term debt			$ 300,000		300,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 7.000% Series Due 2029
Debt Instrument [Line Items]
Stated interest rate percent			7.00%
Total PSE long-term debt			$ 100,000		100,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 3.900% Series Due 2031
Debt Instrument [Line Items]
Stated interest rate percent			3.90%
Total PSE long-term debt			$ 138,460		138,460
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 4.000% Series Due 2031
Debt Instrument [Line Items]
Stated interest rate percent			4.00%
Total PSE long-term debt			$ 23,400		23,400
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 5.483% Series Due 2035
Debt Instrument [Line Items]
Stated interest rate percent			5.483%
Total PSE long-term debt			$ 250,000		250,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 6.724% Series Due 2036
Debt Instrument [Line Items]
Stated interest rate percent			6.724%
Total PSE long-term debt			$ 250,000		250,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 6.274% Series Due 2037
Debt Instrument [Line Items]
Stated interest rate percent			6.274%
Total PSE long-term debt			$ 300,000		300,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 5.757% Series Due 2039
Debt Instrument [Line Items]
Stated interest rate percent			5.757%
Total PSE long-term debt			$ 350,000		350,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 5.795% Series Due 2040
Debt Instrument [Line Items]
Stated interest rate percent			5.795%
Total PSE long-term debt			$ 325,000		325,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 5.764% Series Due 2040
Debt Instrument [Line Items]
Stated interest rate percent			5.764%
Total PSE long-term debt			$ 250,000		250,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 4.434% Series Due 2041
Debt Instrument [Line Items]
Stated interest rate percent			4.434%
Total PSE long-term debt			$ 250,000		250,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 5.638% Series Due 2041
Debt Instrument [Line Items]
Stated interest rate percent			5.638%
Total PSE long-term debt			$ 300,000		300,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 4.700% Series Due 2051
Debt Instrument [Line Items]
Stated interest rate percent			4.70%
Total PSE long-term debt			$ 45,000		45,000
Subsidiaries [Member] | Senior Notes and First Mortgage Bonds | 6.974% Series Due 2067
Debt Instrument [Line Items]
Stated interest rate percent			6.974%
Total PSE long-term debt			$ 250,000		$ 250,000
Subsidiaries [Member] | Junior Subordinated Notes | 6.500% Senior Secured Note Due 2020
Debt Instrument [Line Items]
Stated interest rate percent			6.50%
Subsidiaries [Member] | Junior Subordinated Notes | 6.000% Senior Secured Note Due 2021
Debt Instrument [Line Items]
Stated interest rate percent			6.00%
Subsidiaries [Member] | Junior Subordinated Notes | 5.625% Senior Secured Note Due 2022
Debt Instrument [Line Items]
Stated interest rate percent			5.625%

Long-Term Debt (Narrative) (Det

Long-Term Debt (Narrative) (Detail) - USD ($)	Dec. 06, 2010	Jun. 30, 2014	Dec. 31, 2014	May. 26, 2015	May. 12, 2015	Jun. 29, 2014	Dec. 31, 2013	May. 23, 2013	Feb. 10, 2012	Feb. 28, 2009
Debt Instrument [Line Items]
Current borrowing capacity of line of credit									$ 1,000,000,000
Long-term debt			$ 5,462,272,000		$ 400,000,000	$ 299,100,000
Debt Instrument, Term		3 years
Maximum borrowing capacity			1,300,000,000
Senior secured credit facility
Debt Instrument [Line Items]
Long-term debt							$ 299,000,000
Debt Instrument, Term	5 years
Capital Expenditure Facility
Debt Instrument [Line Items]
Current borrowing capacity of line of credit										$ 1,000,000,000
Term Loan
Debt Instrument [Line Items]
Long-term debt						$ 299,000,000				$ 1,225,000,000
Debt Instrument, Term	5 years	2 years
Revolving Credit Facility
Debt Instrument [Line Items]
Current borrowing capacity of line of credit									$ 800,000,000
Subsidiaries [Member]
Debt Instrument [Line Items]
Current borrowing capacity of line of credit			1,000,000,000
Stated interest rate percent				4.30%	3.65%
Long-term debt			3,763,272,000	$ 425,000,000
Maximum borrowing capacity			1,450,000,000
Subsidiaries [Member] | Pollution Control Bonds
Debt Instrument [Line Items]
Current borrowing capacity of line of credit								$ 161,900,000
Subsidiaries [Member] | Pollution Control Bonds | 5.010% Series Due 2031
Debt Instrument [Line Items]
Stated interest rate percent								5.01%
Subsidiaries [Member] | Pollution Control Bonds | 3.910% Series Due 2031
Debt Instrument [Line Items]
Stated interest rate percent								3.91%
Puget Energy | Pollution Control Bonds
Debt Instrument [Line Items]
Liabilities and Equity, Fair Value Adjustment			$ 18,000,000

Long-Term Debt (Schedule of Mat

Long-Term Debt (Schedule of Maturities of Long-Term Debt) (Detail) - USD ($) $ in Thousands	May. 26, 2015	May. 12, 2015	Dec. 31, 2014	Jun. 29, 2014
Maturities of Long-term Debt [Abstract]
2,015			$ 162,000
2,016			449,000
2,017			102,412
2,018			200,000
2,019			0
Thereafter			4,548,860
Total		$ 400,000	5,462,272	$ 299,100
Subsidiaries [Member]
Maturities of Long-term Debt [Abstract]
2,015			162,000
2,016			250,000
2,017			2,412
2,018			200,000
2,019			0
Thereafter			3,148,860
Total	$ 425,000		3,763,272
Parent Company [Member]
Maturities of Long-term Debt [Abstract]
2,015			0
2,016			199,000
2,017			100,000
2,018			0
2,019			0
Thereafter			1,400,000
Total			$ 1,699,000

Liquidity Facilities and Othe59

Liquidity Facilities and Other Financing Arrangements (Detail) - USD ($)	Feb. 10, 2012	Dec. 31, 2014	Sep. 30, 2015	Dec. 31, 2013	Dec. 31, 2012
Short-term Debt [Line Items]
Short-term debt		$ 85,000,000	$ 79,500,000	$ 162,000,000
Current borrowing capacity of line of credit	$ 1,000,000,000
Maximum borrowing capacity		1,300,000,000
Energy Hedging Activities [Member]
Short-term Debt [Line Items]
Current borrowing capacity of line of credit		$ 350,000,000
Revolving Credit Facility
Short-term Debt [Line Items]
Current borrowing capacity of line of credit	$ 800,000,000
Basis spread on variable rate (percent)		1.75%
Commitment fee percentage for line of credit	0.275%
Subsidiaries [Member]
Short-term Debt [Line Items]
Short-term debt		$ 85,000,000		$ 162,000,000
Weighted-average interest rate on short-term debt (percent)		4.05%			3.93%
Current borrowing capacity of line of credit		$ 1,000,000,000
Current same-day borrowing capacity		75,000,000
Maximum borrowing capacity		$ 1,450,000,000
Maximum capitalization percentage		65.00%
Derivative, Basis Spread on Variable Rate		1.25%
Line of Credit, Unused Capacity, Commitment Fee Percentage		0.175%
Subsidiaries [Member] | Affiliated Entity [Member]
Short-term Debt [Line Items]
Outstanding amount for line of credit		$ 28,900,000
Subsidiaries [Member] | Senior secured credit facility | Affiliated Entity [Member]
Short-term Debt [Line Items]
Current borrowing capacity of line of credit		$ 30,000,000
Basis spread on variable rate (percent)		One-month LIBOR
Basis spread on variable rate (percent)		0.25%
Subsidiaries [Member] | Working Capital Needs
Short-term Debt [Line Items]
Current borrowing capacity of line of credit		$ 650,000,000
Subsidiaries [Member] | Working Capital Needs | Letter of Credit
Short-term Debt [Line Items]
Current borrowing capacity of line of credit		4,200,000
Outstanding amount for line of credit		85,000,000
Subsidiaries [Member] | Energy Hedging Activities [Member]
Short-term Debt [Line Items]
Current borrowing capacity of line of credit		350,000,000
Outstanding amount for line of credit		$ 1,000,000

Leases (Schedule of Operating L

Leases (Schedule of Operating Lease Expense) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Subsidiaries [Member]
Operating Leases, Rent Expense, Net [Abstract]
Operating lease expense net of sublease receipts	$ 30,737	$ 29,392	$ 29,661

Leases (Schedule of Future Mini

Leases (Schedule of Future Minimum Lease Payments for Non-cancellable Leases) (Detail) - Subsidiaries [Member] $ in Thousands	Dec. 31, 2014USD ($)
Operating
2,015	$ 17,677
2,016	21,454
2,017	22,179
2,018	20,423
2,019	15,180
Thereafter	120,791
Total minimum lease payments	217,704
Capital
2,015	8,160
2,016	2,178
2,017	0
2,018	0
2,019	0
Thereafter	0
Total minimum lease payments	$ 10,338

Accounting for Derivative Ins62

Accounting for Derivative Instruments and Hedging Activities Derivative Activity and Notional Amounts (Detail) MWh in Millions, MMBTU in Millions, $ in Millions		Sep. 30, 2015USD ($)MMBTUMWhContract		Dec. 31, 2014USD ($)MMBTUMWh		Dec. 31, 2013USD ($)MMBTUMWh
Interest Rate Swap [Member] | Parent Company [Member]
Derivative [Line Items]
Number of Interest Rate Derivatives Held		2		2
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount | $	[1]	$ 450		$ 450		$ 450
Not Designated as Hedging Instrument [Member] | Natural Gas Derivatives [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary		345.6	[2]	360.4	[2],[3]	423.5	[3]
Not Designated as Hedging Instrument [Member] | Electric generation fuel [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary		175.1		140.2		145.6
Not Designated as Hedging Instrument [Member] | Purchased Electricity [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary | MWh		1.1		5.4		8.6
[1]	Interest rate swap contracts are only held at Puget Energy.
[2]	All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, "Regulated Operations," due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.
[3]	PSE had a net derivative liability and an offsetting regulatory asset of $69.3 million at December 31, 2014 and $27.6 million at December 31, 2013 related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, due to the PGA mechanism.

