Northern States Power 10-Q 31 Oct 14 2014 Q3 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
	Sep. 30, 2014	Oct. 31, 2014
Document and Entity Information [Abstract]	'	'
Entity Registrant Name	'NORTHERN STATES POWER CO	'
Entity Central Index Key	'0001123852	'
Current Fiscal Year End Date	'--12-31	'
Entity Well-known Seasoned Issuer	'Yes	'
Entity Voluntary Filers	'No	'
Entity Current Reporting Status	'Yes	'
Entity Filer Category	'Non-accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	1,000,000
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q3	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Sep-14	'

CONSOLIDATED_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Operating revenues	'	'	'	'
Electric, non-affiliates	$1,004,863	$1,077,545	$2,835,737	$2,778,954
Electric, affiliates	116,192	79,589	354,515	300,725
Natural gas	62,339	53,724	528,252	396,461
Other	6,819	6,618	20,794	19,416
Total operating revenues	1,190,213	1,217,476	3,739,298	3,495,556
Operating expenses	'	'	'	'
Electric fuel and purchased power	411,621	465,106	1,264,834	1,270,185
Cost of natural gas sold and transported	31,416	23,481	368,724	247,018
Cost of sales — other	4,435	4,122	12,736	11,536
Operating and maintenance expenses	296,707	294,831	902,808	854,533
Conservation program expenses	32,589	23,699	99,497	69,756
Depreciation and amortization	102,841	89,228	303,932	302,048
Taxes (other than income taxes)	57,859	52,489	175,034	158,624
Total operating expenses	937,468	952,956	3,127,565	2,913,700
Operating income	252,745	264,520	611,733	581,856
Other (expense) income, net	-484	-1,147	1,049	3
Allowance for funds used during construction — equity	6,296	9,291	17,555	31,892
Interest charges and financing costs	'	'	'	'
Interest charges — includes other financing costs of $1,651, $1,649, $4,863 and $4,687 respectively	51,183	50,307	147,724	141,898
Allowance for funds used during construction — debt	-2,808	-4,331	-7,993	-14,327
Total interest charges and financing costs	48,375	45,976	139,731	127,571
Income before income taxes	210,182	226,688	490,606	486,180
Income taxes	75,713	71,582	172,507	151,408
Net income	$134,469	$155,106	$318,099	$334,772

CONSOLIDATED_STATEMENTS_OF_INC1

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Interest charges and financing costs	'	'	'	'
Other financing costs	$1,651	$1,649	$4,863	$4,687

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Comprehensive income:	'	'	'	'
Net income	$134,469	$155,106	$318,099	$334,772
Pension and retiree medical benefits:	'	'	'	'
Amortization of losses included in net periodic benefit cost, net of tax of $5, $16, $13 and $48, respectively	5	22	16	67
Derivative instruments:	'	'	'	'
Net fair value (decrease) increase, net of tax of $(17), $6, $(13) and $(2), respectively	-25	14	-19	-5
Reclassification of losses to net income, net of tax of $154, $145, $425 and $421, respectively	187	192	580	580
Total derivative instruments, net of tax	162	206	561	575
Marketable securities:	'	'	'	'
Net fair value increase, net of tax of $1, $77, $27 and $55, respectively	2	112	39	80
Other comprehensive income	169	340	616	722
Comprehensive income	$134,638	$155,446	$318,715	$335,494

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Pension and retiree medical benefits:	'	'	'	'
Amortization of losses included in net periodic benefit cost, tax	$5	$16	$13	$48
Derivative instruments:	'	'	'	'
Net fair value (decrease) increase, tax	-17	6	-13	-2
Reclassification of losses to net income, tax	154	145	425	421
Marketable securities:	'	'	'	'
Net fair value increase, tax	$1	$77	$27	$55

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013
Operating activities	'	'
Net income	$318,099	$334,772
Adjustments to reconcile net income to cash provided by operating activities:	'	'
Depreciation and amortization	308,058	306,003
Nuclear fuel amortization	92,278	76,447
Deferred income taxes	141,331	106,619
Amortization of investment tax credits	-1,368	-2,010
Allowance for equity funds used during construction	-17,555	-31,892
Net realized and unrealized hedging and derivative transactions	3,667	-4,856
Changes in operating assets and liabilities:	'	'
Accounts receivable	-50,666	-73,538
Accrued unbilled revenues	62,776	22,053
Inventories	-19,841	-32,950
Other current assets	-10,669	29,509
Accounts payable	-73,307	33,623
Net regulatory assets and liabilities	95,605	27,368
Other current liabilities	51,371	126,474
Pension and other employee benefit obligations	-46,727	-63,513
Change in other noncurrent assets	34,138	13,886
Change in other noncurrent liabilities	-16,190	-5,795
Net cash provided by operating activities	871,000	862,200
Investing activities	'	'
Utility capital/construction expenditures	-864,501	-1,157,110
Proceeds from insurance recoveries	6,000	90,000
Allowance for equity funds used during construction	17,555	31,892
Purchases of investments in external decommissioning fund	-499,493	-1,177,398
Proceeds from the sale of investments in external decommissioning fund	494,554	1,172,597
Investments in utility money pool arrangement	-397,000	-29,000
Repayments from utility money pool arrangement	389,000	29,000
Other, net	-893	-1,000
Net cash used in investing activities	-854,778	-1,041,019
Financing activities	'	'
Repayments of short-term borrowings, net	-131,000	-188,000
Borrowings under utility money pool arrangement	333,000	718,000
Repayments under utility money pool arrangement	-367,000	-663,000
Proceeds from issuance of long-term debt	295,356	394,806
Capital contributions from parent	95,028	110,102
Dividends paid to parent	-192,241	-176,755
Net cash provided by financing activities	33,143	195,153
Net change in cash and cash equivalents	49,365	16,334
Cash and cash equivalents at beginning of period	42,920	28,842
Cash and cash equivalents at end of period	92,285	45,176
Supplemental disclosure of cash flow information:	'	'
Cash paid for interest (net of amounts capitalized)	-151,002	-141,916
Cash paid for income taxes, net	-16,087	-10,190
Supplemental disclosure of non-cash investing transactions:	'	'
Property, plant and equipment additions in accounts payable	$206,549	$142,359

CONSOLIDATED_BALANCE_SHEETS_UN

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets	'	'
Cash and cash equivalents	$92,285	$42,920
Accounts receivable, net	342,459	284,532
Accounts receivable from affiliates	12,508	19,769
Investments in utility money pool arrangement	8,000	0
Accrued unbilled revenues	192,636	255,412
Inventories	299,803	279,915
Regulatory assets	222,082	207,467
Derivative instruments	82,565	66,726
Deferred income taxes	91,723	80,095
Prepayments and other	120,008	118,036
Total current assets	1,464,069	1,354,872
Property, plant and equipment, net	11,059,789	10,589,522
Other assets	'	'
Nuclear decommissioning fund and other investments	1,718,664	1,655,356
Regulatory assets	955,427	990,204
Derivative instruments	12,835	36,881
Other	36,055	68,060
Total other assets	2,722,981	2,750,501
Total assets	15,246,839	14,694,895
Current liabilities	'	'
Current portion of long-term debt	250,013	2
Short-term debt	0	131,000
Borrowings under utility money pool arrangement	0	34,000
Accounts payable	453,495	554,265
Accounts payable to affiliates	65,972	65,941
Regulatory liabilities	159,888	101,795
Taxes accrued	212,571	195,734
Accrued interest	45,045	59,846
Dividends payable to parent	67,210	58,752
Derivative instruments	14,169	13,066
Other	149,761	104,544
Total current liabilities	1,418,124	1,318,945
Deferred credits and other liabilities	'	'
Deferred income taxes	2,418,018	2,253,915
Deferred investment tax credits	27,934	29,202
Regulatory liabilities	441,312	430,999
Asset retirement obligations	1,799,955	1,732,763
Derivative instruments	136,364	151,651
Pension and employee benefit obligations	260,527	307,282
Other	112,309	100,614
Total deferred credits and other liabilities	5,196,419	5,006,426
Commitments and contingencies	'	'
Capitalization	'	'
Long-term debt	3,938,458	3,888,730
Common stock — authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares outstanding at Sept. 30, 2014 and Dec. 31, 2013, respectively	10	10
Additional paid in capital	2,961,632	2,866,603
Retained earnings	1,753,309	1,635,910
Accumulated other comprehensive loss	-21,113	-21,729
Total common stockholder’s equity	4,693,838	4,480,794
Total liabilities and equity	$15,246,839	$14,694,895

CONSOLIDATED_BALANCE_SHEETS_UN1

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Capitalization, Long-term Debt and Equity [Abstract]	'	'
Common stock, shares authorized (in shares)	5,000,000	5,000,000
Common stock, par value (in dollars per share)	$0.01	$0.01
Common stock, shares outstanding (in shares)	1,000,000	1,000,000

Managements_Opinion

Management's Opinion	9 Months Ended
	Sep. 30, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Management's Opinion	'
	In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of NSP-Minnesota and its subsidiaries as of Sept. 30, 2014 and Dec. 31, 2013; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2014 and 2013; and its cash flows for the nine months ended Sept. 30, 2014 and 2013. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2014 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2013 balance sheet information has been derived from the audited 2013 consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2013. These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2013, filed with the SEC on Feb. 24, 2014. Due to the seasonality of NSP-Minnesota’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2014
Accounting Policies [Abstract]	'
Summary of Significant Accounting Policies	'
	Summary of Significant Accounting Policies
	The significant accounting policies set forth in Note 1 to the consolidated financial statements in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2013, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

Accounting_Pronouncements

Accounting Pronouncements	9 Months Ended
	Sep. 30, 2014
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]	'
Accounting Pronouncements	'
	Accounting Pronouncements
	Recently Issued
	Revenue Recognition — In May 2014, the Financial Accounting Standards Board issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09), which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. This guidance, which includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers, will be effective for interim and annual reporting periods beginning after Dec. 15, 2016. NSP-Minnesota is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

Selected_Balance_Sheet_Data

Selected Balance Sheet Data	9 Months Ended
	Sep. 30, 2014
Balance Sheet Related Disclosures [Abstract]	'
Selected Balance Sheet Data	'
	Selected Balance Sheet Data
	(Thousands of Dollars)	Sept. 30, 2014			Dec. 31, 2013
	Accounts receivable, net
	Accounts receivable	$	363,392		$	304,748
	Less allowance for bad debts	(20,933		)	(20,216		)
		$	342,459		$	284,532
	(Thousands of Dollars)	Sept. 30, 2014			Dec. 31, 2013
	Inventories
	Materials and supplies	$	155,743		$	144,140
	Fuel	84,113			81,971
	Natural gas	59,947			53,804
		$	299,803		$	279,915
	(Thousands of Dollars)	Sept. 30, 2014			Dec. 31, 2013
	Property, plant and equipment, net
	Electric plant	$	14,176,125		$	13,530,767
	Natural gas plant	1,119,309			1,092,314
	Common and other property	509,956			503,168
	Construction work in progress	893,581			902,820
	Total property, plant and equipment	16,698,971			16,029,069
	Less accumulated depreciation	(5,954,356		)	(5,783,658		)
	Nuclear fuel	2,250,140			2,186,799
	Less accumulated amortization	(1,934,966		)	(1,842,688		)
		$	11,059,789		$	10,589,522

Income_Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2014
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	Income Taxes
	Except to the extent noted below, the circumstances set forth in Note 6 to the consolidated financial statements included in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.
	Federal Tax Loss Carryback Claims — In 2012 and 2013, NSP-Minnesota identified certain expenses related to 2009, 2010, 2011 and 2013 that qualify for an extended carryback beyond the typical two-year carryback period. As a result of a higher tax rate in prior years, NSP-Minnesota recognized a tax benefit of approximately $15 million in 2012 and $12 million in 2013.
	Federal Audit — NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expired in September 2012. The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in June 2015. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of Sept. 30, 2014, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $10 million of income tax expense for the 2009 through 2011 claims and the anticipated claim for 2013. Xcel Energy is continuing to work through the audit process, but the outcome and timing of a resolution is uncertain.
	State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Sept. 30, 2014, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.
	Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate (ETR). In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.
	A reconciliation of the amount of unrecognized tax benefit is as follows:
	(Millions of Dollars)	Sept. 30, 2014			Dec. 31, 2013
	Unrecognized tax benefit — Permanent tax positions	$	5.3		$	8.5
	Unrecognized tax benefit — Temporary tax positions	16.1			16.7
	Total unrecognized tax benefit	$	21.4		$	25.2
	The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:
	(Millions of Dollars)	Sept. 30, 2014			Dec. 31, 2013
	NOL and tax credit carryforwards	$	(12.6	)	$	(12.4	)
	It is reasonably possible that NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $4 million.
	The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Sept. 30, 2014 and Dec. 31, 2013 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2014 or Dec. 31, 2013.

