Puget Sound Energy 10-Q 29 Apr 15 2015 Q1 Quarterly report Financial data

Document_And_Entity_Informatio

Document And Entity Information	3 Months Ended
	Mar. 31, 2015
Entity Information [Line Items]
Entity Registrant Name	PUGET ENERGY INC /WA
Entity Central Index Key	1085392
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	200
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	FALSE
Document Period End Date	31-Mar-15
Subsidiaries [Member]
Entity Information [Line Items]
Entity Registrant Name	PUGET SOUND ENERGY INC
Entity Central Index Key	81100
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	85,903,791
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	FALSE
Document Period End Date	31-Mar-15

CONSOLIDATED_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Operating revenue:
Electric	$573,628	$633,553
Gas	348,861	387,443
Other	4,346	4,379
Total operating revenue	926,835	1,025,375
Energy costs:
Purchased electricity	153,480	181,157
Electric generation fuel	48,017	75,436
Residential exchange	-43,714	-30,003
Purchased gas	156,433	191,306
Unrealized (gain) loss on derivative instruments, net	-3,696	-7,839
Utility operations and maintenance	137,175	144,076
Non-utility expense and other	3,210	3,422
Depreciation	106,178	101,719
Conservation amortization	29,604	28,982
Taxes other than income taxes	94,913	100,818
Total operating expenses	681,600	789,074
Operating income	245,235	236,301
Other income (deductions):
Other income	4,781	4,242
Other expense	-1,407	-1,582
Non-hedged interest rate derivative expense	-1,975	-747
Interest charges:
AFUDC	1,432	1,153
Interest expense	-88,909	-90,255
Total before tax	159,157	149,112
Tax (expense) or benefit	43,481	41,520
Net of Tax	115,676	107,592
Subsidiaries [Member]
Operating revenue:
Electric	573,628	633,553
Gas	348,861	387,443
Other	4,354	4,379
Total operating revenue	926,843	1,025,375
Energy costs:
Purchased electricity	153,480	181,157
Electric generation fuel	48,017	75,436
Residential exchange	-43,714	-30,003
Purchased gas	156,433	191,306
Unrealized (gain) loss on derivative instruments, net	-3,152	-7,270
Utility operations and maintenance	137,175	144,076
Non-utility expense and other	7,006	6,177
Depreciation	106,178	101,719
Conservation amortization	29,604	28,982
Taxes other than income taxes	94,913	100,818
Total operating expenses	685,940	792,398
Operating income	240,903	232,977
Other income (deductions):
Other income	4,782	4,240
Other expense	-1,407	-1,582
Interest charges:
AFUDC	1,432	1,153
Interest expense	-63,196	-64,137
Interest expense on parent note	-31	-26
Total before tax	182,483	172,625
Tax (expense) or benefit	53,383	51,542
Net of Tax	$129,100	$121,083

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Parent [Line Items]
Net income (loss)	$115,676	$107,592
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	579	-209
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	333	347
Other Comprehensive Income Reclassification Of Net Unrealized Gain Loss On Interest Rate Swaps During Period Net Of Tax	0	94
Other comprehensive income (loss)	912	232
Comprehensive income (loss)	116,588	107,824
Subsidiaries [Member]
Parent [Line Items]
Net income (loss)	129,100	121,083
Other comprehensive income (loss):
Net unrealized gain (loss) from pension and postretirement plans, net of tax	3,381	2,001
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	686	718
Amortization Of Financing Cash Flow Hedge Contracts To Earnings During Period Net Of Tax	79	79
Other comprehensive income (loss)	4,146	2,798
Comprehensive income (loss)	133,246	123,881
Reclassification out of Accumulated Other Comprehensive Income [Member] | Parent Company [Member]
Other comprehensive income (loss):
Comprehensive income (loss)	-912	-232
Reclassification out of Accumulated Other Comprehensive Income [Member] | Subsidiaries [Member]
Other comprehensive income (loss):
Comprehensive income (loss)	-4,146	-2,798
Reclassification out of Accumulated Other Comprehensive Income [Member] | Net unrealized gain (loss) and prior service cost on pension plans | Parent Company [Member]
Parent [Line Items]
Net income (loss)	-579	209
Reclassification out of Accumulated Other Comprehensive Income [Member] | Net unrealized gain (loss) and prior service cost on pension plans | Subsidiaries [Member]
Parent [Line Items]
Net income (loss)	($3,381)	($2,001)

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Reclassification of net unrealized loss on interest rate swaps during the period, net of tax	$0	$50
Net unrealized gain (loss) from pension and postretirement plans, net of tax	312	-113
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax	179	187
Subsidiaries [Member]
Net unrealized gain (loss) from pension and postretirement plans, net of tax	1,821	1,078
Reclassification of net unrealized loss on energy derivative instruments during the period, net of tax	369	386
Amortization of treasury interest rate swaps to earnings, net of tax	$43	$43

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Utility plant (at original cost, including construction work in progress):
Electric plant	$7,180,026	$7,135,206
Gas plant	2,717,549	2,680,067
Common plant	456,595	472,926
Less: Accumulated depreciation and amortization	-1,666,759	-1,611,220
Net utility plant	8,687,411	8,676,979
Other property and investments:
Goodwill	1,656,513	1,656,513
Other property and investments	86,880	91,139
Total other property and investments	1,743,393	1,747,652
Current assets:
Cash and cash equivalents	19,119	37,527
Restricted cash	16,801	32,863
Accounts receivable, net of allowance for doubtful accounts	318,477	306,923
Unbilled revenue	142,123	168,039
Purchased Gas Adjustment Receivable	0	21,073
Materials and supplies, at average cost	84,999	83,189
Fuel and gas inventory, at average cost	43,345	69,433
Unrealized gain on derivative instruments	9,806	21,178
Income taxes	151	301
Prepaid expense and other	17,714	20,905
Power contract acquisition adjustment gain	43,266	43,843
Deferred income taxes	165,266	161,445
Total current assets	861,067	966,719
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	77,406	95,432
Power Cost Adjustment Mechanism Asset, Noncurrent	4,654	4,623
Regulatory assets related to power contracts	29,095	29,816
Other regulatory assets	889,780	866,835
Unrealized gain on derivative instruments	3,528	3,170
Power contract acquisition adjustment gain	326,006	347,547
Other	96,609	96,275
Total other long-term and regulatory assets	1,427,078	1,443,698
Total assets	12,718,949	12,835,048
Capitalization:
Common stock	0	0
Additional paid-in capital	3,308,957	3,308,957
Earnings reinvested in the business	322,346	271,414
Accumulated Other Comprehensive Income (Loss), Net of Tax	-36,131	-37,043
Total common shareholder's equity	3,595,172	3,543,328
Long-term debt:
First mortgage bonds and senior notes	2,939,412	3,189,412
Pollution control bonds	161,860	161,860
Junior subordinated notes	250,000	250,000
Long-term debt	1,699,000	1,699,000
Debt discount	-215,881	-218,664
Total long-term debt	4,834,391	5,081,608
Total capitalization	8,429,563	8,624,936
Current liabilities:
Accounts payable	226,552	307,578
Short-term debt	0	85,000
Long-term Debt, Current Maturities	412,000	162,000
Purchased gas adjustment liability	5,545	0
Accrued expenses:
Taxes	125,155	107,782
Salaries and wages	29,016	40,970
Interest	74,300	78,914
Unrealized loss on derivative instruments	138,873	142,195
Power contract acquisition adjustment loss	3,553	3,593
Other	84,232	62,464
Total current liabilities	1,099,226	990,496
Long-term and regulatory liabilities:
Deferred income taxes	1,552,126	1,522,357
Unrealized loss on derivative instruments	57,376	62,913
Regulatory liabilities	605,584	633,471
Regulatory liabilities related to power contracts	369,271	391,389
Power contract acquisition adjustment loss	25,542	26,223
Other deferred credits	580,261	583,263
Total long-term and regulatory liabilities	3,190,160	3,219,616
Commitments and contingencies
Total capitalization and liabilities	12,718,949	12,835,048
Subsidiaries [Member]
Utility plant (at original cost, including construction work in progress):
Electric plant	9,369,001	9,330,999
Gas plant	3,316,608	3,282,818
Common plant	496,511	512,842
Less: Accumulated depreciation and amortization	-4,494,709	-4,449,680
Net utility plant	8,687,411	8,676,979
Other property and investments:
Other property and investments	82,663	86,913
Total other property and investments	82,663	86,913
Current assets:
Cash and cash equivalents	18,479	37,466
Restricted cash	16,801	32,863
Accounts receivable, net of allowance for doubtful accounts	319,013	307,046
Unbilled revenue	142,123	168,039
Purchased Gas Adjustment Receivable	0	21,073
Materials and supplies, at average cost	84,999	83,189
Fuel and gas inventory, at average cost	40,776	66,656
Unrealized gain on derivative instruments	9,806	21,178
Income taxes	151	301
Prepaid expense and other	17,714	20,907
Deferred income taxes	212,025	208,447
Total current assets	861,887	967,165
Other long-term and regulatory assets:
Regulatory asset for deferred income taxes	76,891	94,913
Power Cost Adjustment Mechanism Asset, Noncurrent	4,654	4,623
Other regulatory assets	889,745	866,793
Unrealized gain on derivative instruments	3,528	3,170
Other	89,985	89,306
Total other long-term and regulatory assets	1,064,803	1,058,805
Total assets	10,696,764	10,789,862
Capitalization:
Common stock	859	859
Additional paid-in capital	3,246,205	3,246,205
Earnings reinvested in the business	236,098	202,622
Accumulated Other Comprehensive Income (Loss), Net of Tax	-166,811	-170,957
Total common shareholder's equity	3,316,351	3,278,729
Long-term debt:
First mortgage bonds and senior notes	2,939,412	3,189,412
Pollution control bonds	161,860	161,860
Junior subordinated notes	250,000	250,000
Debt discount	-13	-13
Total long-term debt	3,351,259	3,601,259
Total capitalization	6,667,610	6,879,988
Current liabilities:
Accounts payable	226,552	307,572
Short-term debt	0	85,000
Short-term note owed to parent	28,933	28,933
Long-term Debt, Current Maturities	412,000	162,000
Purchased gas adjustment liability	5,545	0
Accrued expenses:
Taxes	125,155	107,782
Salaries and wages	29,016	40,970
Interest	56,707	55,346
Unrealized loss on derivative instruments	132,694	135,973
Other	84,232	62,464
Total current liabilities	1,100,834	986,040
Long-term and regulatory liabilities:
Deferred income taxes	1,691,027	1,649,857
Unrealized loss on derivative instruments	54,158	60,063
Regulatory liabilities	602,980	630,651
Other deferred credits	580,155	583,263
Total long-term and regulatory liabilities	2,928,320	2,923,834
Commitments and contingencies
Total capitalization and liabilities	$10,696,764	$10,789,862

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, except Share data, unless otherwise specified
ASSETS
Construction work in progress	$255,247	$239,690
Current assets:
Allowance for doubtful accounts	8,266	7,472
Common shareholderbs equity:
Common stock, par value (in dollars per share)	$0.01	$0.01
Common stock, shares authorized (in shares)	1,000	1,000
Common stock, shares outstanding (in shares)	200	200
Subsidiaries [Member]
ASSETS
Construction work in progress	255,247	239,690
Current assets:
Allowance for doubtful accounts	$8,266	$7,472
Common shareholderbs equity:
Common stock, par value (in dollars per share)	$0.01	$0.01
Common stock, shares authorized (in shares)	150,000,000	150,000,000
Common stock, shares outstanding (in shares)	85,903,791	85,903,791