Accounting for Derivative Ins63

Accounting for Derivative Instruments and Hedging Activities Derivative Assets and Liabilities (Detail) - USD ($) $ in Thousands		Sep. 30, 2015		Dec. 31, 2014		Dec. 31, 2013
Derivative [Line Items]
Assets, Current		$ 18,771		$ 21,178		$ 18,867
Assets, Long-term		3,309		3,170		7,733
Liabilities, Current		133,061		142,195		48,049
Liabilities, Long-term		55,602		62,913		38,162
Commodity Contract [Member]
Derivative [Line Items]
Derivative Assets		22,080	[1]	24,348	[1]	26,600
Derivative Liability		181,041		196,035		72,988
Natural gas portfolio [Member]
Derivative [Line Items]
Offsetting regulatory assets				69,300		27,600
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Assets		22,080	[1]	24,348	[1],[2]	26,600	[2]
Derivative Liability		188,663	[3]	205,108	[3],[4]	86,211	[4]
Not Designated as Hedging Instrument [Member] | Parent Company [Member]
Derivative [Line Items]
Assets, Current		18,771	[1]	21,178	[1],[2]	18,867	[2]
Assets, Long-term		3,309	[1]	3,170	[1],[2]	7,733	[2]
Liabilities, Current		133,061	[3]	142,195	[3],[4]	48,049	[4]
Liabilities, Long-term		55,602	[3]	62,913	[3],[4]	38,162	[4]
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative Assets	[5]	0	[1]	0	[1],[2]	0	[2]
Derivative Liability	[5]	7,622	[3]	9,073	[3],[4]	13,223	[4]
Not Designated as Hedging Instrument [Member] | Electric portfolio [Member]
Derivative [Line Items]
Derivative Assets		15,916	[1],[6]	4,822	[1],[2],[6],[7]	18,479	[2],[7]
Derivative Liability		111,472	[3],[6]	107,228	[3],[4],[6],[7]	37,312	[4],[7]
Not Designated as Hedging Instrument [Member] | Natural gas portfolio [Member]
Derivative [Line Items]
Derivative Assets		6,164	[1],[8]	19,526	[1],[2],[8],[9]	8,121	[2],[9]
Derivative Liability		$ 69,569	[3],[8]	$ 88,807	[3],[4],[8],[9]	$ 35,676	[4],[9]
[1]	Balance sheet locations: Current and Long-term Unrealized gain on derivative instruments.
[2]	Balance sheet location: Current and Long-term Unrealized gain on derivative instruments.
[3]	Balance sheet locations: Current and Long-term Unrealized loss on derivative instruments.
[4]	Balance sheet location: Current and Long-term Unrealized loss on derivative instruments.
[5]	Interest rate swap contracts are only held at Puget Energy.
[6]	Electric portfolio derivatives consist of electric generation fuel of 175.1 million One Million British Thermal Units (MMBtu) and purchased electricity of 1.1 million Megawatt Hours (MWhs) at September 30, 2015, and 140.2 million MMBtus and 5.4 million MWhs at December 31, 2014.
[7]	Electric portfolio derivatives consist of electric generation fuel of 140.2 million One Million British Thermal Units (MMBtus) and purchased electricity of 5.4 million Megawatt Hours (MWhs) at December 31, 2014 and 145.6 million MMBtus and 8.6 million MWhs at December 31, 2013.
[8]	All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, "Regulated Operations," due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.
[9]	PSE had a net derivative liability and an offsetting regulatory asset of $69.3 million at December 31, 2014 and $27.6 million at December 31, 2013 related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, due to the PGA mechanism.

Accounting for Derivative Ins64

Accounting for Derivative Instruments and Hedging Activities Net Amount of Derivatives Reported in the Statement of Financial Position (Detail) - USD ($) $ in Thousands		Sep. 30, 2015		Dec. 31, 2014		Dec. 31, 2013
Commodity Contract [Member]
Assets:
Derivative Asset, Fair Value, Gross Asset		$ 22,080	[1]	$ 24,348	[2]	$ 26,600	[2]
Derivative Asset, Collateral, Obligation to Return Cash, Offset		0		0		0
Total derivative assets		22,080	[3]	24,348	[3]	26,600
Derivative, Collateral, Obligation to Return Securities		(18,416)		(23,066)		(19,491)
Derivative, Collateral, Obligation to Return Cash		0		0		0
Derivative Asset, Fair Value, Amount Offset Against Collateral		3,664		1,282		7,109
Liabilities:
Derivative Liability, Fair Value, Gross Liability		181,041	[1]	196,035	[2]	72,988	[2]
Derivative Liability, Collateral, Right to Reclaim Cash, Offset		0		0		0
Total derivative liabilities		181,041		196,035		72,988
Derivative, Collateral, Right to Reclaim Securities		(18,416)		(23,066)		(19,491)
Derivative, Collateral, Right to Reclaim Cash		0		(20)		0
Derivative Liability, Fair Value, Amount Offset Against Collateral		162,625		172,949		53,497
Interest Rate Contract [Member]
Liabilities:
Derivative Liability, Fair Value, Gross Liability	[4]	7,622	[1]	9,073	[2]	13,223	[2]
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	[4]	0		0		0
Total derivative liabilities	[4]	7,622		9,073		13,223
Derivative, Collateral, Right to Reclaim Securities	[4]	0		0		0
Derivative, Collateral, Right to Reclaim Cash	[4]	0		0		0
Derivative Liability, Fair Value, Amount Offset Against Collateral	[4]	$ 7,622		$ 9,073		$ 13,223
[1]	All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off.
[2]	All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of Offset.
[3]	Balance sheet locations: Current and Long-term Unrealized gain on derivative instruments.
[4]	Interest rate swap contracts are only held at Puget Energy.

Accounting for Derivative Ins65

Accounting for Derivative Instruments and Hedging Activities Recognized in Statement of Income (Detail) - USD ($) $ in Thousands	3 Months Ended				9 Months Ended				12 Months Ended
	Sep. 30, 2015		Sep. 30, 2014		Sep. 30, 2015		Sep. 30, 2014		Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized (gain) loss on derivative instruments	$ (5,588)		$ (32,648)		$ 6,339		$ (7,714)		$ (84,146)		$ 102,744		$ 133,606
Derivative contracts classified as financing activities due to merger					(8,045)		(8,026)		(16,349)		(34,250)		(92,681)
Parent Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Amount Not Designated as Normal Purchase, Normal Sale													2,200
Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized (gain) loss on derivative instruments	(26,856)		(31,178)		(59,673)		1,212		(85,262)		33,953		(107,921)
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other Income (Deductions) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized (gain) loss on derivative instruments	(1,156)		(323)		(4,571)		(2,430)		(3,915)		2,420		(4,288)
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized (gain) loss on derivative instruments	0		1,241		560		398		500		(5,904)		(29,727)
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized (gain) loss on derivative instruments	(5,588)	[1]	(32,648)	[1]	6,339	[1]	(7,714)	[1]	(84,146)	[2]	102,744	[2]	131,407	[2]
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Electric generation fuel [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized (gain) loss on derivative instruments	(11,768)		(420)		(27,512)		8,271		6,511		(27,008)		(66,762)
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Purchased Electricity [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized (gain) loss on derivative instruments	(8,344)		972		(34,489)		2,687		(4,212)		(38,299)		(138,551)
Not Designated as Hedging Instrument [Member] | Subsidiaries [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized (gain) loss on derivative instruments	(25,700)		(32,096)		(56,206)		2,674		(83,337)		33,573		(86,193)
Not Designated as Hedging Instrument [Member] | Subsidiaries [Member] | Commodity Contract [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized (gain) loss on derivative instruments	(5,588)	[1]	(32,648)	[1]	5,795	[1]	(8,284)	[1]	(85,636)		98,880		119,120
Not Designated as Hedging Instrument [Member] | Subsidiaries [Member] | Commodity Contract [Member] | Electric generation fuel [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized (gain) loss on derivative instruments	(11,768)		(420)		(27,512)		8,271		6,511		(27,008)		(66,762)
Not Designated as Hedging Instrument [Member] | Subsidiaries [Member] | Commodity Contract [Member] | Purchased Electricity [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized (gain) loss on derivative instruments	$ (8,344)		$ 972		$ (34,489)		$ 2,687		$ (4,212)		$ (38,299)		$ (138,551)
[1]	Differences between Puget Energy and PSE for the nine months ending September 30, 2015 and September 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.
[2]	For 2012, the amount differs from the amount stated in the statement of income as it does not include amortization related to contracts that were recorded at fair value at the time of the February 2009 merger and subsequently designated as NPNS of $2.2 million for the year ended December 31, 2012.

Accounting for Derivative Ins66

Accounting for Derivative Instruments and Hedging Activities Recognized in Other Comprehensive Income (Detail) - USD ($) $ in Thousands	3 Months Ended				9 Months Ended				12 Months Ended
	Sep. 30, 2015		Sep. 30, 2014		Sep. 30, 2015		Sep. 30, 2014		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months									$ (500)
Subsidiaries [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months					$ 500				(1,100)
Cash Flow Hedging [Member] | Subsidiaries [Member] | Interest Expense [Member] | Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship	$ (122)	[1]	$ (122)	[1]	(366)	[1]	$ (366)	[1]	(488)	$ (488)	$ (488)
Cash Flow Hedging [Member] | Subsidiaries [Member] | Electric generation fuel [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship									0	0	97
Cash Flow Hedging [Member] | Subsidiaries [Member] | Purchased Electricity [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship	0		0		(1,055)		(1,104)		(2,063)	(3,922)	(12,955)
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)		(716)	(4,562)	(18,382)
Other Comprehensive Income (Loss) [Member] | Cash Flow Hedging [Member] | Parent Company [Member] | Interest Expense [Member] | Interest Rate Swap [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)		(144)	(4,505)	(17,811)
Other Comprehensive Income (Loss) [Member] | Cash Flow Hedging [Member] | Parent Company [Member] | Electric generation fuel [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship									0	0	100
Other Comprehensive Income (Loss) [Member] | Cash Flow Hedging [Member] | Parent Company [Member] | Purchased Electricity [Member] | Energy Related Derivative [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)		(534)		(572)	(57)	(671)
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)		$ (1,421)		$ (1,470)		$ (2,551)	$ (4,410)	$ (13,346)
[1]	Within the next twelve months, $0.5 million of losses in AOCI will be reclassified into earnings.