Rate_Matters

Rate Matters	9 Months Ended
	Sep. 30, 2014
Public Utilities, General Disclosures [Abstract]	'
Rate Matters	'
	Rate Matters
	Except to the extent noted below, the circumstances set forth in Note 10 to the consolidated financial statements included in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2013 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.
	Pending Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)
	Minnesota 2014 Multi-Year Electric Rate Case — In November 2013, NSP-Minnesota filed a two-year electric rate case with the MPUC. The rate case is based on a requested return on equity (ROE) of 10.25 percent, a 52.5 percent equity ratio, a 2014 average electric rate base of $6.67 billion and an additional average rate base of $412 million in 2015.
	The NSP-Minnesota electric rate case initially reflected a requested increase in revenues of approximately $193 million or 6.9 percent in 2014 and an additional $98 million or 3.5 percent in 2015. The request includes a proposed rate moderation plan for 2014 and 2015. After reflecting interim rate adjustments, NSP-Minnesota requested a rate increase of $127 million or 4.6 percent in 2014 and an incremental rate increase of $164 million or 5.6 percent in 2015.
	NSP-Minnesota’s moderation plan includes the acceleration of the eight-year amortization of the excess depreciation reserve and the use of expected funds from the U.S. Department of Energy (DOE) for settlement of certain claims. These DOE refunds would be in excess of amounts needed to fund NSP-Minnesota’s decommissioning expense. The interim rate adjustments are primarily associated with ROE, Monticello life cycle management (LCM)/extended power uprate (EPU) project costs and NSP-Minnesota’s request to amortize amounts associated with the canceled Prairie Island (PI) EPU project.
	In December 2013, the MPUC approved interim rates of $127 million, effective Jan. 3, 2014, subject to refund. The MPUC determined that the costs of Sherco Unit 3 would be allowed in interim rates, and that NSP-Minnesota’s request to accelerate the depreciation reserve amortization was a permissible adjustment to its interim rate request.
	In August 2014, the evidentiary hearing was completed. As a result of discussions between NSP-Minnesota and intervening parties, the outstanding issues were further narrowed and the following were agreed upon:
	•	NSP-Minnesota and the Minnesota Department of Commerce (DOC) have agreed to true-up the sales forecast to 12 months of actual weather normalized sales for 2014.
	•	NSP-Minnesota and the DOC agreed to a property tax adjustment of $9 million, based on an assumed 2014 property tax forecast of $141 million. The parties also agreed to a limited true-up mechanism in which NSP-Minnesota would recover actual 2014 property taxes up to $145 million.
	•	NSP-Minnesota agreed with the Minnesota Chamber of Commerce recommendation regarding deferral of the 2014 Monticello EPU depreciation expense and amortization of the depreciation over the remaining life of the plant.
	NSP-Minnesota revised its requested rate increase to $142.2 million for 2014 and to $106.0 million for 2015, for a total combined increase of $248.2 million.
	The following table summarizes the DOC’s and NSP-Minnesota’s recommendations and includes the estimated impact of certain agreed-upon true-up adjustments:
	2014 Rate Request (Millions of Dollars)		DOC			NSP-Minnesota
	NSP-Minnesota’s filed rate request		$	192.7		$	192.7
	Sales forecast		(43.2		)	(15.8		)
	ROE		(36.2		)	—
	Monticello EPU cost recovery		(33.9		)	—
	Monticello EPU depreciation deferral		—			(12.2		)
	Property taxes		(9.0		)	(9.0		)
	PI EPU		(5.1		)	(5.1		)
	Health care, pension and other benefits		(11.4		)	(1.9		)
	Other, net		(8.0		)	(6.5		)
	Total recommendation 2014 — unadjusted		$	45.9		$	142.2
	Estimated true-up adjustments:
	Sales forecast		$	18.3		$	(9.1	)
	Property taxes		3.9			3.9
	Total recommendation 2014 — adjusted		$	68.1		$	137
	2015 Rate Request (Millions of Dollars)		DOC			NSP-Minnesota
	NSP-Minnesota’s filed rate request		$	98.5		$	98.5
	Monticello EPU cost recovery		29.1			—
	Monticello EPU cost disallowance (a)		(10.2		)	—
	Excess depreciation reserve adjustment (b)		(22.7		)	—
	Depreciation		(17.5		)	—
	Monticello EPU depreciation deferral		—			1.6
	Monticello EPU step increase		—			10.1
	Property taxes		(3.3		)	(3.3		)
	Production tax credits to be included in base rates		(11.1		)	(11.1		)
	DOE settlement proceeds		10.1			10.1
	Emission chemicals		(1.6		)	(1.6		)
	Other, net		(4.8		)	1.7
	Total recommendation 2015 step increase		$	66.5		$	106
	Unadjusted cumulative total for 2014 and 2015 step increase		$	112.4		$	248.2
	Estimated adjusted cumulative total for 2014 and 2015 step increase		$	134.6		$	243
	(a)	In July 2014, the DOC recommended a disallowance of recovery of approximately $71.5 million of project costs on a Minnesota jurisdictional basis. This equates to a total NSP System disallowance of approximately $94 million. This would reduce NSP-Minnesota’s revenue requirement by approximately $10.2 million in 2015.
	(b)	Adjustment is due to timing differences and/or methodology of accelerating amortization of the excess depreciation reserve over three years.
	NSP-Minnesota’s revised rate request, moderation plan, interim rate adjustments and impacts on expenses are detailed below:
	(Millions of Dollars)		2014			Percentage		2015			Percentage
						Increase					Increase
	Rebuttal pre-moderation deficiency		$	250.6				$	67.8
	Evidentiary hearing adjustments		(27.3		)			11
	Revised pre-moderation deficiency		223.3					78.8
	Moderation plan:
	Excess depreciation reserve		(81.1		)			52.9
	DOE settlement proceeds		—					(25.7		)
	Revised rate request		142.2			5.10%		106			3.80%
	Interim rate adjustments		(65.3		)			65.3
	PI EPU		4.8					(4.8		)
	Revenue impact (a)		81.7					166.5
	Excess depreciation reserve		81.1					(45.7		)
	Sales forecast (b)		(9.1		)			—
	DOE settlement proceeds		—					25.7
	Estimated impact of request on operating income		$	153.7				$	146.5
(a)	NSP-Minnesota’s total revenue for 2014 is capped at the interim rate level of $127 million and pre-tax operating income is capped at $208 million. This table demonstrates the impact of reducing NSP-Minnesota’s rebuttal request.
(b)	NSP-Minnesota and the DOC have agreed to a sales true-up based on weather normalized sales for 2014, using standard weather coefficients. NSP-Minnesota periodically adjusts the coefficients in periods of extreme weather conditions to enhance weather impact estimates. As a result of the difference in the two methodologies, currently, approximately $9.1 million of revenue that NSP-Minnesota attributed to weather would be considered normal sales growth using the standard weather coefficients. The refund for the full year could vary from the estimate as of Sept. 30, 2014, depending on weather conditions.
NSP-Minnesota recorded a current regulatory liability representing the current best estimate of a refund obligation associated with interim rates as of Sept. 30, 2014.
The next step in the procedural schedule is expected to be the Administrative Law Judge (ALJ) Report on Dec. 26, 2014. The MPUC is expected to deliberate on March 26, 2015. A final MPUC order is anticipated in the second quarter of 2015.
Nuclear Project Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello LCM/EPU project. The multi-year project extended the life of the facility and increased the capacity from 600 to 671 megawatts (MW). Monticello LCM/EPU project expenditures were approximately $665 million. Total capitalized costs were approximately $748 million, which includes allowance for funds used during construction (AFUDC). Project expenditures were initially estimated in 2008 at approximately $320 million, excluding AFUDC.
In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent.
NSP-Minnesota filed a report to support the change and prudence of the incurred costs. The filing indicated the increase in costs was primarily attributable to three factors: (1) the original estimate was based on a high level conceptual design and the project scope increased as the actual conditions of the plant were incorporated into the design; (2) implementation difficulties, including the amount of work that occurred in confined and radioactive or electrically sensitive spaces and NSP-Minnesota’s and its vendors’ ability to attract and retain experienced workers; and (3) additional Nuclear Regulatory Commission (NRC) licensing related requests over the five-plus year application process.
The cost deviation is in line with similar nuclear upgrade projects undertaken by other utilities. In addition, the project remains economically beneficial to customers. NSP-Minnesota has received all necessary licenses from the NRC for the Monticello EPU, and has begun the process to comply with the license requirements for higher power levels, subject to NRC oversight and review. As part of the review process, in October 2014 NSP-Minnesota received approval for ascension to higher EPU levels which is expected to recommence during the fourth quarter.
In July 2014, the DOC filed testimony and recommended a disallowance of recovery of approximately $71.5 million of project costs on a Minnesota jurisdictional basis. This equates to a total NSP System disallowance of approximately $94 million.
The DOC’s recommendation indicated that although the combined LCM/EPU project is cost effective, NSP-Minnesota should have done a better job of estimating initial project costs of the investments required to achieve 71 MW of additional capacity (i.e., EPU costs) as opposed to investments required to extend the life of the plant. They asserted that approximately 85 percent of the total $665 million in costs were associated with project components required solely to achieve the EPU.
In August 2014, the Office of Attorney General (OAG) filed rebuttal testimony and recommended a disallowance of recovery of $321 million for the entire NSP System (based on a total capitalized cost of $748 million), and no return on $107 million. The recommended disallowance is primarily based on criticism of NSP-Minnesota’s management of the project.
NSP-Minnesota believes the costs of the project were prudent and its decisions and actions do not warrant a disallowance. NSP-Minnesota’s testimony is summarized as follows:
•	The plant is cost-effective for customers;
•	The project benefits include providing carbon-free generation through a life extension and uprate of the plant for an installed capacity of about $1,000 per kilowatt;
•	The DOC was incorrect in its analysis that 85 percent of the expenditures were associated with the uprate; and
•	NSP-Minnesota made prudent decisions based on the information available at the time the decisions were made.
The next steps in the procedural schedule are expected to be as follows:
•	Initial Briefs — Oct. 31, 2014;
•	Reply Briefs — Nov. 21, 2014;
•	ALJ Report — Dec. 31, 2014; and
•	MPUC Deliberation — March 6, 2015.
A final MPUC order is anticipated in the second quarter of 2015. The MPUC decision for the Monticello prudence review is expected to be reflected in the final results of NSP-Minnesota’s pending Minnesota 2014 Multi-Year electric rate case.
Electric, Purchased Gas and Resource Adjustment Clauses
Gas Utility Infrastructure Cost (GUIC) Rider — In August 2014, NSP-Minnesota filed a GUIC rider with the MPUC for approval to recover the cost of natural gas infrastructure investments in Minnesota to improve safety and reliability. Costs include funding for pipeline assessment and system upgrades in 2015 and beyond, as well as deferred costs from NSP-Minnesota’s existing sewer separation and pipeline integrity management programs. Sewer separation costs stem from the inspection of sewer lines and the redirection of gas pipes in the event their paths are in conflict. NSP-Minnesota is requesting recovery of approximately $14.9 million from Minnesota gas utility customers beginning Jan. 1, 2015, including $4.8 million of deferred sewer separation and integrity management costs which is the 2015 portion of a five year amortization. In October 2014, the DOC recommended approval of NSP-Minnesota’s request for recovery of the GUIC rider, using the capital structure and cost of capital proposed in the current electric case and a five year amortization period for the deferred costs. An MPUC decision is anticipated by the end of 2014.
Pending Regulatory Proceedings — South Dakota Public Utilities Commission (SDPUC)
South Dakota 2015 Electric Rate Case — In June 2014, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $15.6 million annually, or 8.0 percent, effective Jan. 1, 2015. The request is based on a 2013 historic test year adjusted for certain known and measurable changes for 2014 and 2015, a requested ROE of 10.25 percent, an average rate base of $433.2 million and an equity ratio of 53.86 percent. This request reflects NSP-Minnesota’s proposal to move recovery of approximately $9.0 million for certain Transmission Cost Recovery (TCR) rider and Infrastructure rider projects to base rates.
The major components of the request are as follows:
(Millions of Dollars)		Request
Nuclear investments and operating costs		$	13.4
Other production, transmission and distribution		5
Technology improvements		2.1
Pension and operating and maintenance (O&M) expenses		1.6
Wind generation facilities		1.4
Capital structure		1.1
Incremental increase to base rates		$	24.6
Infrastructure rider to be included in base rates		$	(8.4	)
TCR rider to be included in base rates		(0.6		)
Net request		$	15.6
At this time, the case is in the discovery phase and further procedure scheduling may be established during the fourth quarter of 2014. In November 2014, NSP-Minnesota plans to file a request with the SDPUC for interim rates, effective Jan. 1, 2015. Final rates are anticipated to be effective in the first quarter of 2015.
Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)
Midcontinent Independent System Operator, Inc. (MISO) ROE Complaint — In November 2013, a group of customers filed a complaint at the FERC against MISO transmission owners, including NSP-Minnesota and NSP-Wisconsin. The complaint argues for a reduction in the ROE applicable to transmission formula rates in the MISO region from 12.38 percent to 9.15 percent, a prohibition on capital structures in excess of 50 percent equity, and the removal of ROE adders (including those for regional transmission organization (RTO) membership and being an independent transmission company), effective Nov. 12, 2013.
In January 2014, Xcel Energy filed an answer to the complaint asserting that the 9.15 percent ROE would be unreasonable and that the complainants failed to demonstrate the NSP System equity capital structure was unreasonable. The MISO transmission owners separately answered the complaint, arguing the complaint should be dismissed.
In June 2014, the FERC issued an order in a different ROE proceeding adopting a new ROE methodology for electric utilities. The new ROE methodology requires electric utilities to use a two-step discounted cash flow analysis to estimate cost of equity that incorporates both short-term and long-term growth projections.
In October 2014, the FERC upheld the determination of the long term growth rate to be used together with a short term growth rate in its new ROE methodology. The FERC separately set the ROE complaint against the MISO transmission owners for settlement judge and hearing procedures, which are expected to begin later this year. The FERC directed parties to apply this methodology, but denied the complaints related to equity capital structures and ROE adders. The FERC established a Nov. 12, 2013 refund effective date. NSP-Minnesota recorded a current regulatory liability representing the current best estimate of a refund obligation associated with the new ROE as of Sept. 30, 2014. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $5 million and $7 million annually for NSP-Minnesota and NSP-Wisconsin.

Commitments_and_Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	Commitments and Contingencies
	Except to the extent noted below and in Note 5, the circumstances set forth in Notes 10, 11 and 12 to the consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2013 appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to NSP-Minnesota’s financial position.
	Purchased Power Agreements (PPAs)
	Under certain PPAs, NSP-Minnesota purchases power from independent power producing entities for which NSP-Minnesota is required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which NSP-Minnesota procures the natural gas required to produce the energy that it purchases. These specific PPAs create a variable interest in the associated independent power producing entity.
	NSP-Minnesota had approximately 1,069 MW of capacity under long-term PPAs as of Sept. 30, 2014 and Dec. 31, 2013 with entities that have been determined to be variable interest entities. NSP-Minnesota has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have expiration dates through 2028.
	Guarantees — Under NSP-Minnesota’s railcar lease agreement, accounted for as an operating lease, NSP-Minnesota guarantees the lessor proceeds from sale of the leased assets at the end of the lease term will at least equal the guaranteed residual value. The guarantee issued by NSP-Minnesota limits its exposure to a maximum amount stated in the guarantee; however, NSP-Minnesota expects sale proceeds to exceed the guaranteed amount. This lease agreement expires in 2019.
	The following table presents the guarantee issued and outstanding for NSP-Minnesota:
	(Millions of Dollars)	Sept. 30, 2014		Dec. 31, 2013
	Guarantees issued and outstanding	$	4.9	$	9.2
Environmental Loss Contingency Disclosure [Text Block]	'
	Environmental Contingencies
	Environmental Requirements
	Water and waste
	Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In June 2013, the U.S. Environmental Protection Agency (EPA) published a proposed ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. The final rule is now expected in September 2015. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017, but no later than July 2022. The impact of this rule on NSP-Minnesota is uncertain at this time.
	Federal CWA Section 316(b) — Section 316(b) of the federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. The EPA published the final 316(b) rule in August 2014. The rule prescribes technology for protecting fish that get stuck on plant intake screens (known as impingement) and describes a process for site-specific determinations by each state for sites that must protect the small aquatic organisms that pass through the intake screens into the plant cooling systems (known as entrainment). The timing of compliance with the requirements will vary from plant-to-plant since the new rule does not have a final compliance deadline. NSP-Minnesota estimates the likely cost for complying with impingement requirements is approximately $42 million. NSP-Minnesota believes at least four plants could be required by state regulators to make improvements to reduce entrainment. The exact cost of the entrainment improvements is uncertain, but could be up to $180 million depending on the outcome of certain entrainment studies and cost-benefit analyses. NSP-Minnesota anticipates these costs will be fully recoverable in rates.
	Federal CWA Waters of the United States Rule — In April 2014, the EPA and the U.S. Army Corps of Engineers issued a proposed rule that significantly expands the types of water bodies regulated under the CWA. If finalized as proposed, this rule could delay the siting of new pipelines, transmission lines and distribution lines, increase project costs and expand permitting and reporting requirements. The ultimate impact of the proposed rule will depend on the specific requirements of the final rule and cannot be determined at this time. A final rule is not anticipated before the first quarter of 2015.
	Air
	EPA Greenhouse Gas (GHG) Permitting — In 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which were applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold. These rules were upheld by the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit), but in June 2014 the U.S. Supreme Court reversed the EPA’s GHG emission thresholds for this program. The Supreme Court decided the EPA could not adopt GHG thresholds that would require permitting for new and modified large stationary sources. However, the Supreme Court also decided if a new or modified stationary source becomes subject to the permitting requirements by exceeding emission thresholds for other pollutants, then GHG emissions may be evaluated as part of the permitting process. NSP-Minnesota is unable to determine the cost of compliance with these new EPA requirements as it is not clear whether these requirements will apply to future changes at NSP-Minnesota’s power plants.
	GHG Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. Comments are due to the EPA on Dec. 1, 2014 and a final rule is anticipated in June 2015. Following adoption of the final rule, states must develop implementation plans by June 2016, with the possibility of an extension to June 2017 (June 2018 if submitting a joint plan with other states). Among other things, the proposed rule would require that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA’s state-specific interim (2020-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in states in which NSP-Minnesota operates. It is not possible to evaluate the impact of existing source standards until the EPA promulgates a final rule and states have adopted their applicable state plans.
	GHG New Source Performance Standard (NSPS) Proposal — In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which would set performance standards (maximum carbon dioxide emission rates) for coal- and natural gas-fired power plants. For coal power plants, the NSPS requires an emissions level equivalent to partial carbon capture and storage (CCS) technology; for gas-fired power plants, the NSPS reflects emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.
	GHG NSPS for Modified and Reconstructed Power Plants — In June 2014, the EPA published a proposed NSPS that would apply to GHG emissions from power plants that are modified or reconstructed. A final rule is anticipated in June 2015. A modification is a change to an existing source that increases the maximum achievable hourly rate of emissions. A reconstruction involves the replacement of components at a unit to the extent that the capital cost of the new components exceeds 50 percent of the capital cost of an entirely new comparable unit. The proposed standards would not require installation of CCS technology. Instead, the proposed standard for coal-fired power plants would require a combination of best operating practices and equipment upgrades. The proposal for gas-fired power plants would require emissions standards based on efficient combined cycle technology. It is not possible to evaluate the impact of these proposed standards until the final requirements are known. In addition, it is not clear whether these requirements, once adopted, would apply to future changes at NSP-Minnesota’s power plants.
	Cross-State Air Pollution Rule (CSAPR) — In 2011, the EPA issued the CSAPR to address long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO2) and nitrous oxide (NOx) from utilities in the eastern half of the United States, including Minnesota. The CSAPR set more stringent requirements than the proposed Clean Air Transport Rule. The rule also creates an emissions trading program.
	In August 2012, the D.C. Circuit vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated the EPA must continue administering the Clean Air Interstate Rule (CAIR) pending adoption of a valid replacement. In April 2014, the U.S. Supreme Court reversed and remanded the case to the D.C. Circuit. The Supreme Court held that the EPA’s rule design did not violate the Clean Air Act and that states had received adequate opportunity to develop their own plans. Because the D.C. Circuit overturned the CSAPR on two over-arching issues, there are many other issues the D.C. Circuit did not rule on that will now need to be considered on remand. In June 2014, the EPA filed a motion with the D.C. Circuit asking it to lift the stay of the CSAPR. The EPA requested the CSAPR’s 2012 compliance obligations be imposed starting in January 2015. The D.C. Circuit granted the EPA’s motion in October 2014. In addition, the D.C. Circuit set a briefing schedule and plans to hear arguments on the remaining issues in the case in March 2015.
	NSP-Minnesota can operate within its CSAPR emission allowance allocations, particularly given the cessation of coal operations at Black Dog Units 3 and 4 in early 2015. CSAPR compliance in 2015 is not expected to have a material impact on the results of operations, financial position or cash flows. The EPA will begin to administer the CSAPR in 2015.
	CAIR — In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions. The CAIR does not currently apply to Minnesota.
	Regional Haze Rules — The regional haze program is designed to address widespread, regionally homogeneous haze that results from emissions from a multitude of sources. In 2005, the EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In its first regional haze state implementation plan (SIP), Minnesota identified the NSP-Minnesota facilities that will have to reduce SO2, NOx and PM emissions under BART and set emissions limits for those facilities.
	In 2009, the Minnesota Pollution Control Agency (MPCA) approved a SIP and submitted it to the EPA for approval. The MPCA’s source-specific BART limits for Sherco Units 1 and 2 require combustion controls for NOx and scrubber upgrades for SO2. The MPCA concluded selective catalytic reduction (SCRs) should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs. The combustion controls have been installed and the scrubber upgrades, to be completed by January 2015, are underway. These emission controls are projected to cost approximately $50 million, of which $45.8 million has already been spent. NSP-Minnesota anticipates these costs will be fully recoverable in rates.
	After the CSAPR was adopted in 2011, the MPCA supplemented its SIP, determining that CSAPR meets BART requirements, but also implementing its source-specific BART determination for Sherco Units 1 and 2 from the 2009 SIP. In June 2012, the EPA approved the SIP for electric generating units and also approved the source-specific emission limits for Sherco Units 1 and 2 as strengthening the SIP, but avoided characterizing them as BART limits.
	In August 2012, the National Parks Conservation Association, Sierra Club, Voyageurs National Park Association, Friends of the Boundary Waters Wilderness, Minnesota Center for Environmental Advocacy and Fresh Energy appealed the EPA’s approval of the SIP to the U.S. Court of Appeals for the Eighth Circuit (Eighth Circuit). NSP-Minnesota and other regulated parties were denied intervention. In June 2013, the Eighth Circuit ordered this case to be held in abeyance until the U.S. Supreme Court decided the CSAPR case. In October 2014, the Eighth Circuit set a briefing schedule. The case will be briefed by early 2015. An argument date has not been set. If this litigation ultimately results in further EPA proceedings concerning the SIP, such proceedings may consider whether SCRs should be required for Sherco Units 1 and 2.
	Reasonably Attributable Visibility Impairment (RAVI) — RAVI is intended to address observable impairment from a specific source such as distinct, identifiable plumes from a source’s stack to a national park. In 2009, the U.S. Department of the Interior (DOI) certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from Sherco Units 1 and 2. The EPA is required to make its own determination whether there is RAVI-type impairment in these parks and examine which sources may cause or contribute to any RAVI impact that is identified. After studying the national parks and evaluating multiple sources, if the EPA finds that Sherco Units 1 and 2 cause or contribute to RAVI in the national parks, the EPA would then evaluate whether the level of controls required by the MPCA is appropriate. The EPA has stated it plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the RAVI program.
	In December 2012, a lawsuit against the EPA was filed in the U.S. District Court for the District of Minnesota by the following organizations: National Parks Conservation Association, Minnesota Center for Environmental Advocacy, Friends of the Boundary Waters Wilderness, Voyageurs National Park Association, Fresh Energy and Sierra Club. The lawsuit alleges the EPA has failed to perform a nondiscretionary duty to determine BART for Sherco Units 1 and 2 under the RAVI program. The EPA filed an answer denying the allegations. The District Court denied NSP-Minnesota’s motion to intervene in July 2013. NSP-Minnesota appealed this decision to the Eighth Circuit, which on July 23, 2014, reversed the District Court and found that NSP-Minnesota has standing and a right to intervene.
	In June 2014, the EPA and the plaintiffs lodged a consent decree with the District Court. The consent decree recites it will be subject to public comment. The EPA will then evaluate comments and determine whether to enter the consent decree with the District Court. The consent decree establishes a schedule whereby the EPA would issue a proposal on Feb. 27, 2015, determining whether visibility impairment in the national parks is reasonably attributable to Sherco Units 1 and 2. If the EPA determines that it is, the consent decree requires the EPA to make a final RAVI BART determination for these units by Aug. 31, 2015. If the EPA determines that it is not, the EPA would not determine BART for Sherco Units 1 and 2. NSP-Minnesota filed comments opposing the proposed consent decree and will object to its entry given NSP-Minnesota’s right to intervene in the litigation and thus participate in the negotiation of any purported settlement of the case.
	Revisions to National Ambient Air Quality Standards (NAAQS) for PM — In December 2012, the EPA lowered the primary health-based NAAQS for annual average fine PM and retained the current daily standard for fine PM. In areas where NSP-Minnesota operates power plants, current monitored air concentrations are below the level of the final annual primary standard. In August 2014, EPA issued its proposed designations, which did not include areas in any states in which NSP-Minnesota operates. The EPA is expected to finalize its designation of non-compliant locations by December 2014. States would then study the sources of the nonattainment and make emission reduction plans to attain the standards. It is not possible to evaluate the impact of this regulation further until the final designations have been made.
Legal Matters and Contingencies	'
	Legal Contingencies
	NSP-Minnesota is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on NSP-Minnesota’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.
	Employment, Tort and Commercial Litigation
	Merricourt Wind Project Litigation — In April 2011, NSP-Minnesota terminated its agreements with enXco Development Corporation (enXco) for the development of a 150 MW wind project in southeastern North Dakota. NSP-Minnesota’s decision to terminate the agreements was based in part on enXco’s nonperformance of certain other conditions, including failure to obtain a Certificate of Site Compatibility and the failure to close on the contracts by an agreed upon date of March 31, 2011. In May 2011 enXco filed a lawsuit in the U.S. District Court in Minnesota seeking approximately $240 million for an alleged breach of contract. In April 2013, the U.S. District Court granted NSP-Minnesota’s motion for summary judgment and entered judgment in its favor. enXco subsequently appealed to the Eighth Circuit, which affirmed the U.S. District Court’s decision in July 2014. enXco has elected not to challenge this decision within the required time period which brings this matter to a close.
	Biomass Fuel Handling Reimbursement — NSP-Minnesota has a PPA through which it procures energy from Fibrominn, LLC (Fibrominn). Under this agreement, NSP-Minnesota is charged for certain costs of transporting biomass fuels that are delivered to Fibrominn’s generation facility. Fibrominn has demanded additional cost reimbursement for certain transportation costs incurred since 2007, as well as reimbursement for similar costs in future periods. Fibrominn claims that it is entitled to reimbursement from NSP-Minnesota for past transportation costs of approximately $20 million. NSP-Minnesota has evaluated Fibrominn’s claim and based on the terms of the PPA with Fibrominn and its current understanding of the facts, NSP-Minnesota disputes the validity of Fibrominn’s claim, on the ground that, among other things, it seeks to impose contractual obligations on NSP-Minnesota that are neither supported by the terms nor the intent of the PPA. NSP-Minnesota has concluded that a loss is reasonably possible with respect to this matter; however, given the surrounding uncertainties, NSP-Minnesota is currently unable to determine the amount of reasonably possible loss. If a loss were sustained, NSP-Minnesota would attempt to recover these fuel-related costs in rates. No accrual has been recorded for this matter.
	Nuclear Power Operations and Waste Disposal
	Nuclear Waste Disposal Litigation — In 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the United States requesting breach of contract damages for the DOE’s failure to begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contract between the United States and NSP-Minnesota. NSP-Minnesota sought contract damages in this lawsuit through Dec. 31, 2004. In September 2007, the Court awarded NSP-Minnesota $116.5 million in damages. In August 2007, NSP-Minnesota filed a second complaint; this lawsuit claimed damages for the period Jan. 1, 2005 through Dec. 31, 2008.
	In July 2011, the United States and NSP-Minnesota executed a settlement agreement resolving both lawsuits, providing an initial $100 million payment from the United States to NSP-Minnesota, and providing a method by which NSP-Minnesota can recover its spent fuel storage costs through 2013, estimated to be an additional $100 million. In January 2014, the United States proposed, and NSP-Minnesota accepted, an extension to the settlement agreement which will allow NSP-Minnesota to recover spent fuel storage costs through 2016. The extension does not address costs for used fuel storage after 2016; such costs could be the subject of future litigation. NSP-Minnesota has received a total of $181.9 million of settlement proceeds as of Sept. 30, 2014. NSP-Minnesota’s next claim submission, in the amount of $33.6 million, was filed May 15, 2014, for costs incurred in 2013. In August 2014, the DOE accepted the claim for $32.8 million and NSP-Minnesota expects to receive payment in November 2014. Amounts received from the installments, except for approved reductions such as legal costs, will be subsequently returned to customers through a reduction of future rate increases or credited through another regulatory mechanism.