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Operating activities:
Net income (loss)	$115,676	$107,592
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	106,178	101,719
Conservation amortization	29,604	28,982
Deferred income taxes and tax credits, net	43,483	41,520
Net unrealized (gain) loss on derivative instruments	-3,372	-8,793
Derivative contracts classified as financing activities due to merger	8,045	8,026
AFUDC - Equity	-1,714	-1,436
Funding of pension liability	-4,500	-3,000
Regulatory Assets	-56,506	-38,240
Regulatory liabilities	-4,200	6,407
Other long-term assets	5,045	-5,667
Other long-term liabilities	1,733	21,532
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	14,362	28,650
Materials and supplies	-1,810	214
Fuel and gas inventory	25,880	35,451
Income taxes	150	148
Prepayments and other	3,193	539
Purchased gas adjustment	26,618	-3,079
Accounts payable	-73,907	-13,886
Taxes payable	17,373	11,476
Accrued expenses and other	-11,445	-7,621
Net cash provided by operating activities	239,886	310,534
Investing activities:
Construction expenditures - excluding equity AFUDC	-117,106	-96,318
Proceeds from disposition of assets	487	0
Restricted cash	16,062	-18,266
Other	1,947	-4,125
Net cash used in investing activities	-98,610	-118,709
Financing activities:
Change in short-term debt and leases, net	-85,000	-163,903
Dividends paid	-64,744	-42,081
Derivative contracts classified as financing activities due to merger	-8,045	-8,026
Issuance cost of bonds and other	-1,895	1,464
Net cash provided by (used in) financing activities	-159,684	-212,546
Net increase (decrease) in cash and cash equivalents	-18,408	-20,721
Cash and cash equivalents at beginning of period	37,527	44,302
Cash and cash equivalents at end of period	19,119	23,581
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	88,598	90,756
Cash payments (refunds) for income taxes	0	0
Accounts payable for capital expenditures eliminated from cash flows	44,657	55,603
Subsidiaries [Member]
Operating activities:
Net income (loss)	129,100	121,083
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	106,178	101,719
Conservation amortization	29,604	28,982
Deferred income taxes and tax credits, net	53,381	51,543
Net unrealized (gain) loss on derivative instruments	-3,152	-7,270
AFUDC - Equity	-1,714	-1,436
Funding of pension liability	-4,500	-3,000
Regulatory Assets	-56,506	-38,240
Regulatory liabilities	-4,200	6,407
Other long-term assets	4,691	-3,251
Other long-term liabilities	3,277	19,275
Change in certain current assets and liabilities:
Accounts receivable and unbilled revenue	13,949	28,691
Materials and supplies	-1,810	214
Fuel and gas inventory	25,880	35,451
Income taxes	150	148
Prepayments and other	3,193	539
Purchased gas adjustment	26,618	-3,079
Accounts payable	-73,901	-13,886
Taxes payable	17,373	11,476
Accrued expenses and other	-6,308	-1,276
Net cash provided by operating activities	261,303	334,090
Investing activities:
Construction expenditures - excluding equity AFUDC	-117,106	-96,318
Proceeds from disposition of assets	487	0
Restricted cash	16,062	-18,266
Other	2,786	-3,507
Net cash used in investing activities	-97,771	-118,091
Financing activities:
Change in short-term debt and leases, net	-85,000	-163,903
Dividends paid	-95,624	-74,114
Issuance cost of bonds and other	-1,895	1,463
Net cash provided by (used in) financing activities	-182,519	-236,554
Net increase (decrease) in cash and cash equivalents	-18,987	-20,555
Cash and cash equivalents at beginning of period	37,466	44,111
Cash and cash equivalents at end of period	18,479	23,556
Supplemental cash flow information:
Cash payments for interest (net of capitalized interest)	59,135	59,666
Cash payments (refunds) for income taxes	0	0
Accounts payable for capital expenditures eliminated from cash flows	$44,657	$55,603

New_Accounting_Pronouncements

New Accounting Pronouncements	3 Months Ended
	Mar. 31, 2015
New Accounting Pronouncements [Abstract]
New Accounting Pronouncements and Changes in Accounting Principles [Text Block]	New Accounting Pronouncements
	Revenue
	In May 2014, the (Financial Accounting Standards Board) FASB issued Accounting Standards Update (ASU) No. 2014-09, "Revenue from Contracts with Customers (Topic 606)", which outlines a single comprehensive model for use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The ASU is based on the principle that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to fulfill a contract.
	ASU 2014-09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. On April 1, 2015, FASB voted to propose a deferral to the effective date of ASU 2014-09 by one year and permit entities to adopt one year earlier if they choose (i.e. the original effective date stated above).  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 (IAS) 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. The Company adopted ASU 2015-01 as of the beginning of fiscal year 2015. This did not result in a material change to our financial statements.
	Debt Issuance Costs
	In April 2015, the FASB issued ASU 2015-03, "Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs". ASU 2015-03 requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with the presentation of a debt discount. This new guidance affects only the presentation of debt issuance costs and not the recognition and measurement of debt issuance costs. ASU 2015-03 is to be applied on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance.
	For the Company, the ASU is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption of the amendments is permitted for financial statements that have not been previously issued. The Company plans to adopt ASU 2015-03 during the first quarter of fiscal 2016. The amount of unamortized debt issuance costs as of March 31, 2015 and December 31, 2014 totaled $34.5 million and $35.7 million, respectively.