Accounting for Derivative Ins67

Accounting for Derivative Instruments and Hedging Activities Contractual Contingent Liability (Detail) - USD ($) $ in Thousands		Sep. 30, 2015	Dec. 31, 2014
Electric portfolio [Member]
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value			$ 0
Fair Value Liability	[1]	$ 94,145	(106,356)
Additional Collateral, Aggregate Fair Value		$ 27,360	$ 37,398
Electric portfolio [Member] | External Credit Rating, Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage		99.80%	99.30%
Electric portfolio [Member] | External Credit Rating, Non Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage		0.20%	0.70%
Electric portfolio [Member] | Credit Rating [Member]
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	[2]		$ 0
Fair Value Liability	[1],[2]	$ 27,360	(37,398)
Additional Collateral, Aggregate Fair Value	[2]	27,360	37,398
Electric portfolio [Member] | Requested credit for adequate assurance [Member]
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value			0
Fair Value Liability	[1]	66,785	(66,468)
Additional Collateral, Aggregate Fair Value			0
Electric portfolio [Member] | Forward Value Of Contract [Member]
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	[3]		0
Fair Value Liability	[1],[3]		(2,490)
Additional Collateral, Aggregate Fair Value	[3]		0
Natural gas portfolio [Member] | Credit Rating [Member]
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value		$ 1,000	$ 1,000
[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 - Asset

Fair Value Measurements - Assets and Liabilities With Estimated Fair Value (Detail) - Carrying Value [Member] - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2013
Parent Company [Member]
Assets:
Cash and Cash Equivalents	$ 20,200	$ 37,527	$ 44,302
Restricted Cash	7,036	32,863	7,171
Notes receivable and other investments	50,294	53,503	53,449
Total assets	77,530	123,893	104,922
Liabilities:
Short-term Debt	79,500	85,000	162,000
Total liabilities	79,500	85,000	162,000
Parent Company [Member] | Level 1 [Member]
Assets:
Cash and Cash Equivalents	20,200	37,527	44,302
Restricted Cash	7,036	32,863	7,171
Notes receivable and other investments	0	0
Total assets	27,236	70,390	51,473
Liabilities:
Short-term Debt	79,500	85,000	162,000
Total liabilities	79,500	85,000	162,000
Parent Company [Member] | Level 2 [Member]
Assets:
Cash and Cash Equivalents	0	0
Restricted Cash	0	0
Notes receivable and other investments	50,294	53,503	53,449
Total assets	50,294	53,503	53,449
Liabilities:
Short-term Debt	0	0
Total liabilities	0	0
Subsidiaries [Member]
Assets:
Cash and Cash Equivalents	19,419	37,466	44,111
Restricted Cash	7,036	32,863	7,171
Notes receivable and other investments	50,294	53,503	53,449
Total assets	76,749	123,832	104,731
Liabilities:
Short-term Debt	79,500	85,000	162,000
Short-term debt owed to parent	0	28,933	29,598
Total liabilities	79,500	113,933	191,598
Subsidiaries [Member] | Level 1 [Member]
Assets:
Cash and Cash Equivalents	19,419	37,466	44,111
Restricted Cash	7,036	32,863	7,171
Notes receivable and other investments	0	0	0
Total assets	26,455	70,329	51,282
Liabilities:
Short-term Debt	79,500	85,000	162,000
Short-term debt owed to parent	0	0	0
Total liabilities	79,500	85,000	162,000
Subsidiaries [Member] | Level 2 [Member]
Assets:
Cash and Cash Equivalents	0	0	0
Restricted Cash	0	0	0
Notes receivable and other investments	50,294	53,503	53,449
Total assets	50,294	53,503	53,449
Liabilities:
Short-term Debt	0	0	0
Short-term debt owed to parent	0	28,933	29,598
Total liabilities	$ 0	$ 28,933	$ 29,598

Fair Value Measurements Debt at

Fair Value Measurements Debt at at Carrying and Fair Value (Detail) - Discounted cash flow [Member] - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2013
Carrying Value [Member] | Parent Company [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	$ 5,363,717	$ 5,243,608	$ 5,232,476
Carrying Value [Member] | Parent Company [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes	250,000	250,000	250,000
Long-term debt (fixed-rate), net of discount	5,113,717	4,694,608	4,683,476
Long-term debt (variable-rate)	0	299,000	299,000
Carrying Value [Member] | Subsidiaries [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	3,774,369	3,763,259	3,763,258
Carrying Value [Member] | Subsidiaries [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes	250,000	250,000	250,000
Long-term debt (fixed-rate), net of discount	3,524,369	3,513,259	3,513,258
Fair Value [Member] | Parent Company [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	6,634,816	6,658,789	6,162,680
Fair Value [Member] | Parent Company [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes	269,915	276,235	269,366
Long-term debt (fixed-rate), net of discount	6,364,901	6,083,554	5,594,314
Long-term debt (variable-rate)	0	299,000	299,000
Fair Value [Member] | Subsidiaries [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	4,628,879	4,713,708	4,307,821
Fair Value [Member] | Subsidiaries [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes	269,915	276,235	269,366
Long-term debt (fixed-rate), net of discount	$ 4,358,964	$ 4,437,473	$ 4,038,455

Fair Value Measurements - Ass70

Fair Value Measurements - Assets and Liabilities Measured on Recurring Basis (Detail) - USD ($) $ in Thousands		3 Months Ended				9 Months Ended				12 Months Ended
		Sep. 30, 2015		Sep. 30, 2014		Sep. 30, 2015		Sep. 30, 2014		Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Balance at beginning of period		$ (14,547)		$ (4,966)		$ (14,100)		$ (15,782)		$ (15,782)		$ (35,526)		$ (95,352)
Included in earnings		(1,403)	[1]	(3,116)	[1]	(10,505)	[2]	1,939	[2]	(5,537)	[3]	(10,491)	[3]	(21,362)	[3]
Included in regulatory assets/liabilities		1,295		(725)		4,233		1,654		1,630		(945)		(1,937)
Settlements	[4]	(1,105)		(1,645)		(1,238)		(142)		(498)		10,855		60,102
Transferred into Level 3		0		2,055		(787)		4,570		4,570		(7,799)		(55,845)
Transferred out of Level 3		2,938		(6,548)		9,575		(7,184)		1,515		28,124		78,868
Balance at end of period		(12,822)		(14,945)		(12,822)		(14,945)		(14,100)		(15,782)		(35,526)
Scenario, Previously Reported [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Balance at beginning of period						(14,102)
Balance at end of period										(14,102)
Electric portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Balance at beginning of period		(15,370)		(4,693)		(12,061)		(15,421)		(15,421)		(33,924)		(90,311)
Included in earnings		(1,403)	[1]	(3,116)	[1]	(10,505)	[2]	1,939	[2]	(5,537)	[3]	(10,491)	[3]	(21,362)	[3]
Included in regulatory assets/liabilities		0		0		0		0		0		0		0
Settlements	[4]	1,017		(965)		1,182		1,114		1,036		11,609		59,133
Transferred into Level 3		0		2,055		(787)		5,155		5,155		(7,799)		(55,548)
Transferred out of Level 3		3,314		(6,488)		9,729		(5,994)		2,705		25,184		74,164
Balance at end of period		(12,442)		(13,207)		(12,442)		(13,207)		(12,061)		(15,421)		(33,924)
Unrealized Gain (Loss) on Derivatives and Commodity Contracts		(1,500)		(3,300)		(10,400)		(3,300)		(9,600)		(13,400)		(15,200)
Electric portfolio [Member] | Scenario, Previously Reported [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Balance at beginning of period						(12,062)
Balance at end of period										(12,062)
Natural gas portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Balance at beginning of period		823		(273)		(2,039)		(361)		(361)		(1,602)		(5,041)
Included in earnings		0	[1]	0	[1]	0	[2]	0	[2]	0	[3]	0	[3]	0	[3]
Included in regulatory assets/liabilities		1,295		(725)		4,233		1,654		1,630		(945)		(1,937)
Settlements	[4]	(2,122)		(680)		(2,420)		(1,256)		(1,534)		(754)		969
Transferred into Level 3		0		0		0		(585)		(585)		0		(297)
Transferred out of Level 3		(376)		(60)		(154)		(1,190)		(1,190)		2,940		4,704
Balance at end of period		(380)		$ (1,738)		(380)		$ (1,738)		(2,039)		(361)		$ (1,602)
Natural gas portfolio [Member] | Scenario, Previously Reported [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Balance at beginning of period						(2,040)
Balance at end of period										(2,040)
Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities	[5]	7,622				7,622				9,073		13,223
Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		181,041				181,041				196,035		72,988
Derivative Assets		22,080	[6]			22,080	[6]			24,348	[6]	26,600
Fair Value, Measurements, Recurring | Parent Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		7,622				7,622				9,073
Fair Value, Measurements, Recurring | Parent Company [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		7,622				7,622				9,073
Fair Value, Measurements, Recurring | Parent Company [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		7,622				7,622				9,073		13,223
Fair Value, Measurements, Recurring | Parent Company [Member] | Level 2 [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		7,622				7,622				9,073		13,223
Fair Value, Measurements, Recurring | Parent Company [Member] | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		0				0				0		0
Fair Value, Measurements, Recurring | Parent Company [Member] | Level 3 | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		0				0				0		0
Fair Value, Measurements, Recurring | Parent Company [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities										9,073		13,223
Fair Value, Measurements, Recurring | Parent Company [Member] | Fair Value [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities										9,073		13,223
Fair Value, Measurements, Recurring | Subsidiaries [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		181,041				181,041				196,035
Derivative Assets		22,080				22,080				24,348
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Commodity Contract [Member] | Electric portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		111,472				111,472				107,228
Derivative Assets		15,916				15,916				4,822
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Commodity Contract [Member] | Natural gas portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		69,569				69,569				88,807
Derivative Assets		6,164				6,164				19,526
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		159,043				159,043				177,303
Derivative Assets		12,904				12,904				19,718
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Level 2 [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities										177,303		50,715
Derivative Assets										19,718		20,109
Fair Value, Measurements, Recurring | 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 Liabilities		92,483				92,483				91,998		18,073
Derivative Assets		9,369				9,369				1,654		14,661
Fair Value, Measurements, Recurring | 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 Liabilities		66,560				66,560				85,305		32,642
Derivative Assets		3,535				3,535				18,064		5,448
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		21,998				21,998				18,732
Derivative Assets		9,176				9,176				4,630
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Level 3 | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities										18,732		22,273
Derivative Assets										4,630		6,491
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Level 3 | Commodity Contract [Member] | Electric portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		18,989				18,989				15,230		19,239
Derivative Assets		6,547				6,547				3,168		3,818
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Level 3 | Commodity Contract [Member] | Natural gas portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities		3,009				3,009				3,502		3,034
Derivative Assets		$ 2,629				$ 2,629				1,462		2,673
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities										196,035		72,988
Derivative Assets										24,348		26,600
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Fair Value [Member] | Electric portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities										107,228		37,312
Derivative Assets										4,822		18,479
Fair Value, Measurements, Recurring | Subsidiaries [Member] | Fair Value [Member] | Natural gas portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liabilities										88,807		35,676
Derivative Assets										$ 19,526		$ 8,121
[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 $(1.5) million and $(3.3) million for the three months ended September 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 $(10.4) million and $(3.3) million for the nine months ended September 30, 2015 and 2014, respectively.
[3]	Income Statement location: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $(9.6) million, $(13.4) million, and $(15.2) million for the years ended December 31, 2014, 2013 and 2012, respectively.
[4]	The Company had no purchases, sales or issuances during the reported periods.
[5]	Interest rate swap contracts are only held at Puget Energy.
[6]	Balance sheet locations: Current and Long-term Unrealized gain on derivative instruments.