Borrowings_and_Other_Financing

Borrowings and Other Financing Instruments	9 Months Ended
	Sep. 30, 2014
Debt Disclosure [Abstract]	'
Borrowings and Other Financing Instruments	'
	Borrowings and Other Financing Instruments
	Short-Term Borrowings
	Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. Money pool borrowings for NSP-Minnesota were as follows:
	(Amounts in Millions, Except Interest Rates)		Three Months Ended Sept. 30, 2014				Twelve Months Ended Dec. 31, 2013
	Borrowing limit		$	250			$	250
	Amount outstanding at period end		—				34
	Average amount outstanding		0.2				42
	Maximum amount outstanding		20				211
	Weighted average interest rate, computed on a daily basis		0.26		%		0.14		%
	Weighted average interest rate at period end		N/A				0.25
	Commercial Paper — NSP-Minnesota meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper outstanding for NSP-Minnesota was as follows:
	(Amounts in Millions, Except Interest Rates)		Three Months Ended Sept. 30, 2014				Twelve Months Ended Dec. 31, 2013
	Borrowing limit		$	500			$	500
	Amount outstanding at period end		—				131
	Average amount outstanding		31				97
	Maximum amount outstanding		96				347
	Weighted average interest rate, computed on a daily basis		0.24		%		0.34		%
	Weighted average interest rate at period end		N/A				0.25
	Letters of Credit — NSP-Minnesota uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Sept. 30, 2014 and Dec. 31, 2013, there were $23.9 million and $15.9 million of letters of credit outstanding, respectively, under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.
	Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, NSP-Minnesota must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
	At Sept. 30, 2014, NSP-Minnesota had the following committed credit facility available (in millions of dollars):
	Credit Facility (a)				Drawn (b)				Available
	$	500			$	23.9			$	476.1
	(a)	Credit facility has been amended to expire in October 2019.
	(b)	Includes outstanding letters of credit.
	All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. NSP-Minnesota had no direct advances on the credit facility outstanding at Sept. 30, 2014 and Dec. 31, 2013.
	Amended Credit Agreement — On Oct. 14, 2014, NSP-Minnesota entered into an amended five-year credit agreement with a syndicate of banks. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with an extension of maturity from July 2017 to October 2019. The borrowing limit for NSP-Minnesota remained at $500 million. The Eurodollar borrowing margin on the line of credit ranges from 87.5 to 175 basis points per year based on applicable long-term credit ratings. The commitment fee, calculated on the unused portion of the line of credit, ranges from 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.
	NSP-Minnesota has the right to request an extension of the revolving termination date for two additional one-year periods, subject to majority bank group approval.
	Long-Term Borrowings
	In May 2014, NSP-Minnesota issued $300 million of 4.125 percent first mortgage bonds due May 15, 2044.