Accounting_for_Derivative_Inst

Accounting for Derivative Instruments and Hedging Activities	3 Months Ended
	Mar. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Accounting for Derivative Instruments and Hedging Activities	Accounting for Derivative Instruments and Hedging Activities
	PSE employs various energy portfolio optimization strategies, but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the PCA. Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility in costs in the portfolio. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. The forward physical electric agreements are both fixed and variable (at index), while the physical natural gas agreements are variable. To fix the price of wholesale electricity and natural gas, PSE may enter into fixed-for-floating swap (financial) contracts with various counterparties. PSE also utilizes natural gas call and put options as an additional hedging instrument to increase the hedging portfolio's flexibility to react to commodity price fluctuations.
	The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program, and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. As of March 31, 2015, 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	March 31, 2015							December 31, 2014
	Puget Sound Energy
	(Dollars in Thousands)	Volumes	Assets 1			Liabilities 2			Volumes	Assets 1			Liabilities 2
	Interest rate swap derivatives 3	$450 million	$	—		$	9,397		$450 million	$	—		$	9,073
	Electric portfolio derivatives	*	5,644			103,844			*	4,822			107,228
	Natural gas derivatives (MMBtus) 4	348.2 million	7,690			83,008			360.4 million	19,526			88,807
	Total derivative contracts		$	13,334		$	196,249			$	24,348		$	205,108
	Current		$	9,806		$	138,873			$	21,178		$	142,195
	Long-term		3,528			57,376				3,170			62,913
	Total derivative contracts		$	13,334		$	196,249			$	24,348		$	205,108
	_______________
	1	Balance sheet location: Current and Long-term Unrealized gain on derivative instruments.
	2	Balance sheet location: Current and Long-term Unrealized loss on derivative instruments.
	3	Interest rate swap contracts are only held at Puget Energy.
	4	All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations” (ASC 980) due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.
	*	Electric portfolio derivatives consist of electric generation fuel of 166.0 million One Million British Thermal Units (MMBtus) and purchased electricity of 3.9 million Megawatt Hours (MWhs) at March 31, 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 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
	March 31, 2015
		Gross Amount Recognized in the Statement of Financial Position 1			Gross Amounts Offset in the Statement of Financial Position			Net of Amounts Presented in the Statement of Financial Position			Gross Amounts Not Offset in the Statement of Financial Position
	(Dollars in Thousands)										Commodity Contracts			Cash Collateral Received/Posted			Net Amount
	Assets
	Energy Derivative Contracts	$	13,334		$	—		$	13,334		$	(12,152	)	$	—		$	1,182
	Liabilities
	Energy Derivative Contracts	186,852			—			186,852			(12,152		)	—			174,700
	Interest Rate Swaps 2	9,397			—			9,397			$	—		—			9,397
	Puget Energy and Puget Sound Energy
	December 31, 2014
		Gross Amount Recognized in the Statement of Financial Position 1			Gross Amounts Offset in the Statement of Financial Position			Net of Amounts Presented in the Statement of Financial Position			Gross Amounts Not Offset in the Statement of Financial Position
	(Dollars in Thousands)										Commodity Contracts			Cash Collateral Received/Posted			Net Amount
	Assets
	Energy Derivative Contracts	$	24,348		$	—		$	24,348		$	(23,066	)	$	—		$	1,282
	Liabilities
	Energy Derivative Contracts	196,035			—			196,035			(23,066		)	(20		)	172,949
	Interest Rate Swaps 2	9,073			—			9,073			—			—			9,073
	_______________
	1	All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of 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 Normal Purchase Normal Sale (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 occurred 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		Three Months Ended March 31,
	(Dollars in Thousands)	Location	2015			2014
	Interest rate contracts:	Non-hedged interest rate swap	$	(1,975	)	$	(747	)
		(expense) income
		Interest expense	(162		)	(125		)
	Commodity contracts:
	Electric derivatives	Unrealized gain (loss) on derivative instruments, net	3,696			7,839
		Electric generation fuel	(10,662		)	7,827
		Purchased electricity	(21,884		)	5,383
	Total gain (loss) recognized in income on derivatives		$	(30,987	)	$	20,177
	Puget Sound Energy		Three Months Ended March 31,
	(Dollars in Thousands)	Location	2015			2014
	Commodity contracts:
	Electric derivatives	Unrealized gain (loss) on derivative instruments, net	$	3,152		$	7,270
		Electric generation fuel	(10,662		)	7,827
		Purchased electricity	(21,884		)	5,383
	Total gain (loss) recognized in income on derivatives		$	(29,394	)	$	20,480
	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 three months ended March 31, 2015 and 2014, cash outflows related to financing activities of $8.0 million and $8.0 million, respectively, 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 is reclassified into earnings in the same period(s) during which the hedged transaction affects 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 OCI into income:
Puget Energy		Three Months Ended March 31,
(Dollars in Thousands)	Location	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 March 31,
(Dollars in Thousands)	Location	2015			2014
Interest rate contracts:	Interest expense 1	$	(122	)	$	(122	)
Commodity contracts:
Electric derivatives	Purchased electricity	(1,055		)	(1,104		)
Total		$	(1,177	)	$	(1,226	)
_______________
1	Within the next twelve months, $0.5 million of losses in accumulated OCI 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 March 31, 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.
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 booked as contra accounts to unrealized gain (loss) positions. As of March 31, 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 March 31, 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, 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 March 31, 2015:
Puget Energy and Puget Sound Energy
Contingent Feature
	Fair Value 1			Posted			Contingent
(Dollars in Thousands)	Liability			Collateral			Collateral
Credit rating 2	$	(27,292	)	$	—		$	27,292
Requested credit for adequate assurance	(65,531		)	—			—
Forward value of contract 3	(969		)	—			—
Total	$	(93,792	)	$	—		$	27,292
_______________
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	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements
	ASC 820 established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy categorizes the inputs into three levels with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority given to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
	Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Equity securities that are also classified as cash equivalents are considered Level 1 if there are unadjusted quoted prices in active markets for identical assets or liabilities.
	Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options.
	Level 3 - Pricing inputs include significant inputs that have little or no observability as of the reporting date. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value.
	Financial assets and liabilities measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves, contract terms and prices, credit-risk adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas market from an independent external pricing service. For interest rate swaps, the Company obtains monthly mark-to-market values from an independent external pricing service for London Interbank Offered Rate (LIBOR) forward rates, which is a significant input. Some of the inputs of the interest rate swap valuations, which are less significant, include the credit standing of the counterparties, assumptions for time value and the impact of the Company's nonperformance risk of its liabilities. The Company classifies cash and cash equivalents, and restricted cash as Level 1 financial instruments due to cash being at stated value, and cash equivalents at quoted market prices.
	The Company considers its electric, natural gas and interest rate swap contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. Management's assessment was based on the trading activity in real-time and forward electric and natural gas markets. Each quarter, the Company confirms the validity of pricing-service quoted prices (e.g., Level 2 in the fair value hierarchy) used to value commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter. However, certain energy derivative instruments with maturity dates falling outside the range of observable price quotes are classified as Level 3 in the fair value hierarchy.
	Assets and Liabilities with Estimated Fair Value
	The following table presents the fair value hierarchy by level, the carrying value for cash, cash equivalents, restricted cash, notes receivable and short-term debt. The carrying values below are representative of fair values due to the short-term nature of these financial instruments.
		Carrying / Fair Value									Carrying / Fair Value
	Puget Energy	At March 31, 2015									At December 31, 2014
	(Dollars in Thousands)	Level 1			Level 2			Total			Level 1			Level 2			Total
	Assets:
	Cash and Cash Equivalents	$	19,119		$	—		$	19,119		$	37,527		$	—		$	37,527
	Restricted Cash	16,801			—			16,801			32,863			—			32,863
	Notes Receivable and Other Investments	—			49,587			49,587			—			53,503			53,503
	Total assets	$	35,920		$	49,587		$	85,507		$	70,390		$	53,503		$	123,893
	Liabilities:
	Short-term debt	$	—		$	—		$	—		$	85,000		$	—		$	85,000
	Total liabilities	$	—		$	—		$	—		$	85,000		$	—		$	85,000
		Carrying / Fair Value									Carrying / Fair Value
	Puget Sound Energy	At March 31, 2015									At December 31, 2014
	(Dollars in Thousands)	Level 1			Level 2			Total			Level 1			Level 2			Total
	Assets:
	Cash and Cash Equivalents	$	18,479		$	—		$	18,479		$	37,466		$	—		$	37,466
	Restricted Cash	16,801			—			16,801			32,863			—			32,863
	Notes Receivable and Other Investments	—			49,587			49,587			—			53,503			53,503
	Total assets	$	35,280		$	49,587		$	84,867		$	70,329		$	53,503		$	123,832
	Liabilities:
	Short-term debt	$	—		$	—		$	—		$	85,000		$	—		$	85,000
	Short-term debt owed to parent	—			28,933			28,933			—			28,933			28,933
	Total liabilities	$	—		$	28,933		$	28,933		$	85,000		$	28,933		$	113,933
	The fair value of the junior subordinated and long-term notes were estimated using the discounted cash flow method with U.S. Treasury yields and Company credit spreads as inputs, interpolating to the maturity date of each issue. Carrying values and estimated fair values were as follows:
	Puget Energy		March 31, 2015						December 31, 2014
	(Dollars in Thousands)	Level	Carrying			Fair			Carrying			Fair
			Value			Value			Value			Value
	Liabilities:
	Junior subordinated notes	2	$	250,000		$	269,020		$	250,000		$	276,235
	Long-term debt (fixed-rate), net of discount	2	4,697,391			6,278,183			4,694,608			6,083,554
	Long-term debt (variable-rate)	2	299,000			299,000			299,000			299,000
	Total		$	5,246,391		$	6,846,203		$	5,243,608		$	6,658,789
	Puget Sound Energy		March 31, 2015						December 31, 2014
	(Dollars in Thousands)	Level	Carrying			Fair			Carrying			Fair
			Value			Value			Value			Value
	Liabilities:
	Junior subordinated notes	2	$	250,000		$	269,020		$	250,000		$	276,235
	Long-term debt (fixed-rate), net of discount	2	3,513,259			4,607,614			3,513,259			4,437,473
	Total		$	3,763,259		$	4,876,634		$	3,763,259		$	4,713,708
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	The following tables present the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis:
	Puget Energy	Fair Value									Fair Value
		At March 31, 2015									At December 31, 2014
	(Dollars in Thousands)	Level 2			Level 3			Total			Level 2			Level 3			Total
	Interest rate derivative instruments	$	9,397		$	—		$	9,397		$	9,073		$	—		$	9,073
	Total derivative liabilities	$	9,397		$	—		$	9,397		$	9,073		$	—		$	9,073
	Puget Energy and	Fair Value									Fair Value
	Puget Sound Energy	At March 31, 2015									At December 31, 2014
	(Dollars in Thousands)	Level 2			Level 3			Total			Level 2			Level 3			Total
	Assets:
	Electric derivative instruments	$	2,487		$	3,157		$	5,644		$	1,654		$	3,168		$	4,822
	Natural gas derivative instruments	6,158			1,532			7,690			18,064			1,462			19,526
	Total assets	$	8,645		$	4,689		$	13,334		$	19,718		$	4,630		$	24,348
	Liabilities:
	Electric derivative instruments	$	84,596		$	19,248		$	103,844		$	91,998		$	15,230		$	107,228
Natural gas derivative instruments	79,875			3,133			83,008			85,305			3,502			88,807
Total liabilities	$	164,471		$	22,381		$	186,852		$	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	Three Months Ended March 31,
Puget Sound Energy
Level 3 Roll-Forward Net Asset/(Liability)	2015									2014
(Dollars in Thousands)	Electric			Gas			Total			Electric			Gas			Total
Balance at beginning of period	$	(12,062	)	$	(2,040	)	$	(14,102	)	$	(15,421	)	$	(361	)	$	(15,782	)
Changes during period:
Realized and unrealized energy derivatives:
Included in earnings 1	(5,037		)	—			(5,037		)	(2,745		)	—			(2,745		)
Included in regulatory assets / liabilities	—			125			125			—			259			259
Settlements 2	113			91			204			321			(410		)	(89		)
Transferred into Level 3	(787		)	—			(787		)	3,100			(585		)	2,515
Transferred out of Level 3	1,682			223			1,905			139			(6		)	133
Balance at end of period	$	(16,091	)	$	(1,601	)	$	(17,692	)	$	(14,606	)	$	(1,103	)	$	(15,709	)
_______________
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 $(5.0) million and $(4.6) million for the three months ended March 31, 2015 and 2014, respectively.
2	The Company had no purchases, sales or issuances during the reported periods.
Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company's consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company's consolidated statements of income.
In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company's commodity contracts extend beyond what is considered observable as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next, and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month, and reported in the Level 3 Roll-Forward table above. The Company did not have any transfers between Level 2 and Level 1 during the 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. Below are the forward price ranges for the Company's purchased commodity contracts as of March 31, 2015:
	Fair Value								Range
(Dollars in Thousands)	Assets 1			Liabilities 1			Valuation Technique	Unobservable Input	Low	High	Weighted Average
Electric	$	3,157		$	19,248		Discounted cash flow	Power Prices	$14.63 per MWh	$33.87 per MWh	$30.43 per MWh
Natural gas	$	1,532		$	3,133		Discounted cash flow	Natural Gas Prices	$1.71 per MMBtu	$3.66 per MMBtu	$2.85 per MMBtu
_______________
1	The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.
Below are the forward price ranges for the Company's purchased commodity contracts, as of December 31, 2014:
	Fair Value								Range
(Dollars in Thousands)	Assets 1			Liabilities 1			Valuation Technique	Unobservable Input	Low	High	Weighted Average
Electric	$	3,168		$	15,230		Discounted cash flow	Power Prices	$21.79 per MWh	$35.46 per MWh	$32.89 per MWh
Natural gas	$	1,462		$	3,502		Discounted cash flow	Natural Gas Prices	$3.11 per MMBtu	$3.83 per MMBtu	$3.28 per MMBtu
_______________
1	The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.
The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. At March 31, 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 $4.6 million and $3.9 million, respectively.
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 March 31, 2015, Puget Energy completed a valuation and impairment test of its purchased power contracts classified as intangible assets. The valuation indicated a fair value of $417.3 million with an impairment to the Wells hydro contract. As of March 31, 2015, the carrying value for this contract was $59.2 million and its fair value on a discounted basis was $49.3 million, thereby requiring a write-down of $9.9 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 7% from December 31, 2014 to March 31, 2015, which caused the impairments.
Below are significant unobservable inputs used in estimating the impaired long term power purchase contract's fair value on March 31, 2015:
Valuation Technique	Unobservable Input	Low			High			Average
Discounted cash flow	Power prices	$	19.54	per MWh	$	32.17	per MWh	$	27.23	per MWh
Discounted cash flow	Power contract costs (in thousands)	4,129		per qtr	4,783		per qtr	4,493		per qtr
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 intangible asset contract. As of December 31, 2014, the carrying value for this intangible asset contract was $65.3 million and its fair value on a discounted basis was determined to be an asset of $62.1 million, thereby requiring a write-down of $3.2 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 December 31, 2014:
Valuation Technique	Unobservable Input	Low			High			Average
Discounted cash flow	Power prices	$	19.3	per MWh	$	37.06	per MWh	$	29.53	per MWh
Discounted cash flow	Power contract costs (in thousands)	3,015		per qtr	4,783		per qtr	4,469		per qtr
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.

Retirement_Benefits

Retirement Benefits	3 Months Ended
	Mar. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Retirement Benefits
		Retirement Benefits
	PSE has a defined benefit pension plan covering substantially all PSE employees.  Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates.  All new United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry (UA) employees hired on or after January 1, 2014, as well as all new International Brotherhood of Electrical Workers Local Union 77 (IBEW) hired on or after December 12, 2014 and non-represented employees hired on or after January 1, 2014 who elect to accumulate the Company contribution in the cash balance formula portion of the pension plan, will receive annual pay credits of 4% each year. They will also receive interest credits like other participants in the cash balance pension formula of the pension plan, which are at least 1% per quarter. When a newly-hired employee with a vested cash balance formula 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 formula of the 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 net periodic benefit cost for the three months ended March 31, 2015 and 2014:
	Puget Energy	Qualified						SERP						Other
		Pension Benefits						Pension Benefits						Benefits
		Three Months Ended March 31,
	(Dollars in Thousands)	2015			2014			2015			2014			2015			2014
	Components of net periodic benefit cost:
	Service cost	$	5,472		$	4,512		$	277		$	261		$	33		$	29
	Interest cost	7,107			7,055			570			577			161			183
	Expected return on plan assets	(11,402		)	(10,721		)	—			—			(133		)	(133		)
	Amortization of prior service	(495		)	(495		)	11			11			—			—
	cost
	Amortization of net loss	981			—			410			228			(15		)	(66		)
	(gain)
	Net periodic benefit cost	$	1,663		$	351		$	1,268		$	1,077		$	46		$	13
	Puget Sound Energy	Qualified						SERP						Other
		Pension Benefits						Pension Benefits						Benefits
		Three Months Ended March 31,
	(Dollars in Thousands)	2015			2014			2015			2014			2015			2014
	Components of net periodic benefit cost:
	Service cost	$	5,472		$	4,512		$	277		$	261		$	33		$	29
	Interest cost	7,107			7,055			570			577			161			183
	Expected return on plan assets	(11,508		)	(10,919		)	—			—			(133		)	(133		)
	Amortization of prior service	(393		)	(393		)	11			11			1			1
	cost
	Amortization of net loss	5,136			3,239			530			365			(83		)	(143		)
	(gain)
	Net periodic benefit cost	$	5,814		$	3,494		$	1,388		$	1,214		$	(21	)	$	(63	)
	The following table summarizes the Company’s change in benefit obligation for the periods ended March 31, 2015 and December 31, 2014:
	Puget Energy and	Qualified						SERP						Other
	Puget Sound Energy	Pension Benefits						Pension Benefits						Benefits
		Three Months Ended			Year			Three Months Ended			Year			Three Months Ended			Year
					Ended						Ended						Ended
	(Dollars in Thousands)	March 31,			December 31,			March 31,			December 31,			March 31,			December 31,
		2015			2014			2015			2014			2015			2014
	Change in benefit obligation:
	Benefit obligation at beginning of period	$	690,194		$	573,317		$	55,855		$	47,279		$	15,688		$	14,939
	Service cost	5,472			17,437			277			1,042			33			112
	Interest cost	7,107			28,039			570			2,310			161			684
	Amendment	—			—			—			—			—			—
	Actuarial loss (gain)	—			104,618			—			7,162			—			1,108
	Benefits paid	(10,275		)	(33,217		)	(2,103		)	(1,938		)	(348		)	(1,424		)
	Medicare part D subsidy	—			—			—			—			56			269
	received
	Benefit obligation at end of period	$	692,498		$	690,194		$	54,599		$	55,855		$	15,590		$	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 $0.5 million, respectively. During the three months ended March 31, 2015, the Company contributed $4.5 million, $2.1 million, and $0.3 million to fund the qualified pension plan, SERP and the other postretirement plan, respectively.