Fair Value Measurements Valuati

Fair Value Measurements Valuation Techniques for Measurement with Unobservable Inputs (Detail) $ in Thousands	6 Months Ended	9 Months Ended	12 Months Ended
	Jun. 30, 2013USD ($)$ / MWh	Sep. 30, 2015USD ($)$ / MWh	Dec. 31, 2014USD ($)$ / MWh$ / MMBTU	Dec. 31, 2013$ / MWh$ / MMBTU	Dec. 31, 2012$ / MWh$ / MMBTU	Jul. 01, 2013USD ($)	Mar. 31, 2012USD ($)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value measurement, sensitivity analysis, hypothetical increase or decrease of market prices, result on fair value		10.00%	10.00%
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value		$ 300	$ (3,900)
Finite-lived Intangible Assets, Fair Value Disclosure			437,600			$ 484,100
Impairment of Intangible Assets (Excluding Goodwill)		$ 6,700
Fair Value Inputs, Comparability Adjustments		11.00%
Carrying Value [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure		$ 35,700	$ 62,100
Finite-Lived Intangible Assets, Net						33,600
Portion at Fair Value Measurement [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure							$ 3,200
Finite-Lived Intangible Assets, Net						13,500
Priest Rapids Development
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-Lived Intangible Assets, Net						$ 47,100
Wells Project
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-Lived Intangible Assets, Net		$ 42,400
Minimum | Discounted cash flow [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh	30.85	18.38	19.30
Fair Value Inputs, Power Contract Costs	$ 389	$ 4,100	$ 3,015
Minimum | Discounted cash flow [Member] | Electric portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh		13.39	21.79
Minimum | Discounted cash flow [Member] | Natural gas portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MMBtu)		1.56	3.11
Maximum | Discounted cash flow [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh	65.35	27.92	37.06
Fair Value Inputs, Power Contract Costs	$ 6,845	$ 4,659	$ 4,783
Maximum | Discounted cash flow [Member] | Electric portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh		30.06	35.46	35.46
Maximum | Discounted cash flow [Member] | Natural gas portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MMBtu)		3.13	3.83	3.83
Weighted Average [Member] | Discounted cash flow [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh	48.47	24.88	29.53
Fair Value Inputs, Power Contract Costs	$ 4,110	$ 4,388	$ 4,469
Weighted Average [Member] | Discounted cash flow [Member] | Electric portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value Inputs, Price Per Megawatt-Hour | $ / MWh		24.05	32.89		32.89
Weighted Average [Member] | Discounted cash flow [Member] | Natural gas portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MMBtu)		2.40	3.28		3.28

Employee Investment Plans (Deta

Employee Investment Plans (Detail) - Subsidiaries [Member] - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Sep. 30, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Contribution Plan
Employer discretionary contribution amount			$ 14.9	$ 14.6	$ 14.5
Employer matching contribution, percent	1.00%	1.00%	4.00%
6 percent
Defined Contribution Plan
Employer matching contribution, percent			4.50%
Maximum annual contribution per employee, percent			6.00%
Cash Balance Formula
Defined Contribution Plan
Employer matching contribution, percent			100.00%
Maximum annual contribution per employee, percent			6.00%
Employer additional contribution of base pay, percentage			1.00%
Cash Balance Formula | First 3 Percent
Defined Contribution Plan
Employer matching contribution, percent			100.00%
Maximum annual contribution per employee, percent			3.00%
Cash Balance Formula | Second 3 Percent
Defined Contribution Plan
Employer matching contribution, percent			50.00%
Maximum annual contribution per employee, percent			3.00%
Final Average Earnings Formula
Defined Contribution Plan
Employer matching contribution, percent			55.00%
Maximum annual contribution per employee, percent			6.00%

Retirement Benefits Activity (D

Retirement Benefits Activity (Detail) - USD ($)	3 Months Ended		9 Months Ended	12 Months Ended
	Sep. 30, 2015	Mar. 31, 2014	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2013
Qualified Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension and Other Postretirement Benefit Plans, Net Prior Service Cost or Credit, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year				$ 0.039
Aggregate expected contributions			$ 18,000,000
Company Contribution	$ 4,500,000		13,500,000	18,000,000	$ 20,400,000
SERP Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Net Gain (Loss)				0.016
Company Contribution				1,938,000	6,850,000
Other Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			400,000
Company Contribution	100,000		500,000	$ 488,000	$ 908,000
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions			4,400,000
Company Contribution	$ 500,000		$ 3,000,000
Subsidiaries [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent	1.00%	1.00%		4.00%
Subsidiaries [Member] | Scenario, Forecast [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent			4.00%
Subsidiaries [Member] | Qualified Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension and Other Postretirement Benefit Plans, Net Prior Service Cost or Credit, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year				$ 1,600,000
Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Net Gain (Loss)				20,500,000
Aggregate expected contributions				18,000,000
Subsidiaries [Member] | SERP Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Net Gain (Loss)				2,100,000
Aggregate expected contributions				4,400,000
Subsidiaries [Member] | Other Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Net Gain (Loss)				300,000
Aggregate expected contributions				$ 500,000

Retirement Benefits - Change in

Retirement Benefits - Change in Net Benefit Obligation (Detail) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2013
Qualified Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period		$ 690,194	$ 573,317	$ 616,290
Service cost		15,966	17,437	19,285
Interest cost		21,066	28,039	24,754
Amendment			0	0
Actuarial loss (gain)		(588)	104,618	(48,559)
Benefits paid		(41,804)	(33,217)	(38,453)
Medicare part D subsidiary received		0	0	0
Benefit obligation at end of period	$ 684,834	684,834	690,194	573,317
Defined Benefit Plan, Change in Plan Asset [Roll Forward]
Fair value of plan assets at beginning of period		626,173	615,721	531,183
Actual return on plan assets			25,669	102,591
Employer contribution	4,500	13,500	18,000	20,400
Benefits paid		(41,804)	(33,217)	(38,453)
Fair value of plan assets at end of period			626,173	615,721
Funded status at end of period			(64,021)	42,404
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		831	1,042
Interest cost		1,710	2,310
Actuarial loss (gain)		0	7,162
Benefits paid		(3,026)	(1,938)
Medicare part D subsidiary received		0	0
Benefit obligation at end of period	55,370	55,370	55,855	47,279
Defined Benefit Plan, Change in Plan Asset [Roll Forward]
Employer contribution	500	3,000
Benefits paid		(3,026)	(1,938)
Other Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period		15,688	14,939	17,672
Service cost		84	112	134
Interest cost		467	684	664
Amendment			0	0
Actuarial loss (gain)		(540)	1,108	(2,240)
Benefits paid		(1,045)	(1,424)	(1,536)
Medicare part D subsidiary received		221	269	245
Benefit obligation at end of period	14,875	14,875	15,688	14,939
Defined Benefit Plan, Change in Plan Asset [Roll Forward]
Fair value of plan assets at beginning of period		8,360	8,774	7,541
Actual return on plan assets			522	1,861
Employer contribution	$ 100	500	488	908
Benefits paid		(1,045)	(1,424)	(1,536)
Fair value of plan assets at end of period			8,360	8,774
Funded status at end of period			(7,328)	(6,165)
SERP Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period		55,855	47,279	51,795
Service cost			1,042	1,498
Interest cost			2,310	2,045
Amendment			0	478
Actuarial loss (gain)			7,162	(1,687)
Benefits paid			(1,938)	(6,850)
Medicare part D subsidiary received			0	0
Benefit obligation at end of period			55,855	47,279
Defined Benefit Plan, Change in Plan Asset [Roll Forward]
Fair value of plan assets at beginning of period		$ 0	0	0
Actual return on plan assets			0	0
Employer contribution			1,938	6,850
Benefits paid			(1,938)	(6,850)
Fair value of plan assets at end of period			0	0
Funded status at end of period			$ (55,855)	$ (47,279)