Fair_Value_of_Financial_Assets

Fair Value of Financial Assets and Liabilities	9 Months Ended
	Sep. 30, 2014
Fair Value Disclosures [Abstract]	'
Fair Value of Financial Assets and Liabilities	'
	Fair Value of Financial Assets and Liabilities
	Fair Value Measurements
	The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows:
	Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.
	Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.
	Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.
	Specific valuation methods include the following:
	Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values.
	Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, international equity funds, private equity investments and real estate investments are measured using net asset values, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per-share market value. The investments in commingled funds and international equity funds may be redeemed for net asset value with proper notice. Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate investments may be redeemed with proper notice, which is typically quarterly with 45-90 days notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Based on NSP-Minnesota’s evaluation of its redemption rights, fair value measurements for private equity and real estate investments have been assigned a Level 3.
	Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.
	Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
	Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2. When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.
	Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments purchased from MISO, PJM Interconnection, LLC (PJM), Electric Reliability Council of Texas, Southwest Power Pool, Inc. (SPP) and New York Independent System Operator, generally referred to as financial transmission rights (FTRs). FTRs purchased from an RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by overall transmission load and other transmission constraints. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. NSP-Minnesota’s valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.
	If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model – including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3. Non-trading monthly FTR settlements are included in fuel and purchased energy cost recovery mechanisms, and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of NSP-Minnesota’s FTRs relative to its electric utility operations, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the consolidated financial statements of NSP-Minnesota.
	Non-Derivative Instruments Fair Value Measurements
	The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning the Monticello and PI nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments – all classified as available-for-sale. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust.
	NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning.
	Unrealized gains for the nuclear decommissioning fund were $287.5 million and $240.3 million at Sept. 30, 2014 and Dec. 31, 2013, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $58.8 million and $58.5 million at Sept. 30, 2014 and Dec. 31, 2013, respectively.
	The following tables present the cost and fair value of NSP-Minnesota’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at Sept. 30, 2014 and Dec. 31, 2013:
			Sept. 30, 2014
							Fair Value
	(Thousands of Dollars)		Cost				Level 1			Level 2				Level 3				Total
	Nuclear decommissioning fund (a)
	Cash equivalents		$	14,972			$	14,972		$	—			$	—			$	14,972
	Commingled funds		469,608				—			471,388				—				471,388
	International equity funds		78,812				—			85,856				—				85,856
	Private equity investments		74,222				—			—				97,004				97,004
	Real estate		45,075				—			—				63,973				63,973
	Debt securities:
	Government securities		34,379				—			29,726				—				29,726
	U.S. corporate bonds		80,196				—			79,248				—				79,248
	International corporate bonds		17,696				—			17,613				—				17,613
	Municipal bonds		235,751				—			240,907				—				240,907
	Asset-backed securities		9,226				—			9,347				—				9,347
	Mortgage-backed securities		23,554				—			23,696				—				23,696
	Equity securities:
	Common stock		377,287				555,711			—				—				555,711
	Total		$	1,460,778			$	570,683		$	957,781			$	160,977			$	1,689,441
	(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $29.2 million of miscellaneous investments.
			Dec. 31, 2013
							Fair Value
	(Thousands of Dollars)		Cost				Level 1			Level 2				Level 3				Total
	Nuclear decommissioning fund (a)
	Cash equivalents		$	33,281			$	33,281		$	—			$	—			$	33,281
	Commingled funds		457,986				—			452,227				—				452,227
	International equity funds		78,812				—			81,671				—				81,671
	Private equity investments		52,143				—			—				62,696				62,696
	Real estate		45,564				—			—				57,368				57,368
	Debt securities:
	Government securities		34,304				—			27,628				—				27,628
	U.S. corporate bonds		80,275				—			83,538				—				83,538
	International corporate bonds		15,025				—			15,358				—				15,358
	Municipal bonds		241,112				—			232,016				—				232,016
	Equity securities:
	Common stock		406,695				581,243			—				—				581,243
	Total		$	1,445,197			$	614,524		$	892,438			$	120,064			$	1,627,026
	(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $28.3 million of miscellaneous investments.
	The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three and nine months ended Sept. 30, 2014 and 2013:
	(Thousands of Dollars)		1-Jul-14				Purchases			Settlements				Gains				Transfers Out				Sept. 30, 2014
														Recognized as				of Level 3
														Regulatory
														Liabilities
	Private equity investments		$	81,123			$	11,125		$	—			$	4,756			$	—			$	97,004
Real estate		65,658				1,530			(5,876		)		2,661				—				63,973
Total		$	146,781			$	12,655		$	(5,876	)		$	7,417			$	—			$	160,977
(Thousands of Dollars)		1-Jul-13				Purchases			Settlements				Gains				Transfers Out of Level 3				Sept. 30, 2013
													Recognized as
													Regulatory
													Liabilities
Private equity investments		$	45,590			$	6,790		$	—			$	94			$	—			$	52,474
Real estate		38,140				11,288			—				1,928				—				51,356
Total		$	83,730			$	18,078		$	—			$	2,022			$	—			$	103,830
(Thousands of Dollars)		Jan. 1, 2014				Purchases			Settlements				Gains				Transfers Out				Sept. 30, 2014
													Recognized as				of Level 3
													Regulatory
													Liabilities
Private equity investments		$	62,696			$	22,078		$	—			$	12,230			$	—			$	97,004
Real estate		57,368				5,386			(5,876		)		7,095				—				63,973
Total		$	120,064			$	27,464		$	(5,876	)		$	19,325			$	—			$	160,977
(Thousands of Dollars)		Jan. 1, 2013				Purchases			Settlements				Gains				Transfers Out				Sept. 30, 2013
													Recognized as				of Level 3 (a)
													Regulatory
													Liabilities
Private equity investments		$	33,250			$	15,344		$	—			$	3,880			$	—			$	52,474
Real estate		39,074				18,106			(9,022		)		3,198				—				51,356
Asset-backed securities		2,067				—			—				—				(2,067		)		—
Mortgage-backed securities		30,209				—			—				—				(30,209		)		—
Total		$	104,600			$	33,450		$	(9,022	)		$	7,078			$	(32,276	)		$	103,830
(a)	Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements.
The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at Sept. 30, 2014:
		Final Contractual Maturity
(Thousands of Dollars)		Due in 1 Year				Due in 1 to 5			Due in 5 to 10				Due after 10				Total
		or Less				Years			Years				Years
Government securities		$	—			$	—		$	—			$	29,726			$	29,726
U.S. corporate bonds		303				15,878			62,985				82				79,248
International corporate bonds		—				4,266			13,347				—				17,613
Municipal bonds		807				34,188			41,744				164,168				240,907
Asset-backed securities		—				—			3,546				5,801				9,347
Mortgage-backed securities		—				—			—				23,696				23,696
Debt securities		$	1,110			$	54,332		$	121,622			$	223,473			$	400,537
Derivative Instruments Fair Value Measurements
NSP-Minnesota enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.
Interest Rate Derivatives — NSP-Minnesota enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.
At Sept. 30, 2014, accumulated other comprehensive losses related to interest rate derivatives included $0.8 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for any unsettled hedges, as applicable.
Wholesale and Commodity Trading Risk — NSP-Minnesota conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. NSP-Minnesota’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.
Commodity Derivatives — NSP-Minnesota enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, FTRs, vehicle fuel, and weather.
At Sept. 30, 2014, NSP-Minnesota had various vehicle fuel contracts designated as cash flow hedges extending through December 2016. NSP-Minnesota also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. NSP-Minnesota recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three and nine months ended Sept. 30, 2014 and 2013.
At Sept. 30, 2014, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included an immaterial amount of net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.
Additionally, NSP-Minnesota enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenue, net of amounts credited to customers under margin-sharing mechanisms.
The following table details the gross notional amounts of commodity forwards, options and FTRs at Sept. 30, 2014 and Dec. 31, 2013:
(Amounts in Thousands) (a)(b)		Sept. 30, 2014			Dec. 31, 2013
Megawatt hours of electricity		64,032			52,107
Million British thermal units of natural gas		5,702			2,470
Gallons of vehicle fuel		182			265
(a)	Amounts are not reflective of net positions in the underlying commodities.
(b)	Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.
The following tables detail the impact of derivative activity during the three and nine months ended Sept. 30, 2014 and 2013 on accumulated other comprehensive loss, regulatory assets and liabilities and income:
		Three Months Ended Sept. 30, 2014
		Pre-Tax Fair Value							Pre-Tax (Gains) Losses								Pre-Tax Losses
		Gains (Losses) Recognized							Reclassified into Income								Recognized
		During the Period in:							During the Period from:								During the Period in Income
(Thousands of Dollars)		Accumulated				Regulatory			Accumulated				Regulatory
		Other				(Assets) and Liabilities			Other				Assets and (Liabilities)
		Comprehensive Loss							Comprehensive Loss
Derivatives designated as cash flow hedges
Interest rate		$	—			$	—		$	350		(a)	$	—			$	—
Vehicle fuel and other commodity		(42		)		—			(9		)	(b)	—				—
Total		$	(42	)		$	—		$	341			$	—			$	—
Other derivative instruments
Commodity trading		$	—			$	—		$	—			$	—			$	(1,656	)	(c)
Electric commodity		—				(2,212		)	—				5,457			(d)	—
Natural gas commodity		—				(303		)	—				—				—
Total		$	—			$	(2,515	)	$	—			$	5,457			$	(1,656	)
		Nine Months Ended Sept. 30, 2014
		Pre-Tax Fair Value							Pre-Tax (Gains) Losses								Pre-Tax Gains (Losses)
		Gains (Losses) Recognized							Reclassified into Income								Recognized
		During the Period in:							During the Period from:								During the Period in Income
(Thousands of Dollars)		Accumulated				Regulatory			Accumulated				Regulatory
		Other				(Assets) and Liabilities			Other				Assets and (Liabilities)
		Comprehensive Loss							Comprehensive Loss
Derivatives designated as cash flow hedges
Interest rate		$	—			$	—		$	1,038		(a)	$	—			$	—
Vehicle fuel and other commodity		(32		)		—			(33		)	(b)	—				—
Total		$	(32	)		$	—		$	1,005			$	—			$	—
Other derivative instruments
Commodity trading		$	—			$	—		$	—			$	—			$	1,266		(c)
Electric commodity		—				(13,660		)	—				(18,930		)	(d)	—
Natural gas commodity		—				7,105			—				(9,306		)	(e)	(580		)	(e)
Other commodity		—				—			—				—				643			(c)
Total		$	—			$	(6,555	)	$	—			$	(28,236	)		$	1,329
		Three Months Ended Sept. 30, 2013
		Pre-Tax Fair Value							Pre-Tax (Gains) Losses								Pre-Tax Gains
		Gains (Losses) Recognized							Reclassified into Income								Recognized
		During the Period in:							During the Period from:								During the Period in Income
(Thousands of Dollars)		Accumulated				Regulatory			Accumulated				Regulatory
		Other				(Assets) and Liabilities			Other				Assets and(Liabilities)
		Comprehensive Loss							Comprehensive Loss
Derivatives designated as cash flow hedges
Interest rate		$	—			$	—		$	350		(a)	$	—			$	—
Vehicle fuel and other commodity		20				—			(13		)	(b)	—				—
Total		$	20			$	—		$	337			$	—			$	—
Other derivative instruments
Commodity trading		$	—			$	—		$	—			$	—			$	7,094		(c)
Electric commodity		—				921			—				9,823			(d)	—
Natural gas commodity		—				(49		)	—				—				—
Total		$	—			$	872		$	—			$	9,823			$	7,094
		Nine Months Ended Sept. 30, 2013
		Pre-Tax Fair Value							Pre-Tax (Gains) Losses								Pre-Tax Gains
		Gains (Losses) Recognized							Reclassified into Income								Recognized
		During the Period in:							During the Period from:								During the Period in Income
(Thousands of Dollars)		Accumulated				Regulatory			Accumulated				Regulatory
		Other				(Assets) and Liabilities			Other				Assets and(Liabilities)
		Comprehensive Loss							Comprehensive Loss
Derivatives designated as cash flow hedges
Interest rate		$	—			$	—		$	1,038		(a)	$	—			$	—
Vehicle fuel and other commodity		(7		)		—			(37		)	(b)	—				—
Total		$	(7	)		$	—		$	1,001			$	—			$	—
Other derivative instruments
Commodity trading		$	—			$	—		$	—			$	—			$	9,371		(c)
Electric commodity		—				61,314			—				(38,816		)	(d)	—
Natural gas commodity		—				(47		)	—				—				—
Total		$	—			$	61,267		$	—			$	(38,816	)		$	9,371
(a)	Amounts are recorded to interest charges.
(b)	Amounts are recorded to O&M expenses.
(c)	Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.
(d)	Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.
(e)	Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.
NSP-Minnesota had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 2014 and 2013. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.
Consideration of Credit Risk and Concentrations — NSP-Minnesota continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of NSP-Minnesota’s own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.
NSP-Minnesota employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.
NSP-Minnesota’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity and transmission activities. At Sept. 30, 2014, eight of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $21.4 million or 22 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. The remaining two significant counterparties, comprising $6.4 million or six percent of this credit exposure, was not rated by these agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade. All 10 of these significant counterparties are municipal or cooperative electric entities, or other utilities.
Credit Related Contingent Features — Contract provisions for derivative instruments that NSP-Minnesota enters into, including those recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale (NPNS) contracts and therefore not reflected on the balance sheet, may require the posting of collateral or settlement of the contracts for various reasons, including if NSP-Minnesota is unable to maintain its credit ratings. At Sept. 30, 2014 and Dec. 31, 2013, there were no derivative instruments in a liability position that would have required the posting of collateral or settlement of applicable outstanding contracts if the credit ratings of NSP-Minnesota were downgraded below investment grade.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that NSP-Minnesota’s ability to fulfill its contractual obligations is reasonably expected to be impaired. NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts as of Sept. 30, 2014 and Dec. 31, 2013.
Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Sept. 30, 2014:
		Sept. 30, 2014
		Fair Value											Fair Value Total				Counterparty Netting (b)
(Thousands of Dollars)		Level 1				Level 2			Level 3												Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity		$	—			$	2		$	—			$	2			$	(2	)		$	—
Other derivative instruments:
Commodity trading		—				18,912			4,609				23,521				(5,395		)		18,126
Electric commodity		—				—			48,883				48,883				(2,099		)		46,784
Natural gas commodity		—				3,736			—				3,736				—				3,736
Total current derivative assets		$	—			$	22,650		$	53,492			$	76,142			$	(7,496	)		68,646
PPAs (a)																					13,919
Current derivative instruments																					$	82,565
Noncurrent derivative assets
Other derivative instruments:
Commodity trading		$	—			$	13,269		$	—			$	13,269			$	(2,408	)		$	10,861
Total noncurrent derivative assets		$	—			$	13,269		$	—			$	13,269			$	(2,408	)		10,861
PPAs (a)																					1,974
Noncurrent derivative instruments																					$	12,835
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity		$	—			$	2		$	—			$	2			$	(2	)		$	—
Other derivative instruments:
Commodity trading		—				9,758			—				9,758				(9,336		)		422
Electric commodity		—				—			2,099				2,099				(2,099		)		—
Total current derivative liabilities		$	—			$	9,760		$	2,099			$	11,859			$	(11,437	)		422
PPAs (a)																					13,747
Current derivative instruments																					$	14,169
Noncurrent derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity		$	—			$	3		$	—			$	3			$	—			$	3
Other derivative instruments:
Commodity trading		—				3,066			—				3,066				(2,408		)		658
Total noncurrent derivative liabilities		$	—			$	3,069		$	—			$	3,069			$	(2,408	)		661
PPAs (a)																					135,703
Noncurrent derivative instruments																					$	136,364
(a)	In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
(b)	NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Sept. 30, 2014. At Sept. 30, 2014, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $3.9 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2013:
		Dec. 31, 2013
		Fair Value											Fair Value Total				Counterparty Netting (b)
(Thousands of Dollars)		Level 1				Level 2			Level 3												Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity		$	—			$	48		$	—			$	48			$	—			$	48
Other derivative instruments:
Commodity trading		—				17,854			1,167				19,021				(6,718		)		12,303
Electric commodity		—				—			30,692				30,692				(1,723		)		28,969
Natural gas commodity		—				1,986			—				1,986				—				1,986
Total current derivative assets		$	—			$	19,888		$	31,859			$	51,747			$	(8,441	)		43,306
PPAs (a)																					23,420
Current derivative instruments																					$	66,726
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity		$	—			$	16		$	—			$	16			$	(16	)		$	—
Other derivative instruments:
Commodity trading		—				32,074			3,395				35,469				(9,071		)		26,398
Total noncurrent derivative assets		$	—			$	32,090		$	3,395			$	35,485			$	(9,087	)		26,398
PPAs (a)																					10,483
Noncurrent derivative instruments																					$	36,881
Current derivative liabilities
Other derivative instruments:
Commodity trading		$	—			$	8,108		$	1,804			$	9,912			$	(9,912	)		$	—
Electric commodity		—				—			1,723				1,723				(1,723		)		—
Total current derivative liabilities		$	—			$	8,108		$	3,527			$	11,635			$	(11,635	)		—
PPAs (a)																					13,066
Current derivative instruments																					$	13,066
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading		$	—			$	14,382		$	—			$	14,382			$	(10,137	)		$	4,245
Total noncurrent derivative liabilities		$	—			$	14,382		$	—			$	14,382			$	(10,137	)		4,245
PPAs (a)																					147,406
Noncurrent derivative instruments																					$	151,651
(a)	In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
(b)	NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2013. At Dec. 31, 2013, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.2 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
The following table presents the changes in Level 3 commodity derivatives for the three and nine months ended Sept. 30, 2014 and 2013:
		Three Months Ended Sept. 30
(Thousands of Dollars)		2014				2013
Balance at July 1		$	71,452			$	47,218
Purchases		1,159				155
Settlements		(11,685		)		(9,342		)
Transfers out of Level 3		(1,093		)		—
Net transactions recorded during the period:
Gains recognized in earnings (a)		1,480				4,008
Losses recognized as regulatory assets and liabilities		(9,920		)		(571		)
Balance at Sept. 30		$	51,393			$	41,468
		Nine Months Ended Sept. 30
(Thousands of Dollars)		2014				2013
Balance at Jan. 1		$	31,727			$	16,649
Purchases		82,848				51,541
Settlements		(84,449		)		(30,294		)
Transfers out of Level 3		(1,093		)		—
Net transactions recorded during the period:
Gains recognized in earnings (a)		8,917				3,729
Gains (losses) recognized as regulatory assets and liabilities		13,443				(157		)
Balance at Sept. 30		$	51,393			$	41,468
(a)	These amounts relate to commodity derivatives held at the end of the period.
NSP-Minnesota recognizes transfers between levels as of the beginning of each period. The transfer of amounts from Level 3 to Level 2 in the three and nine months ended Sept. 30, 2014 was due to the valuation of certain long-term derivative contracts for which observable commodity pricing forecasts became a more significant input during the period. There were no transfers of amounts between levels for derivative instruments for the three and nine months ended Sept. 30, 2013.
Fair Value of Long-Term Debt
As of Sept. 30, 2014 and Dec. 31, 2013, other financial instruments for which the carrying amount did not equal fair value were as follows:
		Sept. 30, 2014							Dec. 31, 2013
(Thousands of Dollars)		Carrying				Fair Value			Carrying				Fair Value
		Amount							Amount
Long-term debt, including current portion		$	4,188,471			$	4,655,826		$	3,888,732			$	4,099,745
The fair value of NSP-Minnesota’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of Sept. 30, 2014 and Dec. 31, 2013, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

Other_Expense_Income_Net

Other (Expense) Income, Net	9 Months Ended
	Sep. 30, 2014
Other Income and Expenses [Abstract]	'
Other (Expense) Income, Net	'
	Other (Expense) Income, Net
	Other (expense) income, net consisted of the following:
		Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	(Thousands of Dollars)	2014			2013			2014			2013
	Interest income	$	247		$	389		$	4,001		$	4,041
	Other nonoperating income	25			17			431			138
	Insurance policy expense	(756		)	(1,553		)	(3,383		)	(4,176		)
	Other (expense) income, net	$	(484	)	$	(1,147	)	$	1,049		$	3

Segment_Information

Segment Information	9 Months Ended
	Sep. 30, 2014
Segment Reporting [Abstract]	'
Segment Information	'
	Segment Information
	Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by NSP-Minnesota’s chief operating decision maker. NSP-Minnesota evaluates performance based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.
	NSP-Minnesota has the following reportable segments: regulated electric utility, regulated natural gas utility and all other.
	•	NSP-Minnesota’s regulated electric utility segment generates, transmits and distributes electricity primarily in portions of Minnesota, North Dakota and South Dakota. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes NSP-Minnesota’s commodity trading operations.
	•	NSP-Minnesota’s regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota and North Dakota.
	•	Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include appliance repair services, nonutility real estate activities and revenues associated with processing solid waste into refuse-derived fuel.
	Asset and capital expenditure information is not provided for NSP-Minnesota’s reportable segments because as an integrated electric and natural gas utility, NSP-Minnesota operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.
	To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.
	(Thousands of Dollars)		Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
	Three Months Ended Sept. 30, 2014
	Operating revenues (a)(b)		$	1,121,055	$	62,339		$	6,819	$	—		$	1,190,213
	Intersegment revenues		284		143			—		(427		)	—
	Total revenues		$	1,121,339	$	62,482		$	6,819	$	(427	)	$	1,190,213
	Net income (loss)		$	134,969	$	(5,545	)	$	5,045	$	—		$	134,469
	(Thousands of Dollars)		Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
	Three Months Ended Sept. 30, 2013
	Operating revenues (a)(b)		$	1,157,134	$	53,724		$	6,618	$	—		$	1,217,476
	Intersegment revenues		190		141			—		(331		)	—
	Total revenues		$	1,157,324	$	53,865		$	6,618	$	(331	)	$	1,217,476
	Net income (loss)		$	149,939	$	(6,448	)	$	11,615	$	—		$	155,106
	(a)	Operating revenues include $116 million and $80 million of affiliate electric revenue for the three months ended Sept. 30, 2014 and 2013, respectively.
	(b)	Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended Sept. 30, 2014 and 2013.
	(Thousands of Dollars)		Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
	Nine Months Ended Sept. 30, 2014
	Operating revenues (a)(b)		$	3,190,252	$	528,252		$	20,794	$	—		$	3,739,298
	Intersegment revenues		700		639			—		(1,339		)	—
	Total revenues		$	3,190,952	$	528,891		$	20,794	$	(1,339	)	$	3,739,298
	Net income		$	284,035	$	21,555		$	12,509	$	—		$	318,099
	(Thousands of Dollars)		Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
	Nine Months Ended Sept. 30, 2013
	Operating revenues (a)(b)		$	3,079,679	$	396,461		$	19,416	$	—		$	3,495,556
	Intersegment revenues		489		539			—		(1,028		)	—
	Total revenues		$	3,080,168	$	397,000		$	19,416	$	(1,028	)	$	3,495,556
	Net income		$	298,133	$	17,286		$	19,353	$	—		$	334,772
	(a)	Operating revenues include $355 million and $301 million of affiliate electric revenue for the nine months ended Sept. 30, 2014 and 2013, respectively.
	(b)	Operating revenues include an immaterial amount of affiliate gas revenue for the nine months ended Sept. 30, 2014 and 2013, respectively.

Benefit_Plans_and_Other_Postre

Benefit Plans and Other Postretirement Benefits	9 Months Ended
	Sep. 30, 2014
Compensation and Retirement Disclosure [Abstract]	'
Benefit Plans and Other Postretirement Benefits	'
	Benefit Plans and Other Postretirement Benefits
	Components of Net Periodic Benefit Cost
		Three Months Ended Sept. 30
		2014			2013			2014			2013
	(Thousands of Dollars)	Pension Benefits						Postretirement Health
								Care Benefits
	Service cost	$	7,425		$	8,292		$	47		$	30
	Interest cost	11,827			10,934			1,248			1,225
	Expected return on plan assets	(15,730		)	(15,788		)	(75		)	(104		)
	Amortization of transition obligation	—			—			—			8
	Amortization of prior service cost (credit)	234			514			(759		)	(759		)
	Amortization of net loss	11,196			13,247			854			1,318
	Net periodic benefit cost	14,952			17,199			1,315			1,718
	Costs not recognized due to the effects of regulation	(7,312		)	(13,048		)	—			—
	Net benefit cost recognized for financial reporting	$	7,640		$	4,151		$	1,315		$	1,718
		Nine Months Ended Sept. 30
		2014			2013			2014			2013
	(Thousands of Dollars)	Pension Benefits						Postretirement Health
								Care Benefits
	Service cost	$	22,275		$	24,875		$	140		$	90
	Interest cost	35,481			32,801			3,745			3,675
	Expected return on plan assets	(47,190		)	(47,364		)	(226		)	(312		)
	Amortization of transition obligation	—			—			—			24
	Amortization of prior service cost (credit)	702			1,542			(2,277		)	(2,277		)
	Amortization of net loss	33,588			39,741			2,562			3,954
	Net periodic benefit cost	44,856			51,595			3,944			5,154
	Costs not recognized due to the effects of regulation	(22,383		)	(26,592		)	—			—
	Net benefit cost recognized for financial reporting	$	22,473		$	25,003		$	3,944		$	5,154
	In January 2014, contributions of $130.0 million were made across three of Xcel Energy’s pension plans, of which $52.1 million was attributable to NSP-Minnesota. Xcel Energy does not expect additional pension contributions during 2014.