Regulation_and_Rates

Regulation and Rates	3 Months Ended
	Mar. 31, 2015
Regulation and Rates [Abstract]
Regulation and Rates	Regulation and Rates
	On June 25, 2013, the Washington Commission approved PSE's electric and natural gas decoupling mechanism and Expedited Rate Filing (ERF) tariff filings, effective July 1, 2013. The allowed decoupling revenue per customer for the recovery of delivery system costs will subsequently increase by 3.0% for the electric customers and 2.2% for the gas customers on January 1 of each year, until the conclusion of PSE's next general rate case (GRC). Rate increases are subject to a cap of 3.0% of total revenue for customers.
	The ERF filings also provided for the collection of property taxes through a property tax tracker mechanism. The property tax rate tracker will initially produce no incremental revenue, but is intended to reduce regulatory lag associated with the recovery of future increases in property tax expenses. 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 (ROE) of 9.8% .
	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 argued that the order violated various procedural and substantive requirements of the Washington Administrative Procedure Act, and so requested that it be vacated and that the matter be remanded to the Washington Commission. Oral arguments regarding this matter were held on May 9, 2014. On June 25, 2014, the court issued a 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 GRC, but reversed and remanded the cost of equity for further adjudication consistent with the court's decision. Evidentiary hearings regarding ROE were held in February 2015, and initial briefs and reply briefs were filed in March 2015. An order is anticipated in the first half of 2015.
	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 0.6% annually, and a rate increase for natural gas 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 on 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 February 27, 2015, PSE filed a request with the Washington Commission to change rates under its electric and natural gas conservation riders, effective May 1, 2015.  The proposed rate change incorporates the effects of changes in the annual conservation budgets as well as true-ups to the rate from the prior year.  The proposed rate change represents a rate increase for electric of $4.2 million, or 0.2% annually, and a rate increase for natural gas of $2.3 million, or 0.2% annually.
	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 of $6.5 million, or 0.3% annually, and a rate decrease for natural gas of $0.9 million, or 0.1% annually.
	On March 27, 2015, PSE, Public Counsel and Washington Commission Staff filed a settlement proposing changes to the current PCA mechanism.  The settling parties filed joint testimony supporting the settlement agreement on April 3, 2015. The settlement agreement will require Commission approval. The settlement agreement would not take effect until January 1, 2017. Key components of the settlement will include the following changes to the PCA mechanism:
			Company's Share				Customers' Share
	Sharing Bands		Over		Under		Over		Under
	+/-	$17 million	100	%	100	%	—	%	—	%
	+/-	23 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 general rate case;
	•	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 rates go into effect for a PCORC filing;
	•	Establishing a five-year moratorium on changes to the PCA/PCORC.
	On March 31, 2015, PSE petitioned the Washington Commission to allow PSE to change the methodology of how decoupling deferrals are calculated going forward and adjust deferrals calculated in 2014. The change is to ensure the prior years’ accumulated decoupling deferrals will not be included in the calculation of the current year decoupling deferrals. The change in methodology was approved by the Washington Commission on April 22, 2015. The effect of the methodology change is a reduction of approximately $12.0 million previously recognized revenue from May through December of 2014. The changes represent a rate increase for decoupled revenue 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, the Company is subject to an earnings test whereby PSE will share with customers 50% of earnings above its authorized 7.77% return on rate base.  PSE exceeded this 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 is reflected as a reduction to the natural gas rate increases noted above.
	The Company is limited to 3.0% annual decoupling-related cap on total revenue.  The amount of deferral that won't be 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. This amount will be included in customer rates in May 2016 and collected by December 2016.

Litigation_litigation_disclosu

Litigation litigation disclosure (Notes)	3 Months Ended
	Mar. 31, 2015
Text Block [Abstract]
Legal Matters and Contingencies [Text Block]	Litigation
	Colstrip
	PSE has a 50% ownership interest in Colstrip Units 1 and 2, and a 25% interest in Colstrip Units 3 and 4. On March 6, 2013, the Sierra Club and the Montana Environmental Information Center (MEIC) filed a Clean Air Act citizen suit against all Colstrip owners (including PSE) in the U.S. District Court, District of Montana. Based on a second amended complaint filed 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 two of the seven projects, leaving a total of five 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. Discovery in the case is ongoing. The liability trial is currently set for November 2015, and a date for the remedy trial has yet to be determined. PSE is litigating the allegations set forth in the complaint, and as such, it is not reasonably possible to estimate the outcome of this matter.
	Other Proceedings
	The Company is also involved in litigation relating to claims arising out of its operations in the normal course of business. The Company has recorded reserves of $1.5 million and $1.7 million relating to these claims as of March 31, 2015 and December 31, 2014, respectively.

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income (Notes)	3 Months Ended
	Mar. 31, 2015
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	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 three months ended March 31, 2015:
	Puget Energy	Net unrealized gain (loss) and prior service cost on pension plans			Net unrealized gain (loss) on energy derivative instruments			Net unrealized gain (loss) on interest rate swaps
	Changes in AOCI, net of tax
	(Dollars in Thousands)										Total
	December 31, 2014	$	(36,710	)	$	(333	)	$	—		$	(37,043	)
	Other comprehensive income (loss) before reclassifications				—			—			—
	Amounts reclassified from accumulated other comprehensive income (loss), net of tax	579			333			—			912
	Net current-period other comprehensive income (loss)	579			333			—			912
	March 31, 2015	$	(36,131	)	$	—		$	—		$	(36,131	)
	Puget Sound Energy	Net unrealized gain (loss) and prior service cost on pension plans			Net unrealized gain (loss) on energy derivative instruments			Net unrealized gain (loss) on treasury interest rate swaps
	Changes in AOCI, net of tax
	(Dollars in Thousands)										Total
	December 31, 2014	$	(164,281	)	$	(686	)	$	(5,990	)	$	(170,957	)
	Other comprehensive income (loss) before reclassifications				—			—			—
	Amounts reclassified from accumulated other comprehensive income (loss), net of tax	3,381			686			79			4,146
	Net current-period other comprehensive income (loss)	3,381			686			79			4,146
	March 31, 2015	$	(160,900	)	$	—		$	(5,911	)	$	(166,811	)
	Details about these reclassifications out of accumulated other comprehensive income (loss) for the three months ended March 31, 2015, and 2014, are as follows:
	Puget Energy		Three Months Ended March 31,
	(Dollars in Thousands)		2015			2014
	Details about accumulated other comprehensive income (loss) components	Affected line item in the statement where net income (loss) is presented	Amount reclassified from accumulated other comprehensive income (loss)
	Net unrealized gain (loss) and prior service cost on pension plans:
	Amortization of prior service cost	(a)	$	484		$	484
	Amortization of net gain (loss)	(a)	(1,375		)	(162		)
		Total before tax	(891		)	322
		Tax (expense) or benefit	312			(113		)
		Net of Tax	$	(579	)	$	209
	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	$	(912	)	$	(232	)
	_______________
	(a)	These accumulated OCI components are included in the computation of net periodic pension cost (see Note 5 for additional details).
	Puget Sound Energy		Three Months Ended March 31,
	(Dollars in Thousands)		2015			2014
	Details about accumulated other comprehensive income (loss) components	Affected line item in the statement where net income (loss) is presented	Amount reclassified from accumulated other comprehensive income (loss)
	Net unrealized gain (loss) and prior service cost on pension plans:
	Amortization of prior service cost	(a)	$	381		$	381
	Amortization of net gain (loss)	(a)	(5,583		)	(3,461		)
		Total before tax	(5,202		)	(3,080		)
		Tax (expense) or benefit	1,821			1,079
		Net of Tax	$	(3,381	)	$	(2,001	)
	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		)
		Tax (expense) or benefit	43			43
		Net of Tax	$	(79	)	$	(79	)
	Total reclassification for the period	Net of Tax	$	(4,146	)	$	(2,798	)
	_______________
	(a)	These accumulated OCI components are included in the computation of net periodic pension cost (see Note 5 for additional details).

Summary_of_Significant_Account

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]	Summary of Significant Accounting Policies
	Basis of Presentation
	Puget Energy is an energy services holding company that owns PSE.  PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region.  Following the merger with Puget Holdings LLC (Puget Holdings) in 2009, Puget Energy is an indirect wholly-owned subsidiary of Puget Holdings.
	The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiary, PSE.  PSE’s consolidated financial statements include the accounts of PSE and its subsidiary, Puget Western, Inc.  Puget Energy and PSE are collectively referred to herein as “the Company.”  The consolidated financial statements are presented after elimination of intercompany transactions.  PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any purchase accounting adjustments.
	The consolidated financial statements contained in this Form 10-Q are unaudited.  In the respective opinions of the management of Puget Energy and PSE, all adjustments necessary for a fair statement of the results for the interim periods have been reflected and were of a normal recurring nature.  These consolidated financial statements should be read in conjunction with the audited financial statements (and the Combined Notes thereto) included in the combined Puget Energy and PSE Annual Report on Form 10-K for the year ended December 31, 2014.
	The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period.  Actual results could differ from those estimates.
	PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $69.5 million and $77.9 million for the three months ended March 31, 2015 and 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.
	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 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 years 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 record a reserve against the decoupling revenue and regulatory asset balance. Revenues associated with power costs under the Power Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA) rates are excluded from the decoupling mechanism.
Basis of Presentation	Summary of Significant Accounting Policies
	Basis of Presentation
	Puget Energy is an energy services holding company that owns PSE.  PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region.  Following the merger with Puget Holdings LLC (Puget Holdings) in 2009, Puget Energy is an indirect wholly-owned subsidiary of Puget Holdings.
	The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiary, PSE.  PSE’s consolidated financial statements include the accounts of PSE and its subsidiary, Puget Western, Inc.  Puget Energy and PSE are collectively referred to herein as “the Company.”  The consolidated financial statements are presented after elimination of intercompany transactions.  PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any purchase accounting adjustments.
	The consolidated financial statements contained in this Form 10-Q are unaudited.  In the respective opinions of the management of Puget Energy and PSE, all adjustments necessary for a fair statement of the results for the interim periods have been reflected and were of a normal recurring nature.  These consolidated financial statements should be read in conjunction with the audited financial statements (and the Combined Notes thereto) included in the combined Puget Energy and PSE Annual Report on Form 10-K for the year ended December 31, 2014.
	The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period.  Actual results could differ from those estimates.
Revenue Recognition	PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $69.5 million and $77.9 million for the three months ended March 31, 2015 and 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.
	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 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 years 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 record a reserve against the decoupling revenue and regulatory asset balance. Revenues associated with power costs under the Power Cost Adjustment (PCA) mechanism and Purchased Gas Adjustment (PGA) rates are excluded from the decoupling mechanism.