Retirement Benefits - Amounts R

Retirement Benefits - Amounts Recognized (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Total	$ 36,710	$ (48,514)
Qualified Pension Benefits [Member]
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets	0	42,404
Current liabilities	0	0
Noncurrent liabilities	(64,021)	0
Net assets (liabilities)	(64,021)	42,404
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	121,413	(112,055)
Amortization of net (loss) gain	0	(2,889)
Prior service cost (credit)	0	0
Amortization of prior service cost (credit)	1,980	1,980
Total change in other comprehensive income for year	123,393	(112,964)
Supplemental Employee Retirement Plan [Member]
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets	0	0
Current liabilities	(4,386)	(3,981)
Noncurrent liabilities	(51,469)	(43,298)
Net assets (liabilities)	(55,855)	(47,279)
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	7,162	(1,687)
Amortization of net (loss) gain	(913)	(1,461)
Prior service cost (credit)	0	478
Amortization of prior service cost (credit)	(42)	17
Total change in other comprehensive income for year	6,207	(2,653)
Other Benefit [Member]
Defined Benefit Plan, Amounts Recognized in Statement of Financial Position Consist of: [Abstract]
Noncurrent assets	0	0
Current liabilities	(355)	(421)
Noncurrent liabilities	(6,973)	(5,744)
Net assets (liabilities)	(7,328)	(6,165)
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	1,121	(3,665)
Amortization of net (loss) gain	394	(70)
Prior service cost (credit)	0	0
Amortization of prior service cost (credit)	0	0
Total change in other comprehensive income for year	1,515	(3,735)
Parent Company [Member] | Qualified Pension Benefits [Member]
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	55,471	(65,943)
Prior service cost (credit)	(13,782)	(15,762)
Total	41,689	(81,705)
Parent Company [Member] | Supplemental Employee Retirement Plan [Member]
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	15,918	9,670
Prior service cost (credit)	331	373
Total	16,249	10,043
Parent Company [Member] | Other Benefit [Member]
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	(1,457)	(2,972)
Prior service cost (credit)	0	0
Total	(1,457)	(2,972)
Subsidiaries [Member]
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Total	164,281	87,405
Subsidiaries [Member] | Qualified Pension Benefits [Member]
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	122,202	(110,465)
Amortization of net (loss) gain	(13,195)	(20,612)
Prior service cost (credit)	0	0
Amortization of prior service cost (credit)	1,573	1,573
Amortization of transition obligation	0	0
Total change in other comprehensive income for year	110,580	(129,504)
Net loss (gain)	247,331	138,324
Prior service cost (credit)	(10,952)	(12,525)
Total	236,379	125,799
Subsidiaries [Member] | Supplemental Employee Retirement Plan [Member]
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	7,162	(1,687)
Amortization of net (loss) gain	(1,461)	(2,191)
Prior service cost (credit)	0	477
Amortization of prior service cost (credit)	(44)	16
Amortization of transition obligation	0	0
Total change in other comprehensive income for year	5,657	(3,385)
Net loss (gain)	19,751	14,050
Prior service cost (credit)	339	383
Total	20,090	14,433
Subsidiaries [Member] | Other Benefit [Member]
Other changes (pre-tax) in plan assets and benefit obligations recognized in other comprehensive income:
Net loss (gain)	1,121	(3,665)
Amortization of net (loss) gain	702	284
Prior service cost (credit)	0	0
Amortization of prior service cost (credit)	(3)	(30)
Amortization of transition obligation	0	0
Total change in other comprehensive income for year	1,820	(3,411)
Net loss (gain)	(3,733)	(5,556)
Prior service cost (credit)	3	6
Total	$ (3,730)	$ (5,550)

Retirement Benefits Accumulated

Retirement Benefits Accumulated Benefit Obligation (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
SERP Pension Benefits [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation		$ 55,855	$ 47,279	$ 51,795
Defined Benefit Plan, Accumulated Benefit Obligation		50,137	40,892
Defined Benefit Plan, Fair Value of Plan Assets		0	0	0
Other Benefit [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation	$ 14,875	15,688	14,939	17,672
Defined Benefit Plan, Accumulated Benefit Obligation		15,553	14,794
Defined Benefit Plan, Fair Value of Plan Assets		8,360	8,774	7,541
Qualified Pension Benefits [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation	$ 684,834	690,194	573,317	616,290
Defined Benefit Plan, Accumulated Benefit Obligation		681,745	566,689
Defined Benefit Plan, Fair Value of Plan Assets		$ 626,173	$ 615,721	$ 531,183

Retirement Benefits - Net Perio

Retirement Benefits - Net Periodic Benefit Cost (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost			$ 15,966		$ 17,437	$ 19,285
Interest cost			21,066		28,039	24,754
Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost			831		1,042
Interest cost			1,710		2,310
Other Benefit [Member]
Components of net periodic benefit cost:
Service cost			84		112	134
Interest cost			467		684	664
Parent Company [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	$ 5,322	$ 4,359	15,966	$ 13,077	17,437	19,285	$ 16,926
Interest cost	7,022	7,010	21,066	21,030	28,039	24,754	25,986
Expected return on plan assets	(11,260)	(10,616)	(33,779)	(31,848)	(42,464)	(39,095)	(36,203)
Amortization of prior service cost	(495)	(495)	(1,485)	(1,485)	(1,980)	(1,980)	(1,980)
Amortization of net loss	972	0	2,915	0	0	2,889	768
Defined Benefit Plan, Net Periodic Benefit Cost	1,561	258	4,683	774	1,032	5,853	5,497
Parent Company [Member] | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	277	261	831	782	1,042	1,498	1,073
Interest cost	570	577	1,710	1,732	2,310	2,045	2,152
Expected return on plan assets	0	0	0	0	0	0	0
Amortization of prior service cost	11	12	33	33	42	(17)	0
Amortization of net loss	410	228	1,230	684	913	1,461	702
Defined Benefit Plan, Net Periodic Benefit Cost	1,268	1,078	3,804	3,231	4,307	4,987	3,927
Parent Company [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	28	28	84	84	112	134	139
Interest cost	156	171	467	513	684	664	751
Expected return on plan assets	(133)	(134)	(399)	(401)	(535)	(436)	(435)
Amortization of prior service cost	0	0	0	0	0	0	0
Amortization of net loss	(33)	(228)	(99)	(296)	(393)	69	53
Defined Benefit Plan, Net Periodic Benefit Cost	18	(163)	53	(100)	(132)	431	508
Subsidiaries [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	5,322	4,359	15,966	13,077	17,437	19,285	16,926
Interest cost	7,022	7,010	21,066	21,030	28,039	24,753	25,986
Expected return on plan assets	(11,366)	(10,813)	(34,097)	(32,439)	(43,252)	(40,685)	(41,533)
Amortization of prior service cost	(393)	(393)	(1,179)	(1,179)	(1,573)	(1,573)	(1,573)
Amortization of net loss	5,139	3,298	15,416	9,895	13,195	20,612	15,015
Amortization of transition obligation					0	0	0
Defined Benefit Plan, Net Periodic Benefit Cost	5,724	3,461	17,172	10,384	13,846	22,392	14,821
Subsidiaries [Member] | Supplemental Employee Retirement Plan [Member]
Components of net periodic benefit cost:
Service cost	277	261	831	782	1,042	1,498	1,073
Interest cost	570	577	1,710	1,732	2,310	2,045	2,152
Expected return on plan assets	0	0	0	0	0	0	0
Amortization of prior service cost	11	11	33	33	44	(16)	293
Amortization of net loss	530	365	1,590	1,095	1,461	2,191	1,432
Amortization of transition obligation					0	0	0
Defined Benefit Plan, Net Periodic Benefit Cost	1,388	1,214	4,164	3,642	4,857	5,718	4,950
Subsidiaries [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	28	28	84	84	112	134	139
Interest cost	156	171	467	513	684	664	751
Expected return on plan assets	(133)	(134)	(399)	(401)	(535)	(436)	(435)
Amortization of prior service cost	0	1	2	3	3	30	35
Amortization of net loss	(101)	(175)	(304)	(527)	(702)	(284)	(245)
Amortization of transition obligation					0	0	50
Defined Benefit Plan, Net Periodic Benefit Cost	$ (50)	$ (109)	$ (150)	$ (328)	$ (438)	$ 108	$ 295

Retirement Benefits - Assumptio

Retirement Benefits - Assumptions (Details) (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Assumed Health Care Cost Trend Rates
Medical inflation rate assumed for next fiscal year		6.70%
Ultimate health care cost trend rate		4.30%
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates
1% Increase, Effect on post-retirement benefit obligation		$ 47	$ 66
1% Decrease, Effect on post-retirement benefit obligation		(47)	(66)
1% Increase, Effect on service and interest cost components		2	3
1% Decrease, Effect on service and interest cost components		$ (2)	$ (3)
Qualified Pension Benefits [Member]
Benefit Obligation Assumptions
Discount rate	[1]	4.25%	5.10%	4.15%
Rate of compensation increase		4.50%	4.50%	4.50%
Medical trend rate		0.00%	0.00%	0.00%
Benefit Cost Assumptions
Discount rate		5.10%	4.15%	4.75%
Rate of plan assets		7.75%	7.75%	7.75%
Rate of compensation increase		4.50%	4.50%	4.50%
Medical trend rate		0.00%	0.00%	0.00%
SERP Pension Benefits [Member]
Benefit Obligation Assumptions
Discount rate	[1]	4.25%	5.10%	4.15%
Rate of compensation increase		4.50%	4.50%	4.50%
Medical trend rate		0.00%	0.00%	0.00%
Benefit Cost Assumptions
Discount rate		5.10%	4.15%	4.75%
Rate of plan assets		0.00%	0.00%	0.00%
Rate of compensation increase		4.50%	4.50%	4.50%
Medical trend rate		0.00%	0.00%	0.00%
Other Benefit [Member]
Benefit Obligation Assumptions
Discount rate	[1]	4.25%	5.10%	4.15%
Rate of compensation increase		4.50%	4.50%	4.50%
Medical trend rate		5.70%	6.80%	7.50%
Benefit Cost Assumptions
Discount rate		5.10%	4.15%	4.75%
Rate of plan assets		7.00%	6.90%	7.50%
Rate of compensation increase		4.50%	4.50%	4.50%
Medical trend rate		6.70%	8.20%	7.50%
[1]	The Company calculates the present value of the pension liability using a discount rate of 4.25% which represents the single-rate equivalent of the AA rated corporate bond yield curve.