Other_Comprehensive_Income

Other Comprehensive Income	9 Months Ended
	Sep. 30, 2014
Stockholders' Equity Note [Abstract]	'
Other Comprehensive Income	'
	Other Comprehensive Income
	Changes in accumulated other comprehensive income (loss), net of tax, for the three and nine months ended Sept. 30, 2014 and 2013 were as follows:
			Three Months Ended Sept. 30, 2014
	(Thousands of Dollars)		Gains and				Unrealized				Defined Benefit			Total
			Losses on Cash Flow Hedges				Gains and Losses on Marketable				Pension and
							Securities				Postretirement Items
	Accumulated other comprehensive (loss) income at July 1		$	(20,210	)		$	110			$	(1,182	)	$	(21,282	)
	Other comprehensive (loss) income before reclassifications		(25		)		2				—			(23		)
	Losses reclassified from net accumulated other comprehensive loss		187				—				5			192
	Net current period other comprehensive income		162				2				5			169
	Accumulated other comprehensive (loss) income at Sept. 30		$	(20,048	)		$	112			$	(1,177	)	$	(21,113	)
			Three Months Ended Sept. 30, 2013
	(Thousands of Dollars)		Gains and				Unrealized				Defined Benefit			Total
			Losses on Cash Flow Hedges				Gains and Losses on Marketable				Pension and
							Securities				Postretirement Items
	Accumulated other comprehensive loss at July 1		$	(21,024	)		$	(131	)		$	(1,662	)	$	(22,817	)
	Other comprehensive loss before reclassifications		14				112				—			126
	Losses reclassified from net accumulated other comprehensive loss		192				—				22			214
	Net current period other comprehensive income		206				112				22			340
	Accumulated other comprehensive loss at Sept. 30		$	(20,818	)		$	(19	)		$	(1,640	)	$	(22,477	)
			Nine Months Ended Sept. 30, 2014
	(Thousands of Dollars)		Gains and				Unrealized				Defined Benefit			Total
			Losses on Cash Flow Hedges				Gains and Losses on Marketable				Pension and
							Securities				Postretirement Items
	Accumulated other comprehensive (loss) income at Jan. 1		$	(20,609	)		$	73			$	(1,193	)	$	(21,729	)
	Other comprehensive (loss) income before reclassifications		(19		)		39				—			20
	Losses reclassified from net accumulated other comprehensive loss		580				—				16			596
	Net current period other comprehensive income		561				39				16			616
	Accumulated other comprehensive (loss) income at Sept. 30		$	(20,048	)		$	112			$	(1,177	)	$	(21,113	)
			Nine Months Ended Sept. 30, 2013
	(Thousands of Dollars)		Gains and				Unrealized				Defined Benefit			Total
			Losses on Cash Flow Hedges				Gains and Losses on Marketable				Pension and
							Securities				Postretirement Items
	Accumulated other comprehensive loss at Jan. 1		$	(21,393	)		$	(99	)		$	(1,707	)	$	(23,199	)
	Other comprehensive (loss) income before reclassifications		(5		)		80				—			75
	Losses reclassified from net accumulated other comprehensive loss		580				—				67			647
	Net current period other comprehensive income		575				80				67			722
	Accumulated other comprehensive loss at Sept. 30		$	(20,818	)		$	(19	)		$	(1,640	)	$	(22,477	)
	Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2014 and 2013 were as follows:
			Amounts Reclassified from
			Accumulated Other
			Comprehensive Loss
	(Thousands of Dollars)		Three Months Ended Sept. 30, 2014				Three Months Ended Sept. 30, 2013
	(Gains) losses on cash flow hedges:
	Interest rate derivatives		$	350		(a)	$	350		(a)
	Vehicle fuel derivatives		(9		)	(b)	(13		)	(b)
	Total, pre-tax		341				337
	Tax benefit		(154		)		(145		)
	Total, net of tax		187				192
	Defined benefit pension and postretirement (gains) losses:
	Amortization of net loss		59			(c)	85			(c)
	Prior service credit		(49		)	(c)	(47		)	(c)
	Total, pre-tax		10				38
	Tax benefit		(5		)		(16		)
	Total, net of tax		5				22
	Total amounts reclassified, net of tax		$	192			$	214
			Amounts Reclassified from
			Accumulated Other
			Comprehensive Loss
	(Thousands of Dollars)		Nine Months Ended Sept. 30, 2014				Nine Months Ended Sept. 30, 2013
	(Gains) losses on cash flow hedges:
	Interest rate derivatives		$	1,038		(a)	$	1,038		(a)
	Vehicle fuel derivatives		(33		)	(b)	(37		)	(b)
Total, pre-tax		1,005				1,001
Tax benefit		(425		)		(421		)
Total, net of tax		580				580
Defined benefit pension and postretirement (gains) losses:
Amortization of net loss		175			(c)	255			(c)
Prior service credit		(146		)	(c)	(141		)	(c)
Transition obligation		—			(c)	1			(c)
Total, pre-tax		29				115
Tax benefit		(13		)		(48		)
Total, net of tax		16				67
Total amounts reclassified, net of tax		$	596			$	647
(a)	Included in interest charges.
(b)	Included in O&M expenses.
(c)	Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for details regarding these benefit plans.

Selected_Balance_Sheet_Data_Ta

Selected Balance Sheet Data (Tables)	9 Months Ended
	Sep. 30, 2014
Balance Sheet Related Disclosures [Abstract]	'
Accounts receivable, net	'
	(Thousands of Dollars)	Sept. 30, 2014			Dec. 31, 2013
	Accounts receivable, net
	Accounts receivable	$	363,392		$	304,748
	Less allowance for bad debts	(20,933		)	(20,216		)
		$	342,459		$	284,532
Inventories	'
	(Thousands of Dollars)	Sept. 30, 2014			Dec. 31, 2013
	Inventories
	Materials and supplies	$	155,743		$	144,140
	Fuel	84,113			81,971
	Natural gas	59,947			53,804
		$	299,803		$	279,915
Property, plant and equipment, net	'
	(Thousands of Dollars)	Sept. 30, 2014			Dec. 31, 2013
	Property, plant and equipment, net
	Electric plant	$	14,176,125		$	13,530,767
	Natural gas plant	1,119,309			1,092,314
	Common and other property	509,956			503,168
	Construction work in progress	893,581			902,820
	Total property, plant and equipment	16,698,971			16,029,069
	Less accumulated depreciation	(5,954,356		)	(5,783,658		)
	Nuclear fuel	2,250,140			2,186,799
	Less accumulated amortization	(1,934,966		)	(1,842,688		)
		$	11,059,789		$	10,589,522

Income_Taxes_Tables

Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2014
Income Tax Disclosure [Abstract]	'
Reconciliation of Unrecognized Tax Benefits	'
	A reconciliation of the amount of unrecognized tax benefit is as follows:
	(Millions of Dollars)	Sept. 30, 2014			Dec. 31, 2013
	Unrecognized tax benefit — Permanent tax positions	$	5.3		$	8.5
	Unrecognized tax benefit — Temporary tax positions	16.1			16.7
	Total unrecognized tax benefit	$	21.4		$	25.2
Tax Benefits Associated with NOL and Tax Credit Carryforwards	'
	The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:
	(Millions of Dollars)	Sept. 30, 2014			Dec. 31, 2013
	NOL and tax credit carryforwards	$	(12.6	)	$	(12.4	)

Rate_Matters_Tables

Rate Matters (Tables)	9 Months Ended
	Sep. 30, 2014
Public Utilities, General Disclosures [Abstract]	'
South Dakota 2015 Electric Rate Case [Table Text Block]	'
	The major components of the request are as follows:
	(Millions of Dollars)		Request
	Nuclear investments and operating costs		$	13.4
	Other production, transmission and distribution		5
	Technology improvements		2.1
	Pension and operating and maintenance (O&M) expenses		1.6
	Wind generation facilities		1.4
	Capital structure		1.1
	Incremental increase to base rates		$	24.6
	Infrastructure rider to be included in base rates		$	(8.4	)
	TCR rider to be included in base rates		(0.6		)
	Net request		$	15.6
NSP-Minnesota's 2014 Electric Rate Case [Table Text Block]	'
	The following table summarizes the DOC’s and NSP-Minnesota’s recommendations and includes the estimated impact of certain agreed-upon true-up adjustments:
	2014 Rate Request (Millions of Dollars)		DOC			NSP-Minnesota
	NSP-Minnesota’s filed rate request		$	192.7		$	192.7
	Sales forecast		(43.2		)	(15.8		)
	ROE		(36.2		)	—
	Monticello EPU cost recovery		(33.9		)	—
	Monticello EPU depreciation deferral		—			(12.2		)
	Property taxes		(9.0		)	(9.0		)
	PI EPU		(5.1		)	(5.1		)
	Health care, pension and other benefits		(11.4		)	(1.9		)
	Other, net		(8.0		)	(6.5		)
	Total recommendation 2014 — unadjusted		$	45.9		$	142.2
	Estimated true-up adjustments:
	Sales forecast		$	18.3		$	(9.1	)
	Property taxes		3.9			3.9
	Total recommendation 2014 — adjusted		$	68.1		$	137
	2015 Rate Request (Millions of Dollars)		DOC			NSP-Minnesota
	NSP-Minnesota’s filed rate request		$	98.5		$	98.5
	Monticello EPU cost recovery		29.1			—
	Monticello EPU cost disallowance (a)		(10.2		)	—
	Excess depreciation reserve adjustment (b)		(22.7		)	—
	Depreciation		(17.5		)	—
	Monticello EPU depreciation deferral		—			1.6
	Monticello EPU step increase		—			10.1
	Property taxes		(3.3		)	(3.3		)
	Production tax credits to be included in base rates		(11.1		)	(11.1		)
	DOE settlement proceeds		10.1			10.1
	Emission chemicals		(1.6		)	(1.6		)
	Other, net		(4.8		)	1.7
	Total recommendation 2015 step increase		$	66.5		$	106
	Unadjusted cumulative total for 2014 and 2015 step increase		$	112.4		$	248.2
	Estimated adjusted cumulative total for 2014 and 2015 step increase		$	134.6		$	243
	(a)	In July 2014, the DOC recommended a disallowance of recovery of approximately $71.5 million of project costs on a Minnesota jurisdictional basis. This equates to a total NSP System disallowance of approximately $94 million. This would reduce NSP-Minnesota’s revenue requirement by approximately $10.2 million in 2015.
	(b)	Adjustment is due to timing differences and/or methodology of accelerating amortization of the excess depreciation reserve over three years.
	NSP-Minnesota’s revised rate request, moderation plan, interim rate adjustments and impacts on expenses are detailed below:
	(Millions of Dollars)		2014			Percentage		2015			Percentage
						Increase					Increase
	Rebuttal pre-moderation deficiency		$	250.6				$	67.8
	Evidentiary hearing adjustments		(27.3		)			11
	Revised pre-moderation deficiency		223.3					78.8
	Moderation plan:
	Excess depreciation reserve		(81.1		)			52.9
	DOE settlement proceeds		—					(25.7		)
	Revised rate request		142.2			5.10%		106			3.80%
	Interim rate adjustments		(65.3		)			65.3
	PI EPU		4.8					(4.8		)
	Revenue impact (a)		81.7					166.5
	Excess depreciation reserve		81.1					(45.7		)
	Sales forecast (b)		(9.1		)			—
	DOE settlement proceeds		—					25.7
	Estimated impact of request on operating income		$	153.7				$	146.5
	(a)	NSP-Minnesota’s total revenue for 2014 is capped at the interim rate level of $127 million and pre-tax operating income is capped at $208 million. This table demonstrates the impact of reducing NSP-Minnesota’s rebuttal request.
	(b)	NSP-Minnesota and the DOC have agreed to a sales true-up based on weather normalized sales for 2014, using standard weather coefficients. NSP-Minnesota periodically adjusts the coefficients in periods of extreme weather conditions to enhance weather impact estimates. As a result of the difference in the two methodologies, currently, approximately $9.1 million of revenue that NSP-Minnesota attributed to weather would be considered normal sales growth using the standard weather coefficients. The refund for the full year could vary from the estimate as of Sept. 30, 2014, depending on weather conditions.

Commitments_and_Contingencies_

Commitments and Contingencies Schedule of Guarantor Obligations (Tables)	9 Months Ended
	Sep. 30, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Guarantees Issued and Outstanding	'
	The following table presents the guarantee issued and outstanding for NSP-Minnesota:
	(Millions of Dollars)	Sept. 30, 2014		Dec. 31, 2013
	Guarantees issued and outstanding	$	4.9	$	9.2

Borrowings_and_Other_Financing1

Borrowings and Other Financing Instruments (Tables)	9 Months Ended
	Sep. 30, 2014
Borrowings and Other Financing Instruments [Abstract]	'
Credit Facilities	'
	At Sept. 30, 2014, NSP-Minnesota had the following committed credit facility available (in millions of dollars):
	Credit Facility (a)				Drawn (b)				Available
	$	500			$	23.9			$	476.1
	(a)	Credit facility has been amended to expire in October 2019.
	(b)	Includes outstanding letters of credit.
Money Pool	'
Borrowings and Other Financing Instruments [Abstract]	'
Short-Term Borrowings	'
	Money pool borrowings for NSP-Minnesota were as follows:
	(Amounts in Millions, Except Interest Rates)		Three Months Ended Sept. 30, 2014				Twelve Months Ended Dec. 31, 2013
	Borrowing limit		$	250			$	250
	Amount outstanding at period end		—				34
	Average amount outstanding		0.2				42
	Maximum amount outstanding		20				211
	Weighted average interest rate, computed on a daily basis		0.26		%		0.14		%
	Weighted average interest rate at period end		N/A				0.25
Commercial Paper	'
Borrowings and Other Financing Instruments [Abstract]	'
Short-Term Borrowings	'
	Commercial paper outstanding for NSP-Minnesota was as follows:
	(Amounts in Millions, Except Interest Rates)		Three Months Ended Sept. 30, 2014				Twelve Months Ended Dec. 31, 2013
	Borrowing limit		$	500			$	500
	Amount outstanding at period end		—				131
	Average amount outstanding		31				97
	Maximum amount outstanding		96				347
	Weighted average interest rate, computed on a daily basis		0.24		%		0.34		%
	Weighted average interest rate at period end		N/A				0.25