Accounting_for_Derivative_Inst1

Accounting for Derivative Instruments and Hedging Activities (Tables)	3 Months Ended
	Mar. 31, 2015
Derivative [Line Items]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	The following table presents the volumes, fair values and locations of the Company's derivative instruments recorded on the balance sheets:
	Puget Energy and	March 31, 2015							December 31, 2014
	Puget Sound Energy
	(Dollars in Thousands)	Volumes	Assets 1			Liabilities 2			Volumes	Assets 1			Liabilities 2
	Interest rate swap derivatives 3	$450 million	$	—		$	9,397		$450 million	$	—		$	9,073
	Electric portfolio derivatives	*	5,644			103,844			*	4,822			107,228
	Natural gas derivatives (MMBtus) 4	348.2 million	7,690			83,008			360.4 million	19,526			88,807
	Total derivative contracts		$	13,334		$	196,249			$	24,348		$	205,108
	Current		$	9,806		$	138,873			$	21,178		$	142,195
	Long-term		3,528			57,376				3,170			62,913
	Total derivative contracts		$	13,334		$	196,249			$	24,348		$	205,108
	_______________
	1	Balance sheet location: Current and Long-term Unrealized gain on derivative instruments.
	2	Balance sheet location: Current and Long-term Unrealized loss on derivative instruments.
	3	Interest rate swap contracts are only held at Puget Energy.
	4	All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations” (ASC 980) due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.
	*	Electric portfolio derivatives consist of electric generation fuel of 166.0 million One Million British Thermal Units (MMBtus) and purchased electricity of 3.9 million Megawatt Hours (MWhs) at March 31, 2015, and 140.2 million MMBtus and 5.4 million MWhs at December 31, 2014.
Offsetting Assets and Liabilities	The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities:
	Puget Energy and Puget Sound Energy
	March 31, 2015
		Gross Amount Recognized in the Statement of Financial Position 1			Gross Amounts Offset in the Statement of Financial Position			Net of Amounts Presented in the Statement of Financial Position			Gross Amounts Not Offset in the Statement of Financial Position
	(Dollars in Thousands)										Commodity Contracts			Cash Collateral Received/Posted			Net Amount
	Assets
	Energy Derivative Contracts	$	13,334		$	—		$	13,334		$	(12,152	)	$	—		$	1,182
	Liabilities
	Energy Derivative Contracts	186,852			—			186,852			(12,152		)	—			174,700
	Interest Rate Swaps 2	9,397			—			9,397			$	—		—			9,397
	Puget Energy and Puget Sound Energy
	December 31, 2014
		Gross Amount Recognized in the Statement of Financial Position 1			Gross Amounts Offset in the Statement of Financial Position			Net of Amounts Presented in the Statement of Financial Position			Gross Amounts Not Offset in the Statement of Financial Position
	(Dollars in Thousands)										Commodity Contracts			Cash Collateral Received/Posted			Net Amount
	Assets
	Energy Derivative Contracts	$	24,348		$	—		$	24,348		$	(23,066	)	$	—		$	1,282
	Liabilities
	Energy Derivative Contracts	196,035			—			196,035			(23,066		)	(20		)	172,949
	Interest Rate Swaps 2	9,073			—			9,073			—			—			9,073
	_______________
	1	All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of 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 OCI into income:
	Puget Energy		Three Months Ended March 31,
	(Dollars in Thousands)	Location	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 March 31, 2015:
	Puget Energy and Puget Sound Energy
	Contingent Feature
		Fair Value 1			Posted			Contingent
	(Dollars in Thousands)	Liability			Collateral			Collateral
	Credit rating 2	$	(27,292	)	$	—		$	27,292
	Requested credit for adequate assurance	(65,531		)	—			—
	Forward value of contract 3	(969		)	—			—
	Total	$	(93,792	)	$	—		$	27,292
	_______________
	1	Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable.
	2	Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral.
	3	Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.
Parent Company [Member]
Derivative [Line Items]
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance	The following tables present the effect and locations of the Company's derivatives not designated as hedging instruments, recorded on the statements of income:
	Puget Energy		Three Months Ended March 31,
	(Dollars in Thousands)	Location	2015			2014
	Interest rate contracts:	Non-hedged interest rate swap	$	(1,975	)	$	(747	)
		(expense) income
		Interest expense	(162		)	(125		)
	Commodity contracts:
	Electric derivatives	Unrealized gain (loss) on derivative instruments, net	3,696			7,839
		Electric generation fuel	(10,662		)	7,827
		Purchased electricity	(21,884		)	5,383
	Total gain (loss) recognized in income on derivatives		$	(30,987	)	$	20,177
Subsidiaries [Member]
Derivative [Line Items]
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance
	Puget Sound Energy		Three Months Ended March 31,
	(Dollars in Thousands)	Location	2015			2014
	Commodity contracts:
	Electric derivatives	Unrealized gain (loss) on derivative instruments, net	$	3,152		$	7,270
		Electric generation fuel	(10,662		)	7,827
		Purchased electricity	(21,884		)	5,383
	Total gain (loss) recognized in income on derivatives		$	(29,394	)	$	20,480
Schedule of Derivative Instruments, Effect on Other Comprehensive Income (Loss)
	Puget Sound Energy		Three Months Ended March 31,
	(Dollars in Thousands)	Location	2015			2014
	Interest rate contracts:	Interest expense 1	$	(122	)	$	(122	)
	Commodity contracts:
	Electric derivatives	Purchased electricity	(1,055		)	(1,104		)
	Total		$	(1,177	)	$	(1,226	)

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, by Balance Sheet Grouping	The following table presents the fair value hierarchy by level, the carrying value for cash, cash equivalents, restricted cash, notes receivable and short-term debt. The carrying values below are representative of fair values due to the short-term nature of these financial instruments.
		Carrying / Fair Value									Carrying / Fair Value
	Puget Energy	At March 31, 2015									At December 31, 2014
	(Dollars in Thousands)	Level 1			Level 2			Total			Level 1			Level 2			Total
	Assets:
	Cash and Cash Equivalents	$	19,119		$	—		$	19,119		$	37,527		$	—		$	37,527
	Restricted Cash	16,801			—			16,801			32,863			—			32,863
	Notes Receivable and Other Investments	—			49,587			49,587			—			53,503			53,503
	Total assets	$	35,920		$	49,587		$	85,507		$	70,390		$	53,503		$	123,893
	Liabilities:
	Short-term debt	$	—		$	—		$	—		$	85,000		$	—		$	85,000
	Total liabilities	$	—		$	—		$	—		$	85,000		$	—		$	85,000
		Carrying / Fair Value									Carrying / Fair Value
	Puget Sound Energy	At March 31, 2015									At December 31, 2014
	(Dollars in Thousands)	Level 1			Level 2			Total			Level 1			Level 2			Total
	Assets:
	Cash and Cash Equivalents	$	18,479		$	—		$	18,479		$	37,466		$	—		$	37,466
	Restricted Cash	16,801			—			16,801			32,863			—			32,863
	Notes Receivable and Other Investments	—			49,587			49,587			—			53,503			53,503
	Total assets	$	35,280		$	49,587		$	84,867		$	70,329		$	53,503		$	123,832
	Liabilities:
	Short-term debt	$	—		$	—		$	—		$	85,000		$	—		$	85,000
	Short-term debt owed to parent	—			28,933			28,933			—			28,933			28,933
	Total liabilities	$	—		$	28,933		$	28,933		$	85,000		$	28,933		$	113,933
Fair Value Inputs, Liabilities, Quantitative Information	The fair value of the junior subordinated and long-term notes were estimated using the discounted cash flow method with U.S. Treasury yields and Company credit spreads as inputs, interpolating to the maturity date of each issue. Carrying values and estimated fair values were as follows:
	Puget Energy		March 31, 2015						December 31, 2014
	(Dollars in Thousands)	Level	Carrying			Fair			Carrying			Fair
			Value			Value			Value			Value
	Liabilities:
	Junior subordinated notes	2	$	250,000		$	269,020		$	250,000		$	276,235
	Long-term debt (fixed-rate), net of discount	2	4,697,391			6,278,183			4,694,608			6,083,554
	Long-term debt (variable-rate)	2	299,000			299,000			299,000			299,000
	Total		$	5,246,391		$	6,846,203		$	5,243,608		$	6,658,789
	Puget Sound Energy		March 31, 2015						December 31, 2014
	(Dollars in Thousands)	Level	Carrying			Fair			Carrying			Fair
			Value			Value			Value			Value
	Liabilities:
	Junior subordinated notes	2	$	250,000		$	269,020		$	250,000		$	276,235
	Long-term debt (fixed-rate), net of discount	2	3,513,259			4,607,614			3,513,259			4,437,473
	Total		$	3,763,259		$	4,876,634		$	3,763,259		$	4,713,708
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation	The following table presents the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy:
	Puget Energy and	Three Months Ended March 31,
	Puget Sound Energy
	Level 3 Roll-Forward Net Asset/(Liability)	2015									2014
	(Dollars in Thousands)	Electric			Gas			Total			Electric			Gas			Total
	Balance at beginning of period	$	(12,062	)	$	(2,040	)	$	(14,102	)	$	(15,421	)	$	(361	)	$	(15,782	)
	Changes during period:
	Realized and unrealized energy derivatives:
	Included in earnings 1	(5,037		)	—			(5,037		)	(2,745		)	—			(2,745		)
	Included in regulatory assets / liabilities	—			125			125			—			259			259
	Settlements 2	113			91			204			321			(410		)	(89		)
	Transferred into Level 3	(787		)	—			(787		)	3,100			(585		)	2,515
	Transferred out of Level 3	1,682			223			1,905			139			(6		)	133
	Balance at end of period	$	(16,091	)	$	(1,601	)	$	(17,692	)	$	(14,606	)	$	(1,103	)	$	(15,709	)
	_______________
	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 $(5.0) million and $(4.6) million for the three months ended March 31, 2015 and 2014, respectively.
	2	The Company had no purchases, sales or issuances during the reported periods.
Fair Value Inputs, Assets and Liabilities, Quantitative Information	Below are the forward price ranges for the Company's purchased commodity contracts as of March 31, 2015:
		Fair Value								Range
	(Dollars in Thousands)	Assets 1			Liabilities 1			Valuation Technique	Unobservable Input	Low	High	Weighted Average
	Electric	$	3,157		$	19,248		Discounted cash flow	Power Prices	$14.63 per MWh	$33.87 per MWh	$30.43 per MWh
	Natural gas	$	1,532		$	3,133		Discounted cash flow	Natural Gas Prices	$1.71 per MMBtu	$3.66 per MMBtu	$2.85 per MMBtu
	_______________
	1	The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.
	Below are the forward price ranges for the Company's purchased commodity contracts, as of December 31, 2014:
		Fair Value								Range
	(Dollars in Thousands)	Assets 1			Liabilities 1			Valuation Technique	Unobservable Input	Low	High	Weighted Average
	Electric	$	3,168		$	15,230		Discounted cash flow	Power Prices	$21.79 per MWh	$35.46 per MWh	$32.89 per MWh
	Natural gas	$	1,462		$	3,502		Discounted cash flow	Natural Gas Prices	$3.11 per MMBtu	$3.83 per MMBtu	$3.28 per MMBtu
	_______________
	1	The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.
	The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. At March 31, 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 $4.6 million and $3.9 million, respectively.
	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 March 31, 2015, Puget Energy completed a valuation and impairment test of its purchased power contracts classified as intangible assets. The valuation indicated a fair value of $417.3 million with an impairment to the Wells hydro contract. As of March 31, 2015, the carrying value for this contract was $59.2 million and its fair value on a discounted basis was $49.3 million, thereby requiring a write-down of $9.9 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 7% from December 31, 2014 to March 31, 2015, which caused the impairments.
	Below are significant unobservable inputs used in estimating the impaired long term power purchase contract's fair value on March 31, 2015:
	Valuation Technique	Unobservable Input	Low			High			Average
	Discounted cash flow	Power prices	$	19.54	per MWh	$	32.17	per MWh	$	27.23	per MWh
	Discounted cash flow	Power contract costs (in thousands)	4,129		per qtr	4,783		per qtr	4,493		per qtr
	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 intangible asset contract. As of December 31, 2014, the carrying value for this intangible asset contract was $65.3 million and its fair value on a discounted basis was determined to be an asset of $62.1 million, thereby requiring a write-down of $3.2 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 December 31, 2014:
	Valuation Technique	Unobservable Input	Low			High			Average
	Discounted cash flow	Power prices	$	19.3	per MWh	$	37.06	per MWh	$	29.53	per MWh
	Discounted cash flow	Power contract costs (in thousands)	3,015		per qtr	4,783		per qtr	4,469		per qtr
	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.
Parent Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following tables present the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis:
	Puget Energy	Fair Value									Fair Value
		At March 31, 2015									At December 31, 2014
	(Dollars in Thousands)	Level 2			Level 3			Total			Level 2			Level 3			Total
	Interest rate derivative instruments	$	9,397		$	—		$	9,397		$	9,073		$	—		$	9,073
	Total derivative liabilities	$	9,397		$	—		$	9,397		$	9,073		$	—		$	9,073
Subsidiaries [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis
	Puget Energy and	Fair Value									Fair Value
	Puget Sound Energy	At March 31, 2015									At December 31, 2014
	(Dollars in Thousands)	Level 2			Level 3			Total			Level 2			Level 3			Total
	Assets:
	Electric derivative instruments	$	2,487		$	3,157		$	5,644		$	1,654		$	3,168		$	4,822
	Natural gas derivative instruments	6,158			1,532			7,690			18,064			1,462			19,526
	Total assets	$	8,645		$	4,689		$	13,334		$	19,718		$	4,630		$	24,348
	Liabilities:
	Electric derivative instruments	$	84,596		$	19,248		$	103,844		$	91,998		$	15,230		$	107,228
	Natural gas derivative instruments	79,875			3,133			83,008			85,305			3,502			88,807
	Total liabilities	$	164,471		$	22,381		$	186,852		$	177,303		$	18,732		$	196,035