Retirement Benefits - Future Be

Retirement Benefits - Future Benefit Payments (Detail) $ in Thousands	Dec. 31, 2014USD ($)
Qualified Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,015	$ 41,100
2,016	41,400
2,017	42,100
2,018	43,300
2,019	43,900
2020-2024	237,300
SERP Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,015	4,386
2,016	2,595
2,017	1,940
2,018	5,346
2,019	5,811
2020-2024	18,759
Other Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2,015	1,080
2,016	1,136
2,017	1,113
2,018	1,085
2,019	1,062
2020-2024	5,935
2014, without Medicare Part D subsidy	1,429
2015, without Medicare Part D subsidy	1,414
2016, without Medicare Part D subsidy	1,398
2017, without Medicare Part D subsidy	1,380
2018, without Medicare Part D subsidy	1,362
2019-2023, without Medicare Part D subsidy	$ 6,340

Retirement Benefits - Plan Asse

Retirement Benefits - Plan Asset Allocation (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Qualified Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 626,173	$ 615,721	$ 531,183
Other Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		8,360	8,774	7,541
Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 3
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		65,251	62,278	55,614
Fair Value, Measurements, Recurring | Subtotal | Fair Value [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		625,329	615,935
Fair Value, Measurements, Recurring | Subtotal | Level 1 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		350,429	431,936
Fair Value, Measurements, Recurring | Subtotal | Level 2 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		209,649	121,721
Fair Value, Measurements, Recurring | Subtotal | Level 3
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		65,251	62,278
Fair Value, Measurements, Recurring | Other Benefit [Member] | Fair Value [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		8,360	8,774
Fair Value, Measurements, Recurring | Other Benefit [Member] | Level 1 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		8,360	8,703
Fair Value, Measurements, Recurring | Other Benefit [Member] | Level 2 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0	71
Domestic large cap equity
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation, Minimum		25.00%
Target Allocation		31.00%
Target Allocation, Maximum		40.00%
Domestic large cap equity | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Fair Value [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[1]	$ 203,101	193,725
Domestic large cap equity | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 1 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[1]	134,765	157,874
Domestic large cap equity | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 2 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[1]	68,336	35,851
Domestic large cap equity | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 3
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[1]	$ 0	0
Domestic small cap equity
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation, Minimum		0.00%
Target Allocation		9.00%
Target Allocation, Maximum		15.00%
Domestic small cap equity | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Fair Value [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[2]	$ 59,657	62,867
Domestic small cap equity | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 1 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[2]	59,657	62,867
Domestic small cap equity | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 2 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[2]	0	0
Domestic small cap equity | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 3
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[2]	$ 0	0
Non-U.S. equity
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation, Minimum		10.00%
Target Allocation		25.00%
Target Allocation, Maximum		30.00%
Non-U.S. equity | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Fair Value [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[3]	$ 145,157	155,004
Non-U.S. equity | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 1 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[3]	71,026	76,188
Non-U.S. equity | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 2 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[3]	74,131	78,816
Non-U.S. equity | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 3
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[3]	$ 0	0
Fixed income
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation, Minimum		15.00%
Target Allocation		25.00%
Target Allocation, Maximum		30.00%
Fixed income | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Fair Value [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[4]	$ 139,513	135,007
Fixed income | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 1 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[4]	72,331	135,007
Fixed income | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 2 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[4]	67,182	0
Fixed income | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 3
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[4]	$ 0	0
Real estate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation, Minimum		0.00%
Target Allocation		0.00%
Target Allocation, Maximum		10.00%
Absolute return
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation, Minimum		5.00%
Target Allocation		10.00%
Target Allocation, Maximum		15.00%
Absolute return | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Fair Value [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[5]	$ 65,251	62,278
Absolute return | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 1 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[5]	0	0
Absolute return | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 2 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[5]	0	0
Absolute return | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 3
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[5]	$ 65,251	62,278
Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Allocation, Minimum		0.00%
Target Allocation		0.00%
Target Allocation, Maximum		5.00%
Cash and cash equivalents | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Fair Value [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[6]	$ 12,650	7,054
Cash and cash equivalents | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 1 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[6]	12,650	0
Cash and cash equivalents | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 2 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[6]	0	7,054
Cash and cash equivalents | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 3
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[6]	0	0
Cash and cash equivalents | Fair Value, Measurements, Recurring | Other Benefit [Member] | Fair Value [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[7]	59	71
Cash and cash equivalents | Fair Value, Measurements, Recurring | Other Benefit [Member] | Level 1 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[7]	59	0
Cash and cash equivalents | Fair Value, Measurements, Recurring | Other Benefit [Member] | Level 2 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[7]	0	71
Net (Payable) Receivable [Member] | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Fair Value [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		844	(417)
Accrued income | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Fair Value [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets			203
Equities: | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Fair Value [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		407,915	411,596
Equities: | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 1 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		265,448	296,929
Equities: | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 2 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		142,467	114,667
Equities: | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 3
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Tactical asset allocation | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Fair Value [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[8]	0	0
Tactical asset allocation | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 1 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[8]	0	0
Tactical asset allocation | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 2 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[8]	0	0
Tactical asset allocation | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 3
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[8]	0	0
Mutual Funds | Fair Value, Measurements, Recurring | Qualified Pension Benefits [Member] | Level 3
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0	$ 0
Mutual Funds | Fair Value, Measurements, Recurring | Other Benefit [Member] | Fair Value [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[9]	8,301	8,703
Mutual Funds | Fair Value, Measurements, Recurring | Other Benefit [Member] | Level 1 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[9]	8,301	8,703
Mutual Funds | Fair Value, Measurements, Recurring | Other Benefit [Member] | Level 2 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[9]	$ 0	$ 0
[1]	Domestic large cap equity investments are comprised of (1) common stock, and a (2) commingled fund. Investments in common stock are valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014. The investment in the commingled fund is valued at the net asset value per share multiplied by the number of shares held as of December 31, 2014.
[2]	Domestic small cap equity investments are comprised of (1) common stock and a (2) mutual fund. The investments in common stock are valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014. The investment in the mutual fund is valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014.
[3]	Non-US Equity investments are comprised of a (1) mutual fund; and a (2) commingled fund. The investment in the mutual fund is valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014. The investment in the commingled fund is valued at the net asset value per share multiplied by the number of shares held as of December 31, 2014.
[4]	Fixed income securities consist of a mutual fund. The investment in the mutual fund is valued using quoted market prices multiplied by the number of shares owned as of December 31, 2014.
[5]	As of December 31, 2014 absolute return investments consist of two partnerships. The partnerships are valued using the financial reports as of December 31, 2014. These investments are a Level 3 under ASC 820 because the significant valuation inputs are primarily internal to the partnerships with little third party involvement.
[6]	The investment consists of a money market fund, which is valued at the net asset value per share of $1.00 per unit as of December 31, 2014. The money market fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or short-term in nature.
[7]	This is a money market fund. The money market fund investments are valued at the net asset value per share of $1.00 per unit as of December 31, 2014. The money market fund invests primarily in commercial paper, notes, repurchase agreements, and other evidences of indebtedness which are payable on demand or short-term in nature.
[8]	The tactical asset allocation investment is comprised of a commingled fund, which is valued at the net asset value per share multiplied by the number of shares held as of the measurement date.
[9]	This is a publicly traded balanced mutual fund. The fund seeks regular income, conservation of principal, and an opportunity for long-term growth of principal and income. The fair value is determined by taking the number of shares owned by the plan, and multiplying by the market price as of December 31, 2014.

Retirement Benefits - Fair Valu

Retirement Benefits - Fair Value Level 3 Rollforward (Detail) - Qualified Pension Benefits [Member] - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2014	Dec. 31, 2013
Change in plan assets:
Fair value of plan assets at beginning of period		$ 615,721	$ 531,183
Fair value of plan assets at end of period		626,173	615,721
Fair Value, Measurements, Recurring | Level 3
Change in plan assets:
Fair value of plan assets at beginning of period		62,278	55,614
Additional investments		0	0
Distributions		0	0
Realized losses on distributions		0	0
Unrealized gains relating to instruments still held at the reporting date		2,973	6,664
Transferred out of level 3	[1]	0	0
Fair value of plan assets at end of period		65,251	62,278
Fair Value, Measurements, Recurring | Partnership | Level 3
Change in plan assets:
Fair value of plan assets at beginning of period		62,278	55,614
Additional investments		0	0
Distributions		0	0
Realized losses on distributions		0	0
Unrealized gains relating to instruments still held at the reporting date		2,973	6,664
Transferred out of level 3	[1]	0	0
Fair value of plan assets at end of period		65,251	62,278
Fair Value, Measurements, Recurring | Mutual Funds | Level 3
Change in plan assets:
Fair value of plan assets at beginning of period		0	0
Additional investments		0	0
Distributions		0	0
Realized losses on distributions		0	0
Unrealized gains relating to instruments still held at the reporting date		0	0
Transferred out of level 3	[1]	0	0
Fair value of plan assets at end of period		$ 0	$ 0
[1]	The plan had no transfers between level 2 and level 1 during the years ended December 31, 2014 or 2013.

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosures [Line Items]
Federal					$ 0	$ 0	$ 4,268
State					0	0	0
Federal					57,152	122,559	100,701
State					(167)	(151)	(244)
Total income tax expense	$ (6,880)	$ (4,930)	$ 51,665	$ 51,749	56,985	122,408	104,725
Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Federal					0	0	4,268
State					0	0	0
Federal					89,342	160,886	145,040
State					0	0	0
Total income tax expense					$ 89,342	$ 160,886	$ 149,308

Income Taxes - Income Tax Recon

Income Taxes - Income Tax Reconciliation (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosures [Line Items]
Federal statutory rate					35.00%
Income Tax Reconciliation [Abstract]
Income taxes at the statutory rate					$ 80,087	$ 142,847	$ 132,491
Production tax credit					(23,073)	(22,414)	(22,188)
AFUDC excluded from taxable income					(3,790)	(9,406)	(16,543)
Capitalized interest					2,947	7,294	9,757
Utility plant differences					7,090	9,527	8,674
Income Tax Reconciliation, Treasury Grant					(8,808)	(7,651)	(1,007)
Tenaska gas contract					0	1	(4,687)
Other - net					2,532	2,210	(1,772)
Total income tax expense	$ (6,880)	$ (4,930)	$ 51,665	$ 51,749	$ 56,985	$ 122,408	$ 104,725
Effective tax rate					24.90%	30.00%	27.70%
Subsidiaries [Member]
Income Tax Reconciliation [Abstract]
Income taxes at the statutory rate					$ 114,084	$ 180,955	$ 176,917
Production tax credit					(23,073)	(22,414)	(22,188)
AFUDC excluded from taxable income					(3,790)	(9,406)	(16,543)
Capitalized interest					2,947	7,294	9,757
Utility plant differences					7,090	9,527	8,674
Income Tax Reconciliation, Treasury Grant					(8,808)	(7,651)	(1,007)
Tenaska gas contract					0	1	(4,687)
Other - net					892	2,580	(1,615)
Total income tax expense					$ 89,342	$ 160,886	$ 149,308
Effective tax rate					27.40%	31.10%	29.50%