Fair_Value_of_Financial_Assets1

Fair Value of Financial Assets and Liabilities (Tables)	9 Months Ended
	Sep. 30, 2014
Fair Value Disclosures [Abstract]	'
Cost and Fair Value of Nuclear Decommissioning Fund Investments	'
	The following tables present the cost and fair value of NSP-Minnesota’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund at Sept. 30, 2014 and Dec. 31, 2013:
			Sept. 30, 2014
							Fair Value
	(Thousands of Dollars)		Cost				Level 1			Level 2				Level 3				Total
	Nuclear decommissioning fund (a)
	Cash equivalents		$	14,972			$	14,972		$	—			$	—			$	14,972
	Commingled funds		469,608				—			471,388				—				471,388
	International equity funds		78,812				—			85,856				—				85,856
	Private equity investments		74,222				—			—				97,004				97,004
	Real estate		45,075				—			—				63,973				63,973
	Debt securities:
	Government securities		34,379				—			29,726				—				29,726
	U.S. corporate bonds		80,196				—			79,248				—				79,248
	International corporate bonds		17,696				—			17,613				—				17,613
	Municipal bonds		235,751				—			240,907				—				240,907
	Asset-backed securities		9,226				—			9,347				—				9,347
	Mortgage-backed securities		23,554				—			23,696				—				23,696
	Equity securities:
	Common stock		377,287				555,711			—				—				555,711
	Total		$	1,460,778			$	570,683		$	957,781			$	160,977			$	1,689,441
	(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $29.2 million of miscellaneous investments.
			Dec. 31, 2013
							Fair Value
	(Thousands of Dollars)		Cost				Level 1			Level 2				Level 3				Total
	Nuclear decommissioning fund (a)
	Cash equivalents		$	33,281			$	33,281		$	—			$	—			$	33,281
	Commingled funds		457,986				—			452,227				—				452,227
	International equity funds		78,812				—			81,671				—				81,671
	Private equity investments		52,143				—			—				62,696				62,696
	Real estate		45,564				—			—				57,368				57,368
	Debt securities:
	Government securities		34,304				—			27,628				—				27,628
	U.S. corporate bonds		80,275				—			83,538				—				83,538
	International corporate bonds		15,025				—			15,358				—				15,358
	Municipal bonds		241,112				—			232,016				—				232,016
	Equity securities:
	Common stock		406,695				581,243			—				—				581,243
	Total		$	1,445,197			$	614,524		$	892,438			$	120,064			$	1,627,026
	(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $28.3 million of miscellaneous investments.
Changes in Level 3 Nuclear Decommissioning Fund Investments	'
	The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three and nine months ended Sept. 30, 2014 and 2013:
	(Thousands of Dollars)		1-Jul-14				Purchases			Settlements				Gains				Transfers Out				Sept. 30, 2014
														Recognized as				of Level 3
														Regulatory
														Liabilities
	Private equity investments		$	81,123			$	11,125		$	—			$	4,756			$	—			$	97,004
	Real estate		65,658				1,530			(5,876		)		2,661				—				63,973
	Total		$	146,781			$	12,655		$	(5,876	)		$	7,417			$	—			$	160,977
	(Thousands of Dollars)		1-Jul-13				Purchases			Settlements				Gains				Transfers Out of Level 3				Sept. 30, 2013
														Recognized as
														Regulatory
														Liabilities
	Private equity investments		$	45,590			$	6,790		$	—			$	94			$	—			$	52,474
	Real estate		38,140				11,288			—				1,928				—				51,356
	Total		$	83,730			$	18,078		$	—			$	2,022			$	—			$	103,830
	(Thousands of Dollars)		Jan. 1, 2014				Purchases			Settlements				Gains				Transfers Out				Sept. 30, 2014
														Recognized as				of Level 3
														Regulatory
														Liabilities
	Private equity investments		$	62,696			$	22,078		$	—			$	12,230			$	—			$	97,004
	Real estate		57,368				5,386			(5,876		)		7,095				—				63,973
	Total		$	120,064			$	27,464		$	(5,876	)		$	19,325			$	—			$	160,977
	(Thousands of Dollars)		Jan. 1, 2013				Purchases			Settlements				Gains				Transfers Out				Sept. 30, 2013
														Recognized as				of Level 3 (a)
														Regulatory
														Liabilities
	Private equity investments		$	33,250			$	15,344		$	—			$	3,880			$	—			$	52,474
	Real estate		39,074				18,106			(9,022		)		3,198				—				51,356
	Asset-backed securities		2,067				—			—				—				(2,067		)		—
	Mortgage-backed securities		30,209				—			—				—				(30,209		)		—
	Total		$	104,600			$	33,450		$	(9,022	)		$	7,078			$	(32,276	)		$	103,830
	(a)	Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements.
Final Contractual Maturity Dates of Debt Securities in the Nuclear Decommissioning Fund by Asset Class	'
	The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at Sept. 30, 2014:
			Final Contractual Maturity
	(Thousands of Dollars)		Due in 1 Year				Due in 1 to 5			Due in 5 to 10				Due after 10				Total
			or Less				Years			Years				Years
	Government securities		$	—			$	—		$	—			$	29,726			$	29,726
	U.S. corporate bonds		303				15,878			62,985				82				79,248
	International corporate bonds		—				4,266			13,347				—				17,613
	Municipal bonds		807				34,188			41,744				164,168				240,907
	Asset-backed securities		—				—			3,546				5,801				9,347
	Mortgage-backed securities		—				—			—				23,696				23,696
	Debt securities		$	1,110			$	54,332		$	121,622			$	223,473			$	400,537
Gross Notional Amounts of Commodity Forwards, Options, and FTRs	'
	The following table details the gross notional amounts of commodity forwards, options and FTRs at Sept. 30, 2014 and Dec. 31, 2013:
	(Amounts in Thousands) (a)(b)		Sept. 30, 2014			Dec. 31, 2013
	Megawatt hours of electricity		64,032			52,107
	Million British thermal units of natural gas		5,702			2,470
	Gallons of vehicle fuel		182			265
	(a)	Amounts are not reflective of net positions in the underlying commodities.
	(b)	Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income	'
	The following tables detail the impact of derivative activity during the three and nine months ended Sept. 30, 2014 and 2013 on accumulated other comprehensive loss, regulatory assets and liabilities and income:
			Three Months Ended Sept. 30, 2014
			Pre-Tax Fair Value							Pre-Tax (Gains) Losses								Pre-Tax Losses
			Gains (Losses) Recognized							Reclassified into Income								Recognized
			During the Period in:							During the Period from:								During the Period in Income
	(Thousands of Dollars)		Accumulated				Regulatory			Accumulated				Regulatory
			Other				(Assets) and Liabilities			Other				Assets and (Liabilities)
			Comprehensive Loss							Comprehensive Loss
	Derivatives designated as cash flow hedges
	Interest rate		$	—			$	—		$	350		(a)	$	—			$	—
	Vehicle fuel and other commodity		(42		)		—			(9		)	(b)	—				—
	Total		$	(42	)		$	—		$	341			$	—			$	—
	Other derivative instruments
	Commodity trading		$	—			$	—		$	—			$	—			$	(1,656	)	(c)
	Electric commodity		—				(2,212		)	—				5,457			(d)	—
	Natural gas commodity		—				(303		)	—				—				—
	Total		$	—			$	(2,515	)	$	—			$	5,457			$	(1,656	)
			Nine Months Ended Sept. 30, 2014
			Pre-Tax Fair Value							Pre-Tax (Gains) Losses								Pre-Tax Gains (Losses)
			Gains (Losses) Recognized							Reclassified into Income								Recognized
			During the Period in:							During the Period from:								During the Period in Income
	(Thousands of Dollars)		Accumulated				Regulatory			Accumulated				Regulatory
			Other				(Assets) and Liabilities			Other				Assets and (Liabilities)
			Comprehensive Loss							Comprehensive Loss
	Derivatives designated as cash flow hedges
	Interest rate		$	—			$	—		$	1,038		(a)	$	—			$	—
	Vehicle fuel and other commodity		(32		)		—			(33		)	(b)	—				—
	Total		$	(32	)		$	—		$	1,005			$	—			$	—
	Other derivative instruments
	Commodity trading		$	—			$	—		$	—			$	—			$	1,266		(c)
	Electric commodity		—				(13,660		)	—				(18,930		)	(d)	—
	Natural gas commodity		—				7,105			—				(9,306		)	(e)	(580		)	(e)
	Other commodity		—				—			—				—				643			(c)
	Total		$	—			$	(6,555	)	$	—			$	(28,236	)		$	1,329
			Three Months Ended Sept. 30, 2013
			Pre-Tax Fair Value							Pre-Tax (Gains) Losses								Pre-Tax Gains
			Gains (Losses) Recognized							Reclassified into Income								Recognized
			During the Period in:							During the Period from:								During the Period in Income
	(Thousands of Dollars)		Accumulated				Regulatory			Accumulated				Regulatory
			Other				(Assets) and Liabilities			Other				Assets and(Liabilities)
			Comprehensive Loss							Comprehensive Loss
	Derivatives designated as cash flow hedges
	Interest rate		$	—			$	—		$	350		(a)	$	—			$	—
	Vehicle fuel and other commodity		20				—			(13		)	(b)	—				—
	Total		$	20			$	—		$	337			$	—			$	—
	Other derivative instruments
	Commodity trading		$	—			$	—		$	—			$	—			$	7,094		(c)
	Electric commodity		—				921			—				9,823			(d)	—
	Natural gas commodity		—				(49		)	—				—				—
	Total		$	—			$	872		$	—			$	9,823			$	7,094
			Nine Months Ended Sept. 30, 2013
			Pre-Tax Fair Value							Pre-Tax (Gains) Losses								Pre-Tax Gains
			Gains (Losses) Recognized							Reclassified into Income								Recognized
			During the Period in:							During the Period from:								During the Period in Income
	(Thousands of Dollars)		Accumulated				Regulatory			Accumulated				Regulatory
			Other				(Assets) and Liabilities			Other				Assets and(Liabilities)
			Comprehensive Loss							Comprehensive Loss
	Derivatives designated as cash flow hedges
	Interest rate		$	—			$	—		$	1,038		(a)	$	—			$	—
	Vehicle fuel and other commodity		(7		)		—			(37		)	(b)	—				—
	Total		$	(7	)		$	—		$	1,001			$	—			$	—
	Other derivative instruments
	Commodity trading		$	—			$	—		$	—			$	—			$	9,371		(c)
Electric commodity		—				61,314			—				(38,816		)	(d)	—
Natural gas commodity		—				(47		)	—				—				—
Total		$	—			$	61,267		$	—			$	(38,816	)		$	9,371
(a)	Amounts are recorded to interest charges.
(b)	Amounts are recorded to O&M expenses.
(c)	Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.
(d)	Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.
(e)	Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.
Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level	'
	Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Sept. 30, 2014:
			Sept. 30, 2014
			Fair Value											Fair Value Total				Counterparty Netting (b)
	(Thousands of Dollars)		Level 1				Level 2			Level 3												Total
	Current derivative assets
	Derivatives designated as cash flow hedges:
	Vehicle fuel and other commodity		$	—			$	2		$	—			$	2			$	(2	)		$	—
	Other derivative instruments:
	Commodity trading		—				18,912			4,609				23,521				(5,395		)		18,126
	Electric commodity		—				—			48,883				48,883				(2,099		)		46,784
	Natural gas commodity		—				3,736			—				3,736				—				3,736
	Total current derivative assets		$	—			$	22,650		$	53,492			$	76,142			$	(7,496	)		68,646
	PPAs (a)																					13,919
	Current derivative instruments																					$	82,565
	Noncurrent derivative assets
	Other derivative instruments:
	Commodity trading		$	—			$	13,269		$	—			$	13,269			$	(2,408	)		$	10,861
	Total noncurrent derivative assets		$	—			$	13,269		$	—			$	13,269			$	(2,408	)		10,861
	PPAs (a)																					1,974
	Noncurrent derivative instruments																					$	12,835
	Current derivative liabilities
	Derivatives designated as cash flow hedges:
	Vehicle fuel and other commodity		$	—			$	2		$	—			$	2			$	(2	)		$	—
	Other derivative instruments:
	Commodity trading		—				9,758			—				9,758				(9,336		)		422
	Electric commodity		—				—			2,099				2,099				(2,099		)		—
	Total current derivative liabilities		$	—			$	9,760		$	2,099			$	11,859			$	(11,437	)		422
	PPAs (a)																					13,747
	Current derivative instruments																					$	14,169
	Noncurrent derivative liabilities
	Derivatives designated as cash flow hedges:
	Vehicle fuel and other commodity		$	—			$	3		$	—			$	3			$	—			$	3
	Other derivative instruments:
	Commodity trading		—				3,066			—				3,066				(2,408		)		658
	Total noncurrent derivative liabilities		$	—			$	3,069		$	—			$	3,069			$	(2,408	)		661
	PPAs (a)																					135,703
	Noncurrent derivative instruments																					$	136,364
	(a)	In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
	(b)	NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Sept. 30, 2014. At Sept. 30, 2014, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $3.9 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
	The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2013:
			Dec. 31, 2013
			Fair Value											Fair Value Total				Counterparty Netting (b)
	(Thousands of Dollars)		Level 1				Level 2			Level 3												Total
	Current derivative assets
	Derivatives designated as cash flow hedges:
	Vehicle fuel and other commodity		$	—			$	48		$	—			$	48			$	—			$	48
	Other derivative instruments:
	Commodity trading		—				17,854			1,167				19,021				(6,718		)		12,303
	Electric commodity		—				—			30,692				30,692				(1,723		)		28,969
	Natural gas commodity		—				1,986			—				1,986				—				1,986
	Total current derivative assets		$	—			$	19,888		$	31,859			$	51,747			$	(8,441	)		43,306
	PPAs (a)																					23,420
	Current derivative instruments																					$	66,726
	Noncurrent derivative assets
	Derivatives designated as cash flow hedges:
	Vehicle fuel and other commodity		$	—			$	16		$	—			$	16			$	(16	)		$	—
	Other derivative instruments:
	Commodity trading		—				32,074			3,395				35,469				(9,071		)		26,398
	Total noncurrent derivative assets		$	—			$	32,090		$	3,395			$	35,485			$	(9,087	)		26,398
	PPAs (a)																					10,483
	Noncurrent derivative instruments																					$	36,881
	Current derivative liabilities
	Other derivative instruments:
Commodity trading		$	—			$	8,108		$	1,804			$	9,912			$	(9,912	)		$	—
Electric commodity		—				—			1,723				1,723				(1,723		)		—
Total current derivative liabilities		$	—			$	8,108		$	3,527			$	11,635			$	(11,635	)		—
PPAs (a)																					13,066
Current derivative instruments																					$	13,066
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading		$	—			$	14,382		$	—			$	14,382			$	(10,137	)		$	4,245
Total noncurrent derivative liabilities		$	—			$	14,382		$	—			$	14,382			$	(10,137	)		4,245
PPAs (a)																					147,406
Noncurrent derivative instruments																					$	151,651
(a)	In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
(b)	NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2013. At Dec. 31, 2013, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.2 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
Changes in Level 3 Commodity Derivatives	'
	The following table presents the changes in Level 3 commodity derivatives for the three and nine months ended Sept. 30, 2014 and 2013:
			Three Months Ended Sept. 30
	(Thousands of Dollars)		2014				2013
	Balance at July 1		$	71,452			$	47,218
	Purchases		1,159				155
	Settlements		(11,685		)		(9,342		)
	Transfers out of Level 3		(1,093		)		—
	Net transactions recorded during the period:
	Gains recognized in earnings (a)		1,480				4,008
	Losses recognized as regulatory assets and liabilities		(9,920		)		(571		)
	Balance at Sept. 30		$	51,393			$	41,468
			Nine Months Ended Sept. 30
	(Thousands of Dollars)		2014				2013
	Balance at Jan. 1		$	31,727			$	16,649
	Purchases		82,848				51,541
	Settlements		(84,449		)		(30,294		)
	Transfers out of Level 3		(1,093		)		—
	Net transactions recorded during the period:
	Gains recognized in earnings (a)		8,917				3,729
	Gains (losses) recognized as regulatory assets and liabilities		13,443				(157		)
	Balance at Sept. 30		$	51,393			$	41,468
	(a)	These amounts relate to commodity derivatives held at the end of the period.
Carrying Amount and Fair Value of Long-term Debt	'
	As of Sept. 30, 2014 and Dec. 31, 2013, other financial instruments for which the carrying amount did not equal fair value were as follows:
			Sept. 30, 2014							Dec. 31, 2013
	(Thousands of Dollars)		Carrying				Fair Value			Carrying				Fair Value
			Amount							Amount
	Long-term debt, including current portion		$	4,188,471			$	4,655,826		$	3,888,732			$	4,099,745

Other_Expense_Income_Net_Table

Other (Expense) Income, Net (Tables)	9 Months Ended
	Sep. 30, 2014
Other Income and Expenses [Abstract]	'
Other (Expense) Income, Net	'
	Other (expense) income, net consisted of the following:
		Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	(Thousands of Dollars)	2014			2013			2014			2013
	Interest income	$	247		$	389		$	4,001		$	4,041
	Other nonoperating income	25			17			431			138
	Insurance policy expense	(756		)	(1,553		)	(3,383		)	(4,176		)
	Other (expense) income, net	$	(484	)	$	(1,147	)	$	1,049		$	3

Segment_Information_Tables

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2014
Segment Reporting [Abstract]	'
Results by Reportable Segment	'
	(Thousands of Dollars)		Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
	Three Months Ended Sept. 30, 2014
	Operating revenues (a)(b)		$	1,121,055	$	62,339		$	6,819	$	—		$	1,190,213
	Intersegment revenues		284		143			—		(427		)	—
	Total revenues		$	1,121,339	$	62,482		$	6,819	$	(427	)	$	1,190,213
	Net income (loss)		$	134,969	$	(5,545	)	$	5,045	$	—		$	134,469
	(Thousands of Dollars)		Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
	Three Months Ended Sept. 30, 2013
	Operating revenues (a)(b)		$	1,157,134	$	53,724		$	6,618	$	—		$	1,217,476
	Intersegment revenues		190		141			—		(331		)	—
	Total revenues		$	1,157,324	$	53,865		$	6,618	$	(331	)	$	1,217,476
	Net income (loss)		$	149,939	$	(6,448	)	$	11,615	$	—		$	155,106
	(a)	Operating revenues include $116 million and $80 million of affiliate electric revenue for the three months ended Sept. 30, 2014 and 2013, respectively.
	(b)	Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended Sept. 30, 2014 and 2013.
	(Thousands of Dollars)		Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
	Nine Months Ended Sept. 30, 2014
	Operating revenues (a)(b)		$	3,190,252	$	528,252		$	20,794	$	—		$	3,739,298
	Intersegment revenues		700		639			—		(1,339		)	—
	Total revenues		$	3,190,952	$	528,891		$	20,794	$	(1,339	)	$	3,739,298
	Net income		$	284,035	$	21,555		$	12,509	$	—		$	318,099
	(Thousands of Dollars)		Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
	Nine Months Ended Sept. 30, 2013
	Operating revenues (a)(b)		$	3,079,679	$	396,461		$	19,416	$	—		$	3,495,556
	Intersegment revenues		489		539			—		(1,028		)	—
	Total revenues		$	3,080,168	$	397,000		$	19,416	$	(1,028	)	$	3,495,556
	Net income		$	298,133	$	17,286		$	19,353	$	—		$	334,772
	(a)	Operating revenues include $355 million and $301 million of affiliate electric revenue for the nine months ended Sept. 30, 2014 and 2013, respectively.
	(b)	Operating revenues include an immaterial amount of affiliate gas revenue for the nine months ended Sept. 30, 2014 and 2013, respectively.