Retirement_Benefits_Tables

Retirement Benefits (Tables)	3 Months Ended
	Mar. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Schedule of Changes in Projected Benefit Obligations	The following table summarizes the Company’s change in benefit obligation for the periods ended March 31, 2015 and December 31, 2014:
	Puget Energy and	Qualified						SERP						Other
	Puget Sound Energy	Pension Benefits						Pension Benefits						Benefits
		Three Months Ended			Year			Three Months Ended			Year			Three Months Ended			Year
					Ended						Ended						Ended
	(Dollars in Thousands)	March 31,			December 31,			March 31,			December 31,			March 31,			December 31,
		2015			2014			2015			2014			2015			2014
	Change in benefit obligation:
	Benefit obligation at beginning of period	$	690,194		$	573,317		$	55,855		$	47,279		$	15,688		$	14,939
	Service cost	5,472			17,437			277			1,042			33			112
	Interest cost	7,107			28,039			570			2,310			161			684
	Amendment	—			—			—			—			—			—
	Actuarial loss (gain)	—			104,618			—			7,162			—			1,108
	Benefits paid	(10,275		)	(33,217		)	(2,103		)	(1,938		)	(348		)	(1,424		)
	Medicare part D subsidy	—			—			—			—			56			269
	received
	Benefit obligation at end of period	$	692,498		$	690,194		$	54,599		$	55,855		$	15,590		$	15,688
Parent Company [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Schedule of Net Benefit Costs	The following tables summarize the Company’s net periodic benefit cost for the three months ended March 31, 2015 and 2014:
	Puget Energy	Qualified						SERP						Other
		Pension Benefits						Pension Benefits						Benefits
		Three Months Ended March 31,
	(Dollars in Thousands)	2015			2014			2015			2014			2015			2014
	Components of net periodic benefit cost:
	Service cost	$	5,472		$	4,512		$	277		$	261		$	33		$	29
	Interest cost	7,107			7,055			570			577			161			183
	Expected return on plan assets	(11,402		)	(10,721		)	—			—			(133		)	(133		)
	Amortization of prior service	(495		)	(495		)	11			11			—			—
	cost
	Amortization of net loss	981			—			410			228			(15		)	(66		)
	(gain)
	Net periodic benefit cost	$	1,663		$	351		$	1,268		$	1,077		$	46		$	13
Subsidiaries [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Schedule of Net Benefit Costs
	Puget Sound Energy	Qualified						SERP						Other
		Pension Benefits						Pension Benefits						Benefits
		Three Months Ended March 31,
	(Dollars in Thousands)	2015			2014			2015			2014			2015			2014
	Components of net periodic benefit cost:
	Service cost	$	5,472		$	4,512		$	277		$	261		$	33		$	29
	Interest cost	7,107			7,055			570			577			161			183
	Expected return on plan assets	(11,508		)	(10,919		)	—			—			(133		)	(133		)
	Amortization of prior service	(393		)	(393		)	11			11			1			1
	cost
	Amortization of net loss	5,136			3,239			530			365			(83		)	(143		)
	(gain)
	Net periodic benefit cost	$	5,814		$	3,494		$	1,388		$	1,214		$	(21	)	$	(63	)

Regulation_and_Rates_Schedule_

Regulation and Rates Schedule of Graduated Sale of Rate Adjustment Mechanism (Tables)	3 Months Ended
	Mar. 31, 2015
Regulation and Rates [Abstract]
Schedule of Graduated Scale of Rate Adjustment Mechanisms [Table Text Block]	Key components of the settlement will include the following changes to the PCA mechanism:
			Company's Share				Customers' Share
	Sharing Bands		Over		Under		Over		Under
	+/-	$17 million	100	%	100	%	—	%	—	%
	+/-	23 million	35		50		65		50
	+/-	40 million	10		10		90		90

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income (Tables)	3 Months Ended
	Mar. 31, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Schedule of 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 three months ended March 31, 2015:
	Puget Energy	Net unrealized gain (loss) and prior service cost on pension plans			Net unrealized gain (loss) on energy derivative instruments			Net unrealized gain (loss) on interest rate swaps
	Changes in AOCI, net of tax
	(Dollars in Thousands)										Total
	December 31, 2014	$	(36,710	)	$	(333	)	$	—		$	(37,043	)
	Other comprehensive income (loss) before reclassifications				—			—			—
	Amounts reclassified from accumulated other comprehensive income (loss), net of tax	579			333			—			912
	Net current-period other comprehensive income (loss)	579			333			—			912
	March 31, 2015	$	(36,131	)	$	—		$	—		$	(36,131	)
Parent Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification out of Accumulated Other Comprehensive Income	Details about these reclassifications out of accumulated other comprehensive income (loss) for the three months ended March 31, 2015, and 2014, are as follows:
	Puget Energy		Three Months Ended March 31,
	(Dollars in Thousands)		2015			2014
	Details about accumulated other comprehensive income (loss) components	Affected line item in the statement where net income (loss) is presented	Amount reclassified from accumulated other comprehensive income (loss)
	Net unrealized gain (loss) and prior service cost on pension plans:
	Amortization of prior service cost	(a)	$	484		$	484
	Amortization of net gain (loss)	(a)	(1,375		)	(162		)
		Total before tax	(891		)	322
		Tax (expense) or benefit	312			(113		)
		Net of Tax	$	(579	)	$	209
	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	$	(912	)	$	(232	)
	_______________
	(a)	These accumulated OCI components are included in the computation of net periodic pension cost (see Note 5 for additional details).
Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Schedule of Accumulated Other Comprehensive Income (Loss)
	Puget Sound Energy	Net unrealized gain (loss) and prior service cost on pension plans			Net unrealized gain (loss) on energy derivative instruments			Net unrealized gain (loss) on treasury interest rate swaps
	Changes in AOCI, net of tax
	(Dollars in Thousands)										Total
	December 31, 2014	$	(164,281	)	$	(686	)	$	(5,990	)	$	(170,957	)
	Other comprehensive income (loss) before reclassifications				—			—			—
	Amounts reclassified from accumulated other comprehensive income (loss), net of tax	3,381			686			79			4,146
	Net current-period other comprehensive income (loss)	3,381			686			79			4,146
	March 31, 2015	$	(160,900	)	$	—		$	(5,911	)	$	(166,811	)
Reclassification out of Accumulated Other Comprehensive Income
	Puget Sound Energy		Three Months Ended March 31,
	(Dollars in Thousands)		2015			2014
	Details about accumulated other comprehensive income (loss) components	Affected line item in the statement where net income (loss) is presented	Amount reclassified from accumulated other comprehensive income (loss)
	Net unrealized gain (loss) and prior service cost on pension plans:
	Amortization of prior service cost	(a)	$	381		$	381
	Amortization of net gain (loss)	(a)	(5,583		)	(3,461		)
		Total before tax	(5,202		)	(3,080		)
		Tax (expense) or benefit	1,821			1,079
		Net of Tax	$	(3,381	)	$	(2,001	)
	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		)
		Tax (expense) or benefit	43			43
		Net of Tax	$	(79	)	$	(79	)
	Total reclassification for the period	Net of Tax	$	(4,146	)	$	(2,798	)
	_______________
	(a)	These accumulated OCI components are included in the computation of net periodic pension cost (see Note 5 for additional details).

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Jan. 01, 2015
	sqmi
Subsidiaries [Member]
Schedule of Capitalization, Equity [Line Items]
Area of Service Territory (in sqmi)	6,000
Excise taxes collected	$69.50	$77.90
Maximum [Member] | Decoupling Mechanism [Member]
Schedule of Capitalization, Equity [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)			3.00%

New_Accounting_Pronouncements_

New Accounting Pronouncements Debt Issuance Costs (Details) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Debt Issuance Costs [Abstract]
Debt Issuance Cost	$34.50	$35.70

Accounting_for_Derivative_Inst2

Accounting for Derivative Instruments and Hedging Activities Derivative Activity and Notional Amounts (Details) (USD $)	Mar. 31, 2015		Dec. 31, 2014
In Millions, unless otherwise specified
Interest Rate Swap [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional Amount	$450	[1]	$450	[1]
Natural Gas Derivatives [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary	348,200,000	[2]	360,400,000	[2]
Electric generation fuel [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary	166,000,000		140,200,000
Purchased Electricity [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional amount, Nonmonetary	3,900,000		5,400,000
Parent Company [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Number of Interest Rate Derivatives Held	2
[1]	3B Interest rate swap contracts are only held at Puget Energy.
[2]	4B All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, bRegulated Operationsb (ASC 980) due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.

Accounting_for_Derivative_Inst3

Accounting for Derivative Instruments and Hedging Activities Derivative Assets and Liabilities (Details) (USD $)	Mar. 31, 2015		Dec. 31, 2014
Derivative [Line Items]
Unrealized gain on derivative instruments	$9,806,000		$21,178,000
Assets, Long-term	3,528,000		3,170,000
Unrealized loss on derivative instruments	138,873,000		142,195,000
Unrealized loss on derivative instruments	57,376,000		62,913,000
Subsidiaries [Member]
Derivative [Line Items]
Unrealized gain on derivative instruments	9,806,000		21,178,000
Assets, Long-term	3,528,000		3,170,000
Unrealized loss on derivative instruments	132,694,000		135,973,000
Unrealized loss on derivative instruments	54,158,000		60,063,000
Commodity Contract [Member]
Derivative [Line Items]
Assets	13,334,000		24,348,000
Derivative Liability	186,852,000		196,035,000
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Assets	13,334,000	[1]	24,348,000	[1]
Derivative Liability	196,249,000	[2]	205,108,000	[2]
Not Designated as Hedging Instrument [Member] | Parent Company [Member]
Derivative [Line Items]
Unrealized gain on derivative instruments	9,806,000	[1]	21,178,000	[1]
Assets, Long-term	3,528,000	[1]	3,170,000	[1]
Unrealized loss on derivative instruments	138,873,000	[2]	142,195,000	[2]
Unrealized loss on derivative instruments	57,376,000	[2]	62,913,000	[2]
Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	450,000,000	[3]	450,000,000	[3]
Assets	0	[1],[3]	0	[1],[3]
Derivative Liability	9,397,000	[2],[3]	9,073,000	[2],[3]
Not Designated as Hedging Instrument [Member] | Electric portfolio [Member]
Derivative [Line Items]
Assets	5,644,000	[1]	4,822,000	[1]
Derivative Liability	103,844,000	[2]	107,228,000	[2]
Not Designated as Hedging Instrument [Member] | Natural gas portfolio [Member]
Derivative [Line Items]
Assets	7,690,000	[1],[4]	19,526,000	[1],[4]
Derivative Liability	$83,008,000	[2],[4]	$88,807,000	[2],[4]
Not Designated as Hedging Instrument [Member] | Natural Gas Derivatives [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	348,200,000	[4]	360,400,000	[4]
[1]	1B Balance sheet location: Current and Long-term Unrealized gain on derivative instruments.
[2]	2B Balance sheet location: Current and Long-term Unrealized loss on derivative instruments.
[3]	3B Interest rate swap contracts are only held at Puget Energy.
[4]	4B All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, bRegulated Operationsb (ASC 980) due to the PGA mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.

Accounting_for_Derivative_Inst4

Accounting for Derivative Instruments and Hedging Activities Net Amount of Derivatives Reported in the Statement of Financial Position (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014	Dec. 31, 2014
Liabilities
Derivative contracts classified as financing activities due to merger	($8,045)		($8,026)
Commodity Contract [Member]
Assets
Gross Amount Recognized in the Statement of Financial Position	13,334	[1]		24,348	[1]
Gross Amounts Offset in the Statement of Financial Position	0			0
Net of Amounts Presented in the Statement of Financial Position	13,334			24,348
Commodity Contracts	-12,152			-23,066
Cash Collateral Received	0			0
Net Amount	1,182			1,282
Liabilities
Gross Amount Recognized in the Statement of Financial Position	186,852	[1]		196,035	[1]
Gross Amounts Offset in the Statement of Financial Position	0			0
Net of Amounts Presented in the Statement of Financial Position	186,852			196,035
Commodity Contracts	-12,152			-23,066
Cash Collateral Posted	0			-20
Net Amount	174,700			172,949
Interest Rate Contract [Member]
Liabilities
Gross Amount Recognized in the Statement of Financial Position	9,397	[1],[2]		9,073	[1],[2]
Gross Amounts Offset in the Statement of Financial Position	0	[2]		0	[2]
Net of Amounts Presented in the Statement of Financial Position	9,397	[2]		9,073	[2]
Commodity Contracts	0	[2]		0	[2]
Cash Collateral Posted	0	[2]		0	[2]
Net Amount	$9,397	[2]		$9,073	[2]
[1]	1B All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of Offset.
[2]	2B Interest Rate Swap Contracts are only held at Puget Energy.