Income Taxes - Deferred Income

Income Taxes - Deferred Income Taxes (Detail) - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013
Deferred Tax Liabilities, Gross
Utility plant and equipment	$ 1,720,730	$ 1,625,107
Regulatory asset for income taxes	95,432	146,867
Fair value of debt instruments	73,606	76,991
Other deferred tax liabilities	200,124	202,189
Subtotal deferred tax liabilities	2,089,892	2,051,154
Deferred Tax Assets, Gross
Net operating loss carryforward	(417,684)	(374,606)
Production tax credit carryforward	(158,604)	(135,531)
Regulatory liability on production tax credit	(84,344)	(71,880)
Fair value of derivative instruments	(36,227)	(7,166)
Other deferred tax assets	(32,121)	(60,970)
Subtotal deferred tax assets	(728,980)	(650,153)
Total	1,360,912	1,401,001
Subsidiaries [Member]
Deferred Tax Liabilities, Gross
Utility plant and equipment	1,720,730	1,625,107
Regulatory asset for income taxes	94,913	146,350
Other deferred tax liabilities	171,380	131,977
Subtotal deferred tax liabilities	1,987,023	1,903,434
Deferred Tax Assets, Gross
Net operating loss carryforward	(181,514)	(173,068)
Production tax credit carryforward	(158,604)	(135,531)
Regulatory liability on production tax credit	(84,344)	(71,880)
Fair value of derivative instruments	(39,067)	(9,988)
Other deferred tax assets	(82,084)	(69,175)
Subtotal deferred tax assets	(545,613)	(459,642)
Total	$ 1,441,410	$ 1,443,792

Income Taxes - Balance Sheet Lo

Income Taxes - Balance Sheet Location (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosures [Line Items]
Current deferred taxes	$ (162,336)	$ (161,445)	$ (86,004)
Non-current deferred taxes	$ 1,552,461	1,522,357	1,487,005
Total		1,360,912	1,401,001
Subsidiaries [Member]
Income Tax Disclosures [Line Items]
Current deferred taxes		(208,447)	(141,058)
Non-current deferred taxes		1,649,857	1,584,850
Total		$ 1,441,410	$ 1,443,792

Litigation (Detail)

Litigation (Detail)	Mar. 06, 2013USD ($)Claim	Sep. 30, 2015USD ($)	Dec. 31, 2014USD ($)	Sep. 30, 2014USD ($)	Dec. 31, 2013USD ($)
Pending Litigation [Member]
Loss Contingencies [Line Items]
Litigation claims accrual | $		$ 400,000	$ 1,700,000	$ 1,700,000	$ 1,400,000
Colstrip Units 1 and 2 [Member]
Loss Contingencies [Line Items]
Equity Method Investment, Ownership Percentage		50.00%	50.00%
Colstrip Units 3 and 4 [Member]
Loss Contingencies [Line Items]
Equity Method Investment, Ownership Percentage		25.00%	25.00%
Sierra Club and Montana Environmental Information Center [Member] | Pending Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value | $	$ 100,000
Sierra Club and Montana Environmental Information Center [Member] | Failure to Update Title V Permit | Pending Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number	1
Sierra Club and Montana Environmental Information Center [Member] | Title V compliance certifications incomplete | Pending Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number	1
Sierra Club and Montana Environmental Information Center [Member] | Opacity | Pending Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number	1

Commitments and Contingencies87

Commitments and Contingencies (Detail) $ in Thousands, MWh in Millions	12 Months Ended
	Dec. 31, 2014USD ($)MWhMW	Dec. 31, 2013USD ($)	Dec. 31, 2012USD ($)MWh	Dec. 31, 2010USD ($)MWh	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)
Payment Obligations for Power Purchases
Percentage of Company's energy output (percent)	14.90%
Contract expenses	$ 69,661	$ 63,365	$ 70,188
Megawatt Capacity | MW	749
Estimated 2015 Costs	$ 82,092
2015 Debt Service Costs	32,811
Interest included in 2015 Debt Service Costs	14,604
Debt Outstanding	256,077
2,014	206,531
2,015	248,107
2,016	285,730
2,017	271,530
2,018	264,426
Thereafter	1,998,857
Total	$ 3,275,181
Total energy obtained during period under purchased power contracts (MWh) | MWh	12.1		10.7	6.1
Cost incurred during period to provide energy under purchased power contracts	$ 401,400		$ 348,700	$ 203,100
Daily take obligation under long-term service contract (percent)	100.00%
Daily delivery obligation under long-term service contract (percent)	100.00%
Columbia River projects
Payment Obligations for Power Purchases
2,014	$ 73,023
2,015	75,360
2,016	74,851
2,017	65,981
2,018	53,837
Thereafter	644,666
Total	987,718
Other utilities
Payment Obligations for Power Purchases
2,014	16,136
2,015	18,884
2,016	11,823
2,017	1,257
2,018	890
Total	48,990
Non-utility contracts
Payment Obligations for Power Purchases
2,014	117,372
2,015	153,863
2,016	199,056
2,017	204,292
2,018	209,699
Thereafter	1,354,191
Total	2,238,473
Gas-fired generation facility
Payment Obligations for Power Purchases
2,014	63,600
Purchase obligation under longer term (2013 through 2029) agreements	286,700
Short-term energy supply contracts
Payment Obligations for Power Purchases
2,014	105,800
2,015	32,400
2,016	6,500
Combustion turbines
Payment Obligations for Power Purchases
Deman charges incurred under firm supply and service contracts	35,700
Firm transportation service
Payment Obligations for Power Purchases
2,014	154,121
2,015	147,424
2,016	144,751
2,017	131,484
2,018	112,249
Thereafter	373,958
Total	1,063,987
Deman charges incurred under firm supply and service contracts	155,000
Firm storage service
Payment Obligations for Power Purchases
2,014	6,528
2,015	5,337
2,016	5,209
2,017	1,407
2,018	1,535
Thereafter	1,258
Total	21,274
Deman charges incurred under firm supply and service contracts	6,600
Firm natural gas supply
Payment Obligations for Power Purchases
2,014	160,649
2,015	152,761
2,016	149,960
2,017	132,891
2,018	113,784
Thereafter	375,216
Total	1,085,261
Energy production service contracts
Payment Obligations for Power Purchases
2,014	32,979
2,015	15,650
2,016	5,558
2,017	4,064
2,018	2,372
Thereafter	23,443
Total	84,066
Automated meter reading system
Payment Obligations for Power Purchases
2,014	25,402
2,015	16,081
2,016	13,362
2,017	13,996
2,018	14,602
Thereafter	51,986
Total	135,429
Service contract obligations
Payment Obligations for Power Purchases
2,014	58,381
2,015	31,731
2,016	18,920
2,017	18,060
2,018	16,974
Thereafter	75,429
Total	$ 219,495
Rock Island Project
Payment Obligations for Power Purchases
Percent of Output	25.00%
Megawatt Capacity | MW	156
Estimated 2015 Costs	$ 29,854
2015 Debt Service Costs	11,009
Interest included in 2015 Debt Service Costs	6,174
Debt Outstanding	$ 98,191
Rocky Reach Project
Payment Obligations for Power Purchases
Percent of Output	25.00%
Megawatt Capacity | MW	325
Estimated 2015 Costs	$ 27,583
2015 Debt Service Costs	8,245
Interest included in 2015 Debt Service Costs	3,343
Debt Outstanding	$ 53,299
Wells Project
Payment Obligations for Power Purchases
Percent of Output	29.90%
Megawatt Capacity | MW	251
Estimated 2015 Costs	$ 17,277
2015 Debt Service Costs	9,383
Interest included in 2015 Debt Service Costs	2,597
Debt Outstanding	$ 64,931
Priest Rapids Development
Payment Obligations for Power Purchases
Percent of Output	0.60%
Megawatt Capacity | MW	8
Estimated 2015 Costs	$ 3,689
2015 Debt Service Costs	2,087
Interest included in 2015 Debt Service Costs	1,245
Debt Outstanding	$ 19,828
Wanapum Development
Payment Obligations for Power Purchases
Percent of Output	0.60%
Megawatt Capacity | MW	9
Estimated 2015 Costs	$ 3,689
2015 Debt Service Costs	2,087
Interest included in 2015 Debt Service Costs	1,245
Debt Outstanding	19,828
Pending Litigation [Member]
Payment Obligations for Power Purchases
Litigation claims accrual	$ 1,700	$ 1,400			$ 400	$ 1,700
Minimum | Combustion turbines
Payment Obligations for Power Purchases
Remaining terms under contract	Less than one year
Maximum | Combustion turbines
Payment Obligations for Power Purchases
Remaining terms under contract	30
Colstrip Units 1 and 2 [Member]
Payment Obligations for Power Purchases
Ownership interest (percent)	50.00%				50.00%
Colstrip Units 3 and 4 [Member]
Payment Obligations for Power Purchases
Ownership interest (percent)	25.00%				25.00%

Related Party Transactions (Det

Related Party Transactions (Detail) - Subsidiaries [Member] - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Debt Instrument, Fee Amount	$ 1,000
Short-term note owed to parent	$ 28,933	$ 29,598
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Applicable interest rate on credit facility at period end	0.391%	0.325%

Segment Information (Detail)

Segment Information (Detail)	12 Months Ended
	Dec. 31, 2014mi²Segment	Sep. 30, 2015mi²
Segment Reporting Information [Line Items]
Number of operating segments | Segment	1
Subsidiaries [Member]
Segment Reporting Information [Line Items]
Area of service territory (sqmi)	6,000	6,000