Benefit_Plans_and_Other_Postre1

Benefit Plans and Other Postretirement Benefits (Tables)	9 Months Ended
	Sep. 30, 2014
Compensation and Retirement Disclosure [Abstract]	'
Components of Net Periodic Benefit Cost	'
	Components of Net Periodic Benefit Cost
		Three Months Ended Sept. 30
		2014			2013			2014			2013
	(Thousands of Dollars)	Pension Benefits						Postretirement Health
								Care Benefits
	Service cost	$	7,425		$	8,292		$	47		$	30
	Interest cost	11,827			10,934			1,248			1,225
	Expected return on plan assets	(15,730		)	(15,788		)	(75		)	(104		)
	Amortization of transition obligation	—			—			—			8
	Amortization of prior service cost (credit)	234			514			(759		)	(759		)
	Amortization of net loss	11,196			13,247			854			1,318
	Net periodic benefit cost	14,952			17,199			1,315			1,718
	Costs not recognized due to the effects of regulation	(7,312		)	(13,048		)	—			—
	Net benefit cost recognized for financial reporting	$	7,640		$	4,151		$	1,315		$	1,718
		Nine Months Ended Sept. 30
		2014			2013			2014			2013
	(Thousands of Dollars)	Pension Benefits						Postretirement Health
								Care Benefits
	Service cost	$	22,275		$	24,875		$	140		$	90
	Interest cost	35,481			32,801			3,745			3,675
	Expected return on plan assets	(47,190		)	(47,364		)	(226		)	(312		)
	Amortization of transition obligation	—			—			—			24
	Amortization of prior service cost (credit)	702			1,542			(2,277		)	(2,277		)
	Amortization of net loss	33,588			39,741			2,562			3,954
	Net periodic benefit cost	44,856			51,595			3,944			5,154
	Costs not recognized due to the effects of regulation	(22,383		)	(26,592		)	—			—
	Net benefit cost recognized for financial reporting	$	22,473		$	25,003		$	3,944		$	5,154

Other_Comprehensive_Income_Tab

Other Comprehensive Income (Tables)	9 Months Ended
	Sep. 30, 2014
Stockholders' Equity Note [Abstract]	'
Changes in Accumulated Other Comprehensive Income (Loss), Net of Tax	'
	Changes in accumulated other comprehensive income (loss), net of tax, for the three and nine months ended Sept. 30, 2014 and 2013 were as follows:
			Three Months Ended Sept. 30, 2014
	(Thousands of Dollars)		Gains and				Unrealized				Defined Benefit			Total
			Losses on Cash Flow Hedges				Gains and Losses on Marketable				Pension and
							Securities				Postretirement Items
	Accumulated other comprehensive (loss) income at July 1		$	(20,210	)		$	110			$	(1,182	)	$	(21,282	)
	Other comprehensive (loss) income before reclassifications		(25		)		2				—			(23		)
	Losses reclassified from net accumulated other comprehensive loss		187				—				5			192
	Net current period other comprehensive income		162				2				5			169
	Accumulated other comprehensive (loss) income at Sept. 30		$	(20,048	)		$	112			$	(1,177	)	$	(21,113	)
			Three Months Ended Sept. 30, 2013
	(Thousands of Dollars)		Gains and				Unrealized				Defined Benefit			Total
			Losses on Cash Flow Hedges				Gains and Losses on Marketable				Pension and
							Securities				Postretirement Items
	Accumulated other comprehensive loss at July 1		$	(21,024	)		$	(131	)		$	(1,662	)	$	(22,817	)
	Other comprehensive loss before reclassifications		14				112				—			126
	Losses reclassified from net accumulated other comprehensive loss		192				—				22			214
	Net current period other comprehensive income		206				112				22			340
	Accumulated other comprehensive loss at Sept. 30		$	(20,818	)		$	(19	)		$	(1,640	)	$	(22,477	)
			Nine Months Ended Sept. 30, 2014
	(Thousands of Dollars)		Gains and				Unrealized				Defined Benefit			Total
			Losses on Cash Flow Hedges				Gains and Losses on Marketable				Pension and
							Securities				Postretirement Items
	Accumulated other comprehensive (loss) income at Jan. 1		$	(20,609	)		$	73			$	(1,193	)	$	(21,729	)
	Other comprehensive (loss) income before reclassifications		(19		)		39				—			20
	Losses reclassified from net accumulated other comprehensive loss		580				—				16			596
	Net current period other comprehensive income		561				39				16			616
	Accumulated other comprehensive (loss) income at Sept. 30		$	(20,048	)		$	112			$	(1,177	)	$	(21,113	)
			Nine Months Ended Sept. 30, 2013
	(Thousands of Dollars)		Gains and				Unrealized				Defined Benefit			Total
			Losses on Cash Flow Hedges				Gains and Losses on Marketable				Pension and
							Securities				Postretirement Items
	Accumulated other comprehensive loss at Jan. 1		$	(21,393	)		$	(99	)		$	(1,707	)	$	(23,199	)
	Other comprehensive (loss) income before reclassifications		(5		)		80				—			75
	Losses reclassified from net accumulated other comprehensive loss		580				—				67			647
	Net current period other comprehensive income		575				80				67			722
	Accumulated other comprehensive loss at Sept. 30		$	(20,818	)		$	(19	)		$	(1,640	)	$	(22,477	)
Reclassifications out of Accumulated Other Comprehensive Loss	'
	Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2014 and 2013 were as follows:
			Amounts Reclassified from
			Accumulated Other
			Comprehensive Loss
	(Thousands of Dollars)		Three Months Ended Sept. 30, 2014				Three Months Ended Sept. 30, 2013
	(Gains) losses on cash flow hedges:
	Interest rate derivatives		$	350		(a)	$	350		(a)
	Vehicle fuel derivatives		(9		)	(b)	(13		)	(b)
	Total, pre-tax		341				337
	Tax benefit		(154		)		(145		)
	Total, net of tax		187				192
	Defined benefit pension and postretirement (gains) losses:
	Amortization of net loss		59			(c)	85			(c)
	Prior service credit		(49		)	(c)	(47		)	(c)
	Total, pre-tax		10				38
	Tax benefit		(5		)		(16		)
	Total, net of tax		5				22
	Total amounts reclassified, net of tax		$	192			$	214
			Amounts Reclassified from
			Accumulated Other
			Comprehensive Loss
	(Thousands of Dollars)		Nine Months Ended Sept. 30, 2014				Nine Months Ended Sept. 30, 2013
	(Gains) losses on cash flow hedges:
	Interest rate derivatives		$	1,038		(a)	$	1,038		(a)
	Vehicle fuel derivatives		(33		)	(b)	(37		)	(b)
	Total, pre-tax		1,005				1,001
	Tax benefit		(425		)		(421		)
	Total, net of tax		580				580
	Defined benefit pension and postretirement (gains) losses:
	Amortization of net loss		175			(c)	255			(c)
	Prior service credit		(146		)	(c)	(141		)	(c)
	Transition obligation		—			(c)	1			(c)
	Total, pre-tax		29				115
	Tax benefit		(13		)		(48		)
	Total, net of tax		16				67
	Total amounts reclassified, net of tax		$	596			$	647
	(a)	Included in interest charges.
	(b)	Included in O&M expenses.
	(c)	Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for details regarding these benefit plans.

Selected_Balance_Sheet_Data_Ac

Selected Balance Sheet Data, Accounts Receivable (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Accounts receivable, net	'	'
Accounts receivable	$363,392	$304,748
Less allowance for bad debts	-20,933	-20,216
Accounts receivable, net	$342,459	$284,532

Selected_Balance_Sheet_Data_In

Selected Balance Sheet Data, Inventories (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Public Utilities, Inventory [Line Items]	'	'
Inventories	$299,803	$279,915
Materials and supplies	'	'
Public Utilities, Inventory [Line Items]	'	'
Inventories	155,743	144,140
Fuel	'	'
Public Utilities, Inventory [Line Items]	'	'
Inventories	84,113	81,971
Natural gas	'	'
Public Utilities, Inventory [Line Items]	'	'
Inventories	$59,947	$53,804

Selected_Balance_Sheet_Data_Pr

Selected Balance Sheet Data, Property, Plant and Equipment (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	$16,698,971	$16,029,069
Less accumulated depreciation	-5,954,356	-5,783,658
Property, plant and equipment, net	11,059,789	10,589,522
Electric plant	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	14,176,125	13,530,767
Natural gas plant	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	1,119,309	1,092,314
Common and other property	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	509,956	503,168
Construction work in progress	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	893,581	902,820
Nuclear fuel	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	2,250,140	2,186,799
Less accumulated depreciation	($1,934,966)	($1,842,688)

Income_Taxes_Details

Income Taxes (Details) (USD $)	9 Months Ended	12 Months Ended		3 Months Ended	9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Sep. 30, 2014	Sep. 30, 2014
				Internal Revenue Service (IRS)	Internal Revenue Service (IRS)	State Jurisdiction (Minnesota)
Tax Audits [Abstract]	'	'	'	'	'	'
Number Of Years Of Tax Loss Carryback Period	'2	'	'	'	'	'
Tax Adjustments, Settlements, and Unusual Provisions	'	($12,000,000)	($15,000,000)	'	'	'
Year(s) no longer subject to audit as statute of limitations has expired	'	'	'	'	'2008	'
Earliest year subject to examination	'	'	'	'	'2009	'2009
Year(s) under examination	'	'	'	'2010 and 2011	'	'
Year of carryback claim under examination	'	'	'	'2009	'	'
Potential Tax Adjustments	'	'	'	'	10,000,000	'
Unrecognized Tax Benefits [Abstract]	'	'	'	'	'	'
Unrecognized tax benefit — Permanent tax positions	5,300,000	8,500,000	'	'	'	'
Unrecognized tax benefit — Temporary tax positions	16,100,000	16,700,000	'	'	'	'
Total unrecognized tax benefit	21,400,000	25,200,000	'	'	'	'
NOL and tax credit carryforwards	-12,600,000	-12,400,000	'	'	'	'
Upper bound of decrease in unrecognized tax benefit that is reasonably possible	-4,000,000	'	'	'	'	'
Amounts accrued for penalties related to unrecognized tax benefits	$0	$0	'	'	'	'

Rate_Matters_Details

Rate Matters (Details) (USD $)

1 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

1 Months Ended

Dec. 31, 2013

Sep. 30, 2014

Nov. 30, 2013

Sep. 30, 2014

Jul. 31, 2014

Nov. 30, 2013

Dec. 31, 2013

Jul. 31, 2014

Nov. 30, 2013

Aug. 31, 2014

Jul. 31, 2014

Nov. 30, 2013

Sep. 30, 2014

Oct. 31, 2013

Sep. 30, 2014

Aug. 31, 2014

Jul. 31, 2014

Nov. 30, 2013

Sep. 30, 2014

Aug. 31, 2014

Jun. 30, 2014

Aug. 31, 2014

Aug. 31, 2014

Aug. 31, 2014

Jul. 31, 2014

Jul. 31, 2014

Aug. 31, 2014

Jun. 30, 2014

Jan. 31, 2014

Nov. 30, 2013

Oct. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Aug. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Aug. 31, 2014

2014 Electric Rate Case [Member]

2014 Electric Rate Case [Member]

Electric Rate Case 2014, Rates 2014 [Member]

Electric Rate Case 2014, Rates 2014 [Member]

Nuclear Project Prudency Investigation [Member]

Electric Rate Case 2014, Rates 2015 [Member]

Minnesota Public Utilities Commission [Member]

Minnesota Department of Commerce [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

Minimum

Minimum

Minimum

Maximum

Maximum

Maximum

MW

2014 Electric Rate Case [Member]

Nuclear Project Prudency Investigation [Member]

2014 Electric Rate Case [Member]

Electric Rate Case 2014, Rates 2014 [Member]

Electric Rate Case 2014, Rates 2014 [Member]

Electric Rate Case 2014, Rates 2014 [Member]

Electric Rate Case 2014, Rates 2014 [Member]

Nuclear Project Prudency Investigation [Member]

Nuclear Project Prudency Investigation [Member]

Electric Rate Case 2014, Rates 2015 [Member]

Electric Rate Case 2014, Rates 2015 [Member]

Electric Rate Case 2014, Rates 2015 [Member]

Electric Rate Case 2014, Rates 2015 [Member]

Gas Utility Infrastructure Cost Rider 2015 [Member]

Electric Rate Case 2015 [Member]

Office of Attorney General (OAG) [Member]

Minnesota Department of Commerce [Member]

Minnesota Department of Commerce [Member]

Minnesota Department of Commerce [Member]

Minnesota Department of Commerce [Member]

Minnesota Department of Commerce [Member]

Federal Energy Regulatory Commission (FERC) [Member]

Federal Energy Regulatory Commission (FERC) [Member]

Federal Energy Regulatory Commission (FERC) [Member]

Subsequent Event

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

NSP Minnesota [Member]

Nuclear Project Prudency Investigation [Member]

2014 Electric Rate Case [Member]

Electric Rate Case 2014, Rates 2014 [Member]

Electric Rate Case 2014, Rates 2014 [Member]

Nuclear Project Prudency Investigation [Member]

Electric Rate Case 2014, Rates 2015 [Member]

FERC Proceeding, MISO ROE Complaint [Member]

FERC Proceeding, MISO ROE Complaint [Member]

FERC Proceeding, MISO ROE Complaint [Member]

Minnesota Department of Commerce [Member]

Nuclear Project Prudency Investigation [Member]

FERC Proceeding, MISO ROE Complaint [Member]

Minnesota Department of Commerce [Member]

Nuclear Project Prudency Investigation [Member]

FERC Proceeding, MISO ROE Complaint [Member]

Minnesota Department of Commerce [Member]

Gas Utility Infrastructure Cost Rider 2015 [Member]

MW

2014 Electric Rate Case [Member]

MW

2014 Electric Rate Case [Member]

Public Utilities, General Disclosures [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, ROE applicable to transmission formula rates in the MISO region, upper bound

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12.38%

'

'

'

'

'

'

'

Public Utilities, amount requested by public utility related to nuclear investments and operating costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$13,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Revenue deficiency based on a forecast test year

'

'

'

'

'

'

'

'

'

'

250,600,000

'

'

'

'

'

67,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, number of years rate case is applicable for

'

'

'

'

'

'

'

'

'2 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of factors attributable to project cost increases

'

'

'

'

'

'

'

'

'

'

'

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of years for the application process

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Rate Matters [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Rate Increase (Decrease), Amount

'

'

193,000,000

'

'

98,000,000

'

'

'

192,700,000

'

'

'

'

'

98,500,000

'

'

'

'

15,600,000

'

'

192,700,000

'

'

98,500,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Rate Increase (Decrease), Percentage

'

'

6.90%

'

'

3.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Return on Equity, Percentage

'

'

'

'

'

'

'

'

10.25%

'

'

'

'

'

'

'

'

'

'

'

10.25%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Rate Base, Amount

'

'

'

'

'

'

'

'

'

'

'

6,670,000,000

'

'

'

'

'

412,000,000

'

'

433,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Equity Capital Structure, Percentage

'

'

'

'

'

'

'

'

52.50%

'

'

'

'

'

'

'

'

'

'

'

53.86%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Interim Rate Increase (Decrease), Amount

127,000,000

'

'

'

'

'

127,000,000

'

'

'

'

'

127,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of months of actual weather normalized sales, true up adjustment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'12 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Interim Rate Increase (Decrease), Percentage

'

'

'

'

'

'

'

'

'

'

'

'

4.60%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, number of years excess depreciation reserve is amortized

'

'8 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

Costs for nuclear project, Amount

'

'

'

'

665,000,000

'

'

'

'

'

'

'

'

'

665,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Rate increase (decrease) recommended by third parties

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

66,500,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to Monticello EPU costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-33,900,000

'

'

29,100,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to Monticello EPU costs

'

'

'

'

'

'

'

'

'

0

'

'

'

'

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to an increase to sales forecast

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-43,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to an increase to sales forecast

'

'

'

'

'

'

'

'

'

-15,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to a lower return on equity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-36,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to a lower return on equity

'

'

'

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to health care, pension and other benefits

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-11,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to health care, pension and other benefits

'

'

'

'

'

'

'

'

'

-1,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to property taxes

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-9,000,000

-9,000,000

'

'

-3,300,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to property taxes

'

'

'

'

'

'

'

'

'

-9,000,000

'

'

'

'

'

-3,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to amortization of Prairie Island EPU costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-5,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to amortization of Prairie Island EPU costs

'

'

'

'

'

'

'

'

'

-5,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to other costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-8,000,000

'

'

-4,800,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to other costs

'

'

'

'

'

'

'

'

'

-6,500,000

'

'

'

'

'

1,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to depreciation expense

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-17,500,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to theoretical depreciation reserve

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to PTCs moving to base rates

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-11,100,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to PTCs moving to base rates

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-11,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to DOE settlement proceeds

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10,100,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to DOE settlement proceeds

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to emission chemicals

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-1,600,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to emission chemicals

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-1,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) by public utility related to the depreciation reserve

'

'

'

'

'

'

'

'

'

'

-81,100,000

'

'

'

'

'

52,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public utilities, Adjustment to requested rate increase (decrease) related to DOE settlement proceeds, amount

'

'

'

'

'

'

'

'

'

'

0

'

'

'

'

'

-25,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, rebuttal request to increase (decrease) 2014 rates by public utility

'

'

'

'

'

'

'

'

'

'

142,200,000

'

'

'

'

'

106,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

5.10%

'

'

'

'

'

3.80%

'

5.60%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

106,000,000

'

'

164,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested interim rate increase (decrease), amount

'

'

'

'

'

'

'

'

'

'

-65,300,000

'

'

'

'

'

65,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, adjustment to requested rate increase (decrease) related to prairie island EPU

'

'

'

'

'

'

'

'

'

'

4,800,000

'

'

'

'

'

-4,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Impact on revenue increase (decrease), amount

'

'

'

'

'

'

'

'

'

'

81,700,000

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Impact on revenue increase (decrease) maximum range, amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

166,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to approved rate increase (decrease) related to depreciation expense