Accounting_for_Derivative_Inst5

Accounting for Derivative Instruments and Hedging Activities Recognized in Statement of Income (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	($3,696)	($7,839)
Subsidiaries [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	-3,152	-7,270
Not Designated as Hedging Instrument [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	30,987	-20,177
Not Designated as Hedging Instrument [Member] | Other Income (Deductions) [Member] | Interest Expense [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	1,975	747
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	162	125
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	-3,696	-7,839
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Electric generation fuel [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	10,662	-7,827
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Purchased Electricity [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	21,884	-5,383
Not Designated as Hedging Instrument [Member] | Subsidiaries [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	29,394	-20,480
Not Designated as Hedging Instrument [Member] | Subsidiaries [Member] | Commodity Contract [Member] | Unrealized (Gain) Loss on Derivative Instruments, Net [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	-3,152	-7,270
Not Designated as Hedging Instrument [Member] | Subsidiaries [Member] | Commodity Contract [Member] | Electric generation fuel [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	10,662	-7,827
Not Designated as Hedging Instrument [Member] | Subsidiaries [Member] | Commodity Contract [Member] | Purchased Electricity [Member]
Derivative Instruments, (Loss) Gain [Line Items]
Unrealized (gain) loss on derivative instruments	$21,884	($5,383)

Accounting_for_Derivative_Inst6

Accounting for Derivative Instruments and Hedging Activities Recognized in Other Comprehensive Income (Details) (USD $)	3 Months Ended		12 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Mar. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Purchased electricity	$153,480	$181,157
Subsidiaries [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Purchased electricity	153,480	181,157
Cash Flow Hedging [Member] | Subsidiaries [Member] | Interest Rate Swap [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship	122	122
Cash Flow Hedging [Member] | Subsidiaries [Member] | Energy Related Derivative [Member] | Electric Generation Fuel [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship	-1,055	-1,104
Other Comprehensive Income (Loss) [Member] | Cash Flow Hedging [Member] | Parent Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship	-512	-678
Other Comprehensive Income (Loss) [Member] | Cash Flow Hedging [Member] | Parent Company [Member] | Interest Rate Swap [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship	0	144
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	-1,177	-1,226
Scenario, Forecast [Member] | Cash Flow Hedging [Member] | Subsidiaries [Member] | Interest Rate Swap [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Pre-tax gain (loss) of derivatives that were previously in a cash flow hedge relationship			($500)

Accounting_for_Derivative_Inst7

Accounting for Derivative Instruments and Hedging Activities Contractual Contingent Liability (Details) (USD $)	Mar. 31, 2015
In Thousands, unless otherwise specified
Electric portfolio [Member]
Derivative [Line Items]
Fair Value Liability	($93,792)	[1]
Posted Collateral	0
Additional Collateral, Aggregate Fair Value	27,292
Electric portfolio [Member] | Credit Rating [Member]
Derivative [Line Items]
Fair Value Liability	-27,292	[1],[2]
Posted Collateral	0	[2]
Additional Collateral, Aggregate Fair Value	27,292	[2]
Electric portfolio [Member] | Requested credit for adequate assurance [Member]
Derivative [Line Items]
Fair Value Liability	-65,531	[1]
Posted Collateral	0
Additional Collateral, Aggregate Fair Value	0
Electric portfolio [Member] | Forward value of contract [Member]
Derivative [Line Items]
Fair Value Liability	-969	[1],[3]
Posted Collateral	0	[3]
Additional Collateral, Aggregate Fair Value	0	[3]
Electric portfolio [Member] | External Credit Rating, Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage	99.80%
Electric portfolio [Member] | External Credit Rating, Non Investment Grade [Member]
Derivative [Line Items]
Derivative, Credit Risk Exposure, Percentage	0.20%
Natural gas portfolio [Member] | Credit Rating [Member]
Derivative [Line Items]
Posted Collateral	$1,000	[2]
[1]	1B 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]	2B 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]	3B Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.

Fair_Value_Measurements_Carryi

Fair Value Measurements Carrying Value (Details) (Carrying Value [Member], USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Parent Company [Member]
Assets:
Cash and Cash Equivalents	$19,119	$37,527
Restricted Cash	16,801	32,863
Notes Receivable and Other	49,587	53,503
Total assets	85,507	123,893
Liabilities:
Short-term Debt	0	85,000
Total liabilities	0	85,000
Parent Company [Member] | Level 1 [Member]
Assets:
Cash and Cash Equivalents	19,119	37,527
Restricted Cash	16,801	32,863
Notes Receivable and Other	0	0
Total assets	35,920	70,390
Liabilities:
Short-term Debt	0	85,000
Total liabilities	0	85,000
Parent Company [Member] | Level 2 [Member]
Assets:
Cash and Cash Equivalents	0	0
Restricted Cash	0	0
Notes Receivable and Other	49,587	53,503
Total assets	49,587	53,503
Liabilities:
Short-term Debt	0	0
Total liabilities	0	0
Subsidiaries [Member]
Assets:
Cash and Cash Equivalents	18,479	37,466
Restricted Cash	16,801	32,863
Notes Receivable and Other	49,587	53,503
Total assets	84,867	123,832
Liabilities:
Short-term Debt	0	85,000
Short-term Debt owed by PSE to PE	28,933	28,933
Total liabilities	28,933	113,933
Subsidiaries [Member] | Level 1 [Member]
Assets:
Cash and Cash Equivalents	18,479	37,466
Restricted Cash	16,801	32,863
Notes Receivable and Other	0	0
Total assets	35,280	70,329
Liabilities:
Short-term Debt	0	85,000
Short-term Debt owed by PSE to PE	0	0
Total liabilities	0	85,000
Subsidiaries [Member] | Level 2 [Member]
Assets:
Cash and Cash Equivalents	0	0
Restricted Cash	0	0
Notes Receivable and Other	49,587	53,503
Total assets	49,587	53,503
Liabilities:
Short-term Debt	0	0
Short-term Debt owed by PSE to PE	28,933	28,933
Total liabilities	$28,933	$28,933

Fair_Value_Measurements_Debt_a

Fair Value Measurements Debt at at Carrying and Fair Value (Details) (Discounted cash flow [Member], USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Parent Company [Member] | Carrying Value [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	$5,246,391	$5,243,608
Parent Company [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes	250,000	250,000
Long-term debt (fixed-rate), net of discount	4,697,391	4,694,608
Long Term Debt (variable rate) net of discount	299,000	299,000
Parent Company [Member] | Fair Value [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	6,846,203	6,658,789
Parent Company [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes	269,020	276,235
Long-term debt (fixed-rate), net of discount	6,278,183	6,083,554
Long Term Debt (variable rate) net of discount	299,000	299,000
Subsidiaries [Member] | Carrying Value [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	3,763,259	3,763,259
Subsidiaries [Member] | Carrying Value [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes	250,000	250,000
Long-term debt (fixed-rate), net of discount	3,513,259	3,513,259
Subsidiaries [Member] | Fair Value [Member]
Liabilities:
Long-term Debt, Excluding Current Maturities, Fair Value Disclosure	4,876,634	4,713,708
Subsidiaries [Member] | Fair Value [Member] | Level 2 [Member]
Liabilities:
Junior subordinated notes	269,020	276,235
Long-term debt (fixed-rate), net of discount	$4,607,614	$4,437,473

Fair_Value_Measurements_Assets

Fair Value Measurements Assets and Liabilities (Details) (USD $)	3 Months Ended
	Mar. 31, 2015		Mar. 31, 2014		Dec. 31, 2014
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	($14,102,000)		($15,782,000)
Included in earnings	-5,037,000	[1]	-2,745,000	[1]
Included in regulatory assets/liabilities	125,000		259,000
Settlements	204,000	[2]	-89,000	[2]
Transferred into Level 3	-787,000		2,515,000
Transferred out of Level 3	1,905,000		133,000
Balance at end of period	-17,692,000		-15,709,000
Electric portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	-5,000,000		-4,600,000
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	-12,062,000		-15,421,000
Included in earnings	-5,037,000	[1]	-2,745,000	[1]
Included in regulatory assets/liabilities	0		0
Settlements	113,000	[2]	321,000	[2]
Transferred into Level 3	-787,000		3,100,000
Transferred out of Level 3	1,682,000		139,000
Balance at end of period	-16,091,000		-14,606,000
Natural gas portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	-2,040,000		-361,000
Included in earnings	0	[1]	0	[1]
Included in regulatory assets/liabilities	125,000		259,000
Settlements	91,000	[2]	-410,000	[2]
Transferred into Level 3	0		-585,000
Transferred out of Level 3	223,000		-6,000
Balance at end of period	-1,601,000		-1,103,000
Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	13,334,000				24,348,000
Derivative Liability	186,852,000				196,035,000
Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	9,397,000	[3]			9,073,000	[3]
Fair Value, Measurements, Recurring [Member] | Parent Company [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	9,397,000				9,073,000
Fair Value, Measurements, Recurring [Member] | Parent Company [Member] | Level 2 [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	9,397,000				9,073,000
Fair Value, Measurements, Recurring [Member] | Parent Company [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	0				0
Fair Value, Measurements, Recurring [Member] | Parent Company [Member] | Level 3 [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	0				0
Fair Value, Measurements, Recurring [Member] | Parent Company [Member] | Total [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	9,397,000				9,073,000
Fair Value, Measurements, Recurring [Member] | Parent Company [Member] | Total [Member] | Interest Rate Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	9,397,000				9,073,000
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	8,645,000				19,718,000
Derivative Liability	164,471,000				177,303,000
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Level 2 [Member] | Commodity Contract [Member] | Electric portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	2,487,000				1,654,000
Derivative Liability	84,596,000				91,998,000
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Level 2 [Member] | Commodity Contract [Member] | Natural gas portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	6,158,000				18,064,000
Derivative Liability	79,875,000				85,305,000
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	4,689,000				4,630,000
Derivative Liability	22,381,000				18,732,000
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Level 3 [Member] | Commodity Contract [Member] | Electric portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	3,157,000	[4]			3,168,000	[4]
Derivative Liability	19,248,000	[4]			15,230,000	[4]
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Level 3 [Member] | Commodity Contract [Member] | Natural gas portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	1,532,000	[4]			1,462,000	[4]
Derivative Liability	3,133,000	[4]			3,502,000	[4]
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Total [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	13,334,000				24,348,000
Derivative Liability	186,852,000				196,035,000
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Total [Member] | Commodity Contract [Member] | Electric portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	5,644,000				4,822,000
Derivative Liability	103,844,000				107,228,000
Fair Value, Measurements, Recurring [Member] | Subsidiaries [Member] | Total [Member] | Commodity Contract [Member] | Natural gas portfolio [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets	7,690,000				19,526,000
Derivative Liability	$83,008,000				$88,807,000
[1]	1B 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 $(5.0) million and $(4.6) million for the three months ended MarchB 31, 2015 and 2014, respectively. 2
[2]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmE0MjVjMTc5ODEyYTRmNTNiYTAwNDM1ZjAxZDFjYWYzfFRleHRTZWxlY3Rpb246Rjc0M0VGNEE0MDA3MTFGREJCRkIyNEI3QjNBMUI1RkMM}
[3]	2B Interest Rate Swap Contracts are only held at Puget Energy.
[4]	1B The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions

Fair_Value_Measurements_Valuat

Fair Value Measurements Valuation Technicques for Measurement with Unobservable Inputs (Details) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013
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%
Fair Value Measurements, Sensitivity Analysis, Hypothetical Increase or Decrease of Market Prices, Result on Fair Value	$4,600,000		$3,900,000
Finite-lived Intangible Assets, Fair Value Disclosure	417,300,000		437,600,000
Fair Value Inputs, Comparability Adjustments	7.00%
Impairment of Intangible Assets (Excluding Goodwill)	9,900,000	3,200,000
Carrying Value [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-lived Intangible Assets, Fair Value Disclosure	49,300,000		62,100,000
Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh)	0		0
Fair Value Inputs, Power Contract Costs	4,129		3,015
Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh)	0		0
Fair Value Inputs, Power Contract Costs	4,783		4,783
Discounted cash flow [Member] | Weighted Average [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh)	0		0
Fair Value Inputs, Power Contract Costs	4,493		4,469
Commodity Contract [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets	13,334,000		24,348,000
Derivative Liability	186,852,000		196,035,000
Electric portfolio [Member] | Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh)	14.63			21.79
Electric portfolio [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh)	33.87			35.46
Electric portfolio [Member] | Discounted cash flow [Member] | Weighted Average [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MWh)	30.43			32.89
Natural gas portfolio [Member] | Discounted cash flow [Member] | Low [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MMBtu)	1.71			3.11
Natural gas portfolio [Member] | Discounted cash flow [Member] | High [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MMBtu)	3.66			3.83
Natural gas portfolio [Member] | Discounted cash flow [Member] | Weighted Average [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Price (per MMBtu)	2.85			3.28
Electric portfolio [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	-5,000,000	-4,600,000
Wells Project [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Finite-Lived Intangible Assets, Net	$59,200,000		$65,300,000