Accumulated Other Comprehensi90

Accumulated Other Comprehensive Income (Loss) - Changes by Component (Detail) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive income (loss), net of tax		$ (37,043)	$ 47,715
Accumulated other comprehensive income (loss), net of tax	$ (34,292)	(34,292)	(37,043)	$ 47,715
Parent Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive income (loss), net of tax	(34,854)	(37,043)	47,715	(32,829)	$ (30,907)
Other comprehensive income (loss) before reclassifications	0	696	(84,301)	76,004	(13,574)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	562	2,055	(457)	4,540	11,652
Net current-period other comprehensive income (loss)	562	2,751	(84,758)	80,544	(1,922)
Accumulated other comprehensive income (loss), net of tax	(34,292)	(34,292)	(37,043)	47,715	(32,829)
Parent Company [Member] | Net Unrealized Gain (Loss) on Prior Service Cost on Pension Plans [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive income (loss), net of tax	(34,854)	(36,710)	48,514	(29,065)	(15,195)
Other comprehensive income (loss) before reclassifications	0	696	(84,301)	76,004	(13,574)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	562	1,722	(923)	1,575	(296)
Net current-period other comprehensive income (loss)	562	2,418	(85,224)	77,579	(13,870)
Accumulated other comprehensive income (loss), net of tax	(34,292)	(34,292)	(36,710)	48,514	(29,065)
Parent Company [Member] | Energy Related Derivative [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive income (loss), net of tax	0	(333)	(705)	(742)	(1,113)
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	0	333	372	37	371
Net current-period other comprehensive income (loss)	0	333	372	37	371
Accumulated other comprehensive income (loss), net of tax	0	0	(333)	(705)	(742)
Parent Company [Member] | Interest Rate Swap [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive income (loss), net of tax			(94)	(3,022)	(14,599)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax			94	2,928	11,577
Net current-period other comprehensive income (loss)			94	2,928	11,577
Accumulated other comprehensive income (loss), net of tax				(94)	(3,022)
Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive income (loss), net of tax	(162,638)	(170,957)	(95,739)	(187,198)	(188,579)
Other comprehensive income (loss) before reclassifications	0	712	(84,955)	74,969	(17,049)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	3,449	11,056	9,737	16,490	18,430
Net current-period other comprehensive income (loss)	3,449	11,768	(75,218)	91,459	1,381
Accumulated other comprehensive income (loss), net of tax	(159,189)	(159,189)	(170,957)	(95,739)	(187,198)
Subsidiaries [Member] | Net Unrealized Gain (Loss) on Prior Service Cost on Pension Plans [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive income (loss), net of tax	(156,806)	(164,281)	(87,405)	(175,998)	(168,704)
Other comprehensive income (loss) before reclassifications	0	712	(84,955)	74,969	(17,049)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	3,370	10,133	8,079	13,624	9,755
Net current-period other comprehensive income (loss)	3,370	10,845	(76,876)	88,593	(7,294)
Accumulated other comprehensive income (loss), net of tax	(153,436)	(153,436)	(164,281)	(87,405)	(175,998)
Subsidiaries [Member] | Energy Related Derivative [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive income (loss), net of tax	0	(686)	(2,027)	(4,576)	(12,934)
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	0	686	1,341	2,549	8,358
Net current-period other comprehensive income (loss)	0	686	1,341	2,549	8,358
Accumulated other comprehensive income (loss), net of tax	0	0	(686)	(2,027)	(4,576)
Subsidiaries [Member] | Interest Rate Swap [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive income (loss), net of tax	(5,832)	(5,990)	(6,307)	(6,624)	(6,941)
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	79	237	317	317	317
Net current-period other comprehensive income (loss)	79	237	317	317	317
Accumulated other comprehensive income (loss), net of tax	$ (5,753)	$ (5,753)	$ (5,990)	$ (6,307)	$ (6,624)

Accumulated Other Comprehensi91

Accumulated Other Comprehensive Income (Loss) - Reclassification Location (Detail) - USD ($) $ in Thousands		3 Months Ended				9 Months Ended				12 Months Ended
		Sep. 30, 2015		Sep. 30, 2014		Sep. 30, 2015		Sep. 30, 2014		Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Reclassification Out Of Accumulated Other Comprehensive Income [Line Items]
Reclassification of net unrealized loss on derivative instruments during the period, tax		$ 0		$ 0		$ (179)		$ (187)		$ (200)		$ (20)		$ (200)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0		0		(333)		(347)		(372)		(37)		(371)
Parent Company [Member] | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Out Of Accumulated Other Comprehensive Income [Line Items]
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent		(562)		314		(2,751)		(80)		457		(4,540)		(11,652)
Parent Company [Member] | Reclassification out of Accumulated Other Comprehensive Income | Net Unrealized Gain (Loss) on Prior Service Cost on Pension Plans [Member]
Reclassification Out Of Accumulated Other Comprehensive Income [Line Items]
Amortization of prior service cost		484	[1]	483	[1]	1,452	[1]	1,452	[1]	1,938	[2]	1,997	[2]	1,980	[2]
Amortization of net gain (loss)		(1,349)	[1]	0	[1]	(5,172)	[1]	(388)	[1]	(519)	[2]	(4,420)	[2]	(1,524)	[2]
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax		(865)		483		(3,720)		1,064		1,419		(2,423)		456
Tax (expense) or benefit		303		(169)		1,302		(703)		(496)		848		(160)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax		(562)		314		(2,418)		361		923		(1,575)		296
Parent Company [Member] | Energy Related Derivative [Member] | Reclassification out of Accumulated Other Comprehensive Income | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [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)		(572)		(57)		(571)
Reclassification of net unrealized loss on derivative instruments during the period, tax		0		0		179		187		200		20		200
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0		0		(333)		(347)		(372)		(37)		(371)
Parent Company [Member] | Energy Related Derivative [Member] | Electric generation fuel [Member] | Reclassification out of Accumulated Other Comprehensive Income | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Reclassification Out Of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax												0		100
Parent Company [Member] | Energy Related Derivative [Member] | Purchased Electricity [Member] | Reclassification out of Accumulated Other Comprehensive Income | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Reclassification Out Of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax										(572)		(57)		(671)
Parent Company [Member] | Interest Rate Swap [Member] | Reclassification out of Accumulated Other Comprehensive Income | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [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)		(144)		(4,505)		(17,811)
Reclassification of net unrealized loss on derivative instruments during the period, tax		0		0		0		50		50		1,577		6,234
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0		0		0		(94)		(94)		(2,928)		(11,577)
Subsidiaries [Member] | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Out Of Accumulated Other Comprehensive Income [Line Items]
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent		(3,449)		(1,959)		(11,768)		(7,205)		(9,737)		(16,490)		(18,430)
Subsidiaries [Member] | Reclassification out of Accumulated Other Comprehensive Income | Net Unrealized Gain (Loss) on Prior Service Cost on Pension Plans [Member]
Reclassification Out Of Accumulated Other Comprehensive Income [Line Items]
Amortization of prior service cost		383	[1]	381	[1]	1,145	[1]	1,143	[1]	1,526	[2]	1,559	[2]	1,245	[2]
Amortization of net gain (loss)		(5,568)	[1]	(3,488)	[1]	(17,830)	[1]	(10,463)	[1]	(13,954)	[2]	(22,519)	[2]	(16,203)	[2]
Amortization of transition obligation	[2]									0		0		(50)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax		(5,185)		(3,107)		(16,685)		(9,320)		(12,428)		(20,960)		(15,008)
Tax (expense) or benefit		1,815		1,227		5,840		3,070		4,349		7,336		5,253
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax		(3,370)		(1,880)		(10,845)		(6,250)		(8,079)		(13,624)		(9,755)
Subsidiaries [Member] | Energy Related Derivative [Member] | Reclassification out of Accumulated Other Comprehensive Income | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [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)		(2,063)		(3,922)		(12,858)
Reclassification of net unrealized loss on derivative instruments during the period, tax		0		0		369		386		722		1,373		4,500
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0		0		(686)		(718)		(1,341)		(2,549)		(8,358)
Subsidiaries [Member] | Energy Related Derivative [Member] | Electric generation fuel [Member] | Reclassification out of Accumulated Other Comprehensive Income | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Reclassification Out Of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax										0		0		97
Subsidiaries [Member] | Energy Related Derivative [Member] | Purchased Electricity [Member] | Reclassification out of Accumulated Other Comprehensive Income | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Reclassification Out Of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax										(2,063)		(3,922)		(12,955)
Subsidiaries [Member] | Interest Rate Swap [Member] | Reclassification out of Accumulated Other Comprehensive Income | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Reclassification Out Of Accumulated Other Comprehensive Income [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax		(122)		(122)		(366)		(366)		(488)		(488)		(488)
Reclassification of net unrealized loss on derivative instruments during the period, tax		43		43		129		129		171		171		171
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		$ (79)		$ (79)		$ (237)		$ (237)		$ (317)		$ (317)		$ (317)
[1]	These AOCI components are included in the computation of net periodic pension cost (see Note 5 for additional details).
[2]	These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 12 for additional details).

New Accounting Pronouncements D

New Accounting Pronouncements Debt Issuance Costs (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Debt Issuance Cost	$ 39.6	$ 35.7

Asset Retirement Obligation (De

Asset Retirement Obligation (Detail) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset retirement obligation at beginning of period	$ 48,909	$ 48,687	$ 45,496
Asset Retirement Obligation, Liabilities Incurred		0	350
Asset Retirement Obligation, Revision of Estimate		(480)	2,769
Asset Retirement Obligation, Accretion Expense		1,304	1,260
Asset retirement obligation at end of period		48,909	$ 48,687
Subsidiaries [Member]
Asset retirement obligation at beginning of period	48,909
Asset Retirement Obligations, Significant Changes	34,534
Asset Retirement Obligation, Liabilities Incurred	(3,696)
Asset Retirement Obligation, Revision of Estimate	450
Asset Retirement Obligation, Accretion Expense	1,220
Asset retirement obligation at end of period	$ 81,417	$ 48,909

Other (Term Loan) (Detail)

Other (Term Loan) (Detail) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Jan. 31, 2016	Oct. 31, 2015	May. 26, 2015	May. 12, 2015	Dec. 31, 2014	Jun. 29, 2014
Debt and Financial Instruments [Line Items]
Long-term Debt, Gross					$ 400,000	$ 5,462,272	$ 299,100
Special Dividend [Line Items]	$ 96,700
Subsidiaries [Member]
Debt and Financial Instruments [Line Items]
Long-term Debt, Gross				$ 425,000		$ 3,763,272
Debt Instrument, Interest Rate, Stated Percentage				4.30%	3.65%
Subsidiaries [Member] | Scenario, Forecast [Member]
Debt and Financial Instruments [Line Items]
Long-term Debt, Gross		$ 250,000	$ 150,000
Debt Instrument, Interest Rate, Stated Percentage		6.75%	5.197%

Other Related Party Transaction

Other Related Party Transactions (Detail) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transaction, Amounts of Transaction	$ 14.8	$ 17.7