'

'

'

'

'

'

'

'

'

'

81,100,000

'

'

'

'

'

-45,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Recommended rate increase (decrease) impact on pre-tax income, minimum range

'

'

'

'

'

'

'

'

'

'

153,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Recommended rate increase (decrease) impact on pre-tax income

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

146,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Recommended rate increase (decrease) impact on pre-tax income, cap

'

'

'

208,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested increase (decrease) to rider revenue

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

14,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utility, Deferred sewer separation costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of years cost deferral is amortized

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'5

'

'

'

'

'

'

Public Utilities, Rider costs to be recovered through base rates, amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, amount requested by public utility related to other production, transmission and distribution costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, amount requested by public utility related to technology improvements

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, amount requested by public utility related to pension and operating and maintenance expenses

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, amount requested by public utility related to wind generation facilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, amount requested by public utility related to capital structure

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Incremental base revenue requested

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

24,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, adjustment to requested rate increase (decrease) requested by public utility related to infrastructure rider recovery moving to base rates

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-8,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, adjustment to requested rate increase (decrease) requested by public utility related to TCR rider recovery moving to base rates

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total capitalized nuclear project costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

748,000,000

'

'

'

'

'

'

748,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Initial estimated nuclear project expenditures

'

'

'

'

'

'

'

'

'

'

'

'

'

'

320,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Total cost disallowances recommended by third parties

'

'

'

'

'

'

'

71,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

321,000,000

'

'

'

71,500,000

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, disallowance of project costs recommended by third parties impacting the NSP System

'

'

'

'

'

'

'

94,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

94,000,000

'

'

'

'

'

'

'

'

'

'

'

Number of megawatts of additional capacity

'

'

'

'

71

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of total project costs associated with project components required to achieve the EPU

'

'

'

'

85.00%

'

'

'

'

'

'

'

'

'

85.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, ROE applicable to transmission formula rates in the MISO region, lower bound

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9.15%

9.15%

'

'

'

'

'

'

'

Public Utilities, maximum equity capital structure percentage allowed per the complaint

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

Public Utilities, number of steps required for newly adopted ROE discounted cash flow methodology

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

Public Utilities, reduction of transmission revenue, net of expense due to the new ROE methodology, lower bound

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5,000,000

'

'

7,000,000

'

Number of sales forecast methodologies

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

Property tax forecast

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

141,000,000

'

'

145,000,000

Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to Monticello EPU depreciation deferrals

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

'

0

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to Monticello EPU depreciation deferrals

'

'

'

'

'

'

'

'

'

-12,200,000

'

'

'

'

'

1,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of the rate increase (decrease) recommended by third parties, unadjusted.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

45,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of public utility's amended requested rate increase (decrease) with regulatory agency, unadjusted.

'

'

'

'

'

'

'

'

'

142,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties, sales forecast true up.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

18,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by Public Utility, sales forecast true up.

'

'

'

'

'

'

'

'

'

-9,100,000

-9,100,000

[2]

'

'

'

'

'

0

'

'

'

'

'

'

'

-9,100,000

'

'

'

'

'

'

'

'

'

'

'

'

Facility generating capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

600

'

'

671

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by third party, property taxes true up.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility, property taxes true up.

'

'

'

'

'

'

'

'

'

3,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of the rate increase (decrease) recommended by third parties, adjusted.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

68,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of public utility's amended requested rate increase (decrease) with regulatory agency, adjusted.

'

'

'

'

'

'

'

'

'

137,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to Monticello EPU cost disallowance.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-10,200,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to Monticello EPU cost disallowance.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to excess depreciation reserve adjustment.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-22,700,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to excess depreciation reserve adjustment.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to Monticello EPU step increase.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by public utility related to Monticello EPU step increase.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Unadjusted cumulative total step increase (decrease) recommended by third parties.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

112,400,000

'

'

'

'

'

'

'

'

'

'

Amount of public utility's amended unadjusted cumulative total step up increase (decrease) with regulatory agency.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

248,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Estimated adjusted cumulative total step increase (decrease) recommended by third parties.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

134,600,000

'

'

'

'

'

'

'

'

'

'

Amount of public utility's amended estimated adjusted cumulative total step up increase (decrease) with regulatory agency.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

243,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) by public utility related to the evidentiary hearing adjustments

'

'

'

'

'

'

'

'

'

'

-27,300,000

'

'

'

'

'

11,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Amended revenue deficiency based on a forecast test year

'

'

'

'

'

'

'

'

'

'

223,300,000

'

'

'

'

'

78,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of recoverable investment, without a return

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

107,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cost per kilowatt of installed capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$1,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

[1]

NSP-Minnesota’s total revenue for 2014 is capped at the interim rate level of $127 million and pre-tax operating income is capped at $208 million. This table demonstrates the impact of reducing NSP-Minnesota’s rebuttal request.

[2]

NSP-Minnesota and the DOC have agreed to a sales true-up based on weather normalized sales for 2014, using standard weather coefficients. NSP-Minnesota periodically adjusts the coefficients in periods of extreme weather conditions to enhance weather impact estimates. As a result of the difference in the two methodologies, currently, approximately $9.1 million of revenue that NSP-Minnesota attributed to weather would be considered normal sales growth using the standard weather coefficients. The refund for the full year could vary from the estimate as of Sept. 30, 2014, depending on weather conditions.

Commitments_and_Contingencies_1

Commitments and Contingencies, Purchased Power Agreements (Details) (Independent Power Producing Entities)	3 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
	MW	MW
Independent Power Producing Entities	'	'
Purchased Power Agreements [Abstract]	'	'
Generating capacity (in MW)	1,069	1,069
Purchase Power Agreement Duration, Maximum (year)	'2028	'

Commitments_and_Contingencies_2

Commitments and Contingencies Commitments and Contingencies, Guarantees and Indemnifications (Details) (Payment or Performance Guarantee, USD $)	3 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Payment or Performance Guarantee	'	'
Guarantor Obligations [Line Items]	'	'
Lease Guarantee Expiration (year)	'2019	'
Guarantees issued and outstanding	$4.90	$9.20

Commitments_and_Contingencies_3

Commitments and Contingencies, Environmental Contingencies (Details) (USD $)	Jun. 30, 2014	Apr. 30, 2014	Sep. 30, 2014	Sep. 30, 2014
In Millions, unless otherwise specified	Greenhouse Gas New Source Performance Standard for Modified and Reconstructed Power Plants	Cross-State Air Pollution Rule	Capital Commitments	Capital Commitments
		Issue	Federal Clean Water Act Section 316(b)	Regional Haze Rules
			Plant
Environmental Requirements [Abstract]	'	'	'	'
Liability for estimated cost to comply with regulation	'	'	$42	$50
Minimum number of plants which could be required to make improvements to reduce entrainment	'	'	4	'
Liability for estimated cost to comply with entrainment regulation	'	'	180	'
Percentage of a comparable new plant's capital cost which would have to be exceeded to consider a project as a reconstruction under the proposed GHG NSPS for Modified and Reconstructed Power Plants (in hundredths)	50.00%	'	'	'
Number of issues on which the D.C. Circuit overturned the CSAPR	'	2	'	'
Estimated amount spent on projects to reduce NOx emissions on Sherco Units 1 and 2	'	'	'	$45.80

Commitments_and_Contingencies_4

Commitments and Contingencies, Legal Contingencies (Details) (NSP Minnesota [Member], USD $)	31-May-11	Apr. 30, 2011	Sep. 30, 2014	Aug. 31, 2014	Jul. 31, 2011	Sep. 30, 2007	Sep. 30, 2014	15-May-14
	Merricourt Wind Project Litigation [Member]	Merricourt Wind Project Litigation [Member]	Fibrominn Fuel Handling Dispute [Domain]	Nuclear Waste Disposal Litigation [Member]	Nuclear Waste Disposal Litigation [Member]	Nuclear Waste Disposal Litigation [Member]	Nuclear Waste Disposal Litigation [Member]	Nuclear Waste Disposal Litigation [Member]
		MW
Legal Contingencies [Abstract]	'	'	'	'	'	'	'	'
Accrual for legal contingency	'	'	$0	'	'	'	'	'
Generating capacity (in MW)	'	150	'	'	'	'	'	'
Minimum amount of damages claimed by plaintiff	240,000,000	'	20,000,000	'	'	'	'	'
Damages awarded	'	'	'	32,800,000	'	116,500,000	'	'
Storage costs for spent nuclear fuel	'	'	'	'	'	'	100,000,000	'
Cash payment received under settlement agreement	'	'	'	'	100,000,000	'	181,900,000	'
Claim submitted for storage costs for spent nuclear fuel	'	'	'	'	'	'	'	$33,600,000

Borrowings_and_Other_Financing2

Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) (USD $)	3 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Short-term Debt [Line Items]	'	'
Amount outstanding at period end	$0	$131,000,000
Money Pool	'	'
Short-term Debt [Line Items]	'	'
Borrowing limit	250,000,000	250,000,000
Amount outstanding at period end	0	34,000,000
Average amount outstanding	200,000	42,000,000
Maximum amount outstanding	20,000,000	211,000,000
Weighted average interest rate, computed on a daily basis (percentage)	0.26%	0.14%
Weighted average interest rate at period end (percentage)	'	0.25%
Commercial Paper	'	'
Short-term Debt [Line Items]	'	'
Borrowing limit	500,000,000	500,000,000
Amount outstanding at period end	0	131,000,000
Average amount outstanding	31,000,000	97,000,000
Maximum amount outstanding	$96,000,000	$347,000,000
Weighted average interest rate, computed on a daily basis (percentage)	0.24%	0.34%
Weighted average interest rate at period end (percentage)	'	0.25%

Borrowings_and_Other_Financing3

Borrowings and Other Financing Instruments, Letters of Credit (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014
In Thousands, unless otherwise specified			Letter of Credit	Letter of Credit	Letter of Credit
Line of Credit Facility [Line Items]	'	'	'	'	'
Term of letters of credit (in years)	'	'	'	'	'1 year
Short-term debt	$0	$131,000	$23,900	$15,900	'

Borrowings_and_Other_Financing4

Borrowings and Other Financing Instruments, Credit Facility (Details) (USD $)	Dec. 31, 2013	Sep. 30, 2014
		Credit Facility
Line of Credit Facility [Line Items]	'	'
Credit Facility	'	$500,000,000	[1]
Drawn	'	23,900,000	[2]
Available	'	476,100,000
Direct advances on the credit facility outstanding	$0	$0
[1]	Credit facility has been amended to expire in October 2019.
[2]	Includes outstanding letters of credit.

Borrowings_and_Other_Financing5

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Amended Credit Agreements (Details) (Credit Facility, USD $)	Sep. 30, 2014		Oct. 31, 2014	Oct. 14, 2014	Oct. 31, 2014	Oct. 31, 2014	Oct. 31, 2014	Oct. 31, 2014
			Subsequent Event	Subsequent Event	Subsequent Event	Subsequent Event	Subsequent Event	Subsequent Event
					Minimum	Maximum	Eurodollar	Eurodollar
							Minimum	Maximum
Line of Credit Facility [Line Items]	'		'	'	'	'	'	'
Amended Credit Agreements, Commencement Date	'		14-Oct-14	'	'	'	'	'
Amended Term (in years)	'		'5 years	'	'	'	'	'
Borrowing Limit	$500,000,000	[1]	'	$500,000,000	'	'	'	'
Borrowing Margin Based On Long-Term Credit Ratings (percentage)	'		'	'	'	'	0.88%	1.75%
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	'		'	'	0.08%	0.28%	'	'
Number Of Additional Periods The Revolving Termination Date On The Credit Facility Can Be Extended, Subject To Majority Bank Group Approval	'		2	'	'	'	'	'
Term Of Each Additional Period The Revolving Termination Date Can Be Extended, Subject To Majority Bank Group Approval (in years)	'		'1 year	'	'	'	'	'
[1]	Credit facility has been amended to expire in October 2019.

Borrowings_and_Other_Financing6

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Long-Term Borrowings and Other Financing Instruments (Details) (First Mortgage Bonds, Series Due May 15, 2044, USD $)	1 Months Ended
	31-May-14
First Mortgage Bonds | Series Due May 15, 2044	'
Debt Instrument [Line Items]	'
Face Amount	$300,000,000
Interest Rate, Stated Percentage	4.13%
Maturity Date	15-May-44

Fair_Value_of_Financial_Assets2

Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities (Details)	9 Months Ended
	Sep. 30, 2014
Minimum | Commingled Funds and International Equity Funds	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Notice period for investment redemption (in days)	'1 day
Minimum | Real Estate Funds	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Notice period for investment redemption (in days)	'45 days
Maximum | Commingled Funds and International Equity Funds	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Notice period for investment redemption (in days)	'90 days
Maximum | Real Estate Funds	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Notice period for investment redemption (in days)	'90 days

Fair_Value_of_Financial_Assets3

Fair Value of Financial Assets and Liabilities, Cost and Fair Value of Nuclear Decommissioning Fund (Details) (USD $)	9 Months Ended		12 Months Ended
	Sep. 30, 2014		Dec. 31, 2013
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Gross Unrealized Gain	$287,500,000		$240,300,000
Available-for-sale Securities, Gross Unrealized Loss	58,800,000		58,500,000
Investments [Abstract]	'		'
Miscellaneous investments	29,200,000		28,300,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Cash equivalents	14,972,000		33,281,000
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	1,460,778,000		1,445,197,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Commingled funds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	469,608,000		457,986,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | International equity funds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	78,812,000		78,812,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Private equity investments	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	74,222,000		52,143,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Real estate	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	45,075,000		45,564,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Government securities	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	34,379,000		34,304,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | U.S. corporate bonds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	80,196,000		80,275,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | International corporate bonds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	17,696,000		15,025,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Municipal bonds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	235,751,000		241,112,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Asset-backed Securities	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	9,226,000		'
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Mortgage-backed Securities	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	23,554,000		'
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Common stock	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Equity Securities	377,287,000		406,695,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Cash equivalents	14,972,000		33,281,000
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	1,689,441,000	[1]	1,627,026,000	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Commingled funds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	471,388,000		452,227,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | International equity funds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	85,856,000		81,671,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Private equity investments	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	97,004,000		62,696,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Real estate	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	63,973,000		57,368,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Government securities	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	29,726,000		27,628,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | U.S. corporate bonds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	79,248,000		83,538,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | International corporate bonds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	17,613,000		15,358,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Municipal bonds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	240,907,000		232,016,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Asset-backed Securities	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	9,347,000		'
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Mortgage-backed Securities	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	23,696,000		'
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Common stock	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Equity Securities	555,711,000		581,243,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Cash equivalents	14,972,000		33,281,000
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	570,683,000		614,524,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Commingled funds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | International equity funds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Private equity investments	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Real estate	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Government securities	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | U.S. corporate bonds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | International corporate bonds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Municipal bonds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Asset-backed Securities	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	0		'
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Mortgage-backed Securities	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	0		'
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Common stock	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Equity Securities	555,711,000		581,243,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Cash equivalents	0		0
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	957,781,000		892,438,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Commingled funds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	471,388,000		452,227,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | International equity funds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	85,856,000		81,671,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Private equity investments	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Real estate	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Government securities	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	29,726,000		27,628,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | U.S. corporate bonds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	79,248,000		83,538,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | International corporate bonds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	17,613,000		15,358,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Municipal bonds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	240,907,000		232,016,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Asset-backed Securities	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	9,347,000		'
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Mortgage-backed Securities	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	23,696,000		'
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Common stock	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Equity Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Cash equivalents	0		0
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	160,977,000		120,064,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Commingled funds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | International equity funds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Private equity investments	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	97,004,000		62,696,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Real estate	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities	63,973,000		57,368,000
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Government securities	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | U.S. corporate bonds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | International corporate bonds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Municipal bonds	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	0		0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Asset-backed Securities	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	0		'
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Mortgage-backed Securities	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Debt Securities	0		'
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Common stock	'		'
Available-for-sale Securities [Abstract]	'		'
Available-for-sale Securities, Equity Securities	$0		$0
[1]	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $29.2 million of miscellaneous investments.
[2]	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $28.3 million of miscellaneous investments.

Fair_Value_of_Financial_Assets4

Fair Value of Financial Assets and Liabilities, Changes in Level 3 Nuclear Decommissioning Fund (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward]	'	'	'	'
Balance at beginning of period	$146,781	$83,730	$120,064	$104,600
Purchases	12,655	18,078	27,464	33,450
Settlements	-5,876	0	-5,876	-9,022
Gains recognized as regulatory assets	7,417	2,022	19,325	7,078
Transfers out of Level 3	0	0	0	-32,276	[1]
Balance at end of period	160,977	103,830	160,977	103,830
Private equity investments	'	'	'	'
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward]	'	'	'	'
Balance at beginning of period	81,123	45,590	62,696	33,250
Purchases	11,125	6,790	22,078	15,344
Settlements	0	0	0	0
Gains recognized as regulatory assets	4,756	94	12,230	3,880
Transfers out of Level 3	0	0	0	0
Balance at end of period	97,004	52,474	97,004	52,474
Real estate	'	'	'	'
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward]	'	'	'	'
Balance at beginning of period	65,658	38,140	57,368	39,074
Purchases	1,530	11,288	5,386	18,106
Settlements	-5,876	0	-5,876	-9,022
Gains recognized as regulatory assets	2,661	1,928	7,095	3,198
Transfers out of Level 3	0	0	0	0
Balance at end of period	63,973	51,356	63,973	51,356
Asset-backed Securities	'	'	'	'
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward]	'	'	'	'
Balance at beginning