Retirement_Benefits_Net_Period

Retirement Benefits Net Periodic Benefit Cost (Details) (USD $)	3 Months Ended	12 Months Ended	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014
Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	($5,472)	($17,437)
Interest cost	-7,107	-28,039
SERP Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	-277	-1,042
Interest cost	-570	-2,310
Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	-33	-112
Interest cost	-161	-684
Parent Company [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	-5,472		-4,512
Interest cost	-7,107		-7,055
Expected return on plan assets	-11,402		-10,721
Amortization of prior service cost	-495		-495
Amortization of net loss (gain)	981		0
Defined Benefit Plan, Net Periodic Benefit Cost	1,663		351
Parent Company [Member] | SERP Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	-277		-261
Interest cost	-570		-577
Expected return on plan assets	0		0
Amortization of prior service cost	11		11
Amortization of net loss (gain)	410		228
Defined Benefit Plan, Net Periodic Benefit Cost	1,268		1,077
Parent Company [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	-33		-29
Interest cost	161		-183
Expected return on plan assets	-133		-133
Amortization of prior service cost	0		0
Amortization of net loss (gain)	-15		-66
Defined Benefit Plan, Net Periodic Benefit Cost	46		13
Subsidiaries [Member] | Qualified Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	-5,472		-4,512
Interest cost	-7,107		-7,055
Expected return on plan assets	-11,508		-10,919
Amortization of prior service cost	-393		-393
Amortization of net loss (gain)	5,136		3,239
Defined Benefit Plan, Net Periodic Benefit Cost	5,814		3,494
Subsidiaries [Member] | SERP Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	-277		-261
Interest cost	-570		-577
Expected return on plan assets	0		0
Amortization of prior service cost	11		11
Amortization of net loss (gain)	530		365
Defined Benefit Plan, Net Periodic Benefit Cost	1,388		1,214
Subsidiaries [Member] | Other Benefit [Member]
Components of net periodic benefit cost:
Service cost	-33		-29
Interest cost	-161		-183
Expected return on plan assets	-133		-133
Amortization of prior service cost	1		1
Amortization of net loss (gain)	-83		-143
Defined Benefit Plan, Net Periodic Benefit Cost	($21)		($63)

Retirement_Benefits_Change_in_

Retirement Benefits Change in Net Benefit Obligation (Details) (USD $)	3 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Qualified Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	$690,194	$573,317
Service cost	-5,472	-17,437
Interest cost	7,107	28,039
Amendments	0	0
Actuarial loss/(gain)	0	104,618
Benefits paid	-10,275	-33,217
Medicare part D subsidiary received	0	0
Benefit obligation at end of period	692,498	690,194
SERP Pension Benefits [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	55,855	47,279
Service cost	-277	-1,042
Interest cost	570	2,310
Amendments	0	0
Actuarial loss/(gain)	0	7,162
Benefits paid	-2,103	-1,938
Medicare part D subsidiary received	0	0
Benefit obligation at end of period	54,599	55,855
Other Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation at beginning of period	15,688	14,939
Service cost	-33	-112
Interest cost	161	684
Amendments	0	0
Actuarial loss/(gain)	0	1,108
Benefits paid	-348	-1,424
Medicare part D subsidiary received	56	269
Benefit obligation at end of period	$15,590	$15,688

Retirement_Benefits_Activity_D

Retirement Benefits Activity (Details) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2015
Qualified Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Company Contribution	$4.50
SERP Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Company Contribution	2.1
Other Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Company Contribution	0.3
Subsidiaries [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent	1.00%
Scenario, Forecast [Member] | Qualified Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions		18
Scenario, Forecast [Member] | SERP Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions		4.4
Scenario, Forecast [Member] | Other Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Aggregate expected contributions		$0.50
Scenario, Forecast [Member] | Subsidiaries [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent	4.00%

Regulation_and_Rates_Details

Regulation and Rates (Details) (USD $)	Jul. 02, 2013	Jan. 01, 2015	1-May-15	1-May-14	Dec. 01, 2014	23-May-14	Nov. 01, 2014	Dec. 31, 2014	Mar. 31, 2015	Jun. 25, 2013
In Millions, unless otherwise specified
Subsidiaries [Member]
Regulatory Assets [Line Items]
Rate Case, Approved Effective Weighted Cost of Capital	7.77%
Rate Case, Approved Effective Common Equity in Capital Structure	48.00%
Rate Case, Approved Effective Return on Equity	9.80%
Decoupling Mechanism [Member] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)		2.20%
Decoupling Mechanism [Member] | Subsidiaries [Member]
Regulatory Assets [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)			($12)
Decoupling Mechanism [Member] | Subsidiaries [Member] | Electric [Member]
Regulatory Assets [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)			53.8	10.6
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)			2.60%	0.50%
Decoupling Mechanism [Member] | Subsidiaries [Member] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)			22	-1
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)			2.10%	-0.10%
Power Cost Only Rate Case (PCORC) [Member] | Subsidiaries [Member] | Electric [Member]
Regulatory Assets [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)					-19.4	-9.6
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)					-0.90%	-0.50%
Purchased Gas Adjustment (PGA) [Member] | Subsidiaries [Member] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)							23.3
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)							2.50%
Property tax tracker [Member] [Domain] [Domain] | Subsidiaries [Member] | Electric [Member]
Regulatory Assets [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)			6.5	11
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)			0.30%	0.50%
Property tax tracker [Member] [Domain] [Domain] | Subsidiaries [Member] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)			-0.9	5.6
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)			-0.10%	0.60%
Conservation Rider [Member] | Subsidiaries [Member] | Electric [Member]
Regulatory Assets [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)			4.2	12.2
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)			0.20%	0.60%
Conservation Rider [Member] | Subsidiaries [Member] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)			2.3	0.3
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)			0.20%
Maximum [Member] | Decoupling Mechanism [Member]
Regulatory Assets [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Percentage Increase (Decrease)		3.00%
Deferred Revenue [Domain] | Decoupling Mechanism [Member] | Subsidiaries [Member] | Electric [Member]
Regulatory Assets [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)								1.9
Deferred Revenue [Domain] | Decoupling Mechanism [Member] | Subsidiaries [Member] | Natural Gas [Member]
Regulatory Assets [Line Items]
Public Utilities, Rate Case, Approved Effective Annual Rate Increase (Decrease)								8.2
Range 1 [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount									17
Range 2 [Member] [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount									23
Range 3 [Member] [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount									40
Over Recovery [Member] | Range 1 [Member] | Customers share [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage									0.00%
Over Recovery [Member] | Range 1 [Member] | Company's share [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage									100.00%
Over Recovery [Member] | Range 2 [Member] [Member] | Customers share [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage									65.00%
Over Recovery [Member] | Range 2 [Member] [Member] | Company's share [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage									35.00%
Over Recovery [Member] | Range 3 [Member] [Member] | Customers share [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage									90.00%
Over Recovery [Member] | Range 3 [Member] [Member] | Company's share [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage									10.00%
Under Recovery [Member] | Range 1 [Member] | Customers share [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage									0.00%
Under Recovery [Member] | Range 1 [Member] | Company's share [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage									100.00%
Under Recovery [Member] | Range 2 [Member] [Member] | Customers share [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage									50.00%
Under Recovery [Member] | Range 2 [Member] [Member] | Company's share [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage									50.00%
Under Recovery [Member] | Range 3 [Member] [Member] | Customers share [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage									90.00%
Under Recovery [Member] | Range 3 [Member] [Member] | Company's share [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Percentage									10.00%
Deferral Trigger [Member] [Member]
Regulatory Assets [Line Items]
Annual Power Cost Variability, Amount									$20	$30

Litigation_Details

Litigation (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Colstrip Units 1 and 2 [Member]
Loss Contingencies [Line Items]
Ownership interest (percent)	50.00%
Colstrip Units 3 and 4 [Member]
Loss Contingencies [Line Items]
Ownership interest (percent)	25.00%
Pending Litigation [Member]
Loss Contingencies [Line Items]
Litigation claims accrual	$1.50	$1.70

Accumulated_Other_Comprehensiv2

Accumulated Other Comprehensive Income - Changes by Component (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		($37,043)
Ending balance	-36,131	-37,043
Parent Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	-37,043
Other comprehensive income (loss) before reclassifications	0
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	912
Net current-period other comprehensive income (loss)	912
Ending balance	-36,131
Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	-170,957
Other comprehensive income (loss) before reclassifications	0
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	4,146
Net current-period other comprehensive income (loss)	4,146
Ending balance	-166,811
Net unrealized gain (loss) and prior service cost on pension plans | Parent Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	-36,710
Other comprehensive income (loss) before reclassifications
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	579
Net current-period other comprehensive income (loss)	579
Ending balance	-36,131
Net unrealized gain (loss) and prior service cost on pension plans | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	-164,281
Other comprehensive income (loss) before reclassifications
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	3,381
Net current-period other comprehensive income (loss)	3,381
Ending balance	-160,900
Energy Related Derivative [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Parent Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	-333
Other comprehensive income (loss) before reclassifications	0
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	333
Net current-period other comprehensive income (loss)	333
Ending balance	0
Energy Related Derivative [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	-686
Other comprehensive income (loss) before reclassifications	0
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	686
Net current-period other comprehensive income (loss)	686
Ending balance	0
Interest Rate Swap [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Parent Company [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	0
Other comprehensive income (loss) before reclassifications	0
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	0
Net current-period other comprehensive income (loss)	0
Ending balance	0
Interest Rate Swap [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Subsidiaries [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	-5,990
Other comprehensive income (loss) before reclassifications	0
Amounts reclassified from accumulated other comprehensive income (loss), net of tax	79
Net current-period other comprehensive income (loss)	79
Ending balance	($5,911)

Accumulated_Other_Comprehensiv3

Accumulated Other Comprehensive Income - Reclassification Location (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Purchased electricity	($153,480)		($181,157)
Interest expense	-88,909		-90,255
Total before tax	159,157		149,112
Tax (expense) or benefit	-43,481		-41,520
Net of Tax	115,676		107,592
Comprehensive income (loss)	116,588		107,824
Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Purchased electricity	-153,480		-181,157
Interest expense	-63,196		-64,137
Total before tax	182,483		172,625
Tax (expense) or benefit	-53,383		-51,542
Net of Tax	129,100		121,083
Comprehensive income (loss)	133,246		123,881
Reclassification out of Accumulated Other Comprehensive Income [Member] | Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Comprehensive income (loss)	-912		-232
Reclassification out of Accumulated Other Comprehensive Income [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Comprehensive income (loss)	-4,146		-2,798
Net unrealized gain (loss) and prior service cost on pension plans | Reclassification out of Accumulated Other Comprehensive Income [Member] | Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Amortization of prior service cost	484	[1]	484	[1]
Amortization of net gain (loss)	-1,375	[1]	-162	[1]
Total before tax	-891		322
Tax (expense) or benefit	312		-113
Net of Tax	-579		209
Net unrealized gain (loss) and prior service cost on pension plans | Reclassification out of Accumulated Other Comprehensive Income [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Amortization of prior service cost	381	[1]	381	[1]
Amortization of net gain (loss)	-5,583	[1]	-3,461	[1]
Total before tax	-5,202		-3,080
Tax (expense) or benefit	1,821		1,079
Net of Tax	-3,381		-2,001
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Derivative [Member] | Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Purchased electricity	-512	[1]	-534	[1]
Tax (expense) or benefit	179		187
Net of Tax	-333		-347
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Derivative [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Purchased electricity	-1,055		-1,104	[1]
Tax (expense) or benefit	369		386
Net of Tax	-686		-718
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate Swap [Member] | Parent Company [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	0		-144
Tax (expense) or benefit	0		50
Net of Tax	0		-94
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate Swap [Member] | Subsidiaries [Member]
Reclassification out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	-122		-122
Tax (expense) or benefit	43		43
Net of Tax	($79)		($79)
[1]	(a)B These accumulated OCI components are included in the computation of net periodic pension cost (see Note 5 for additional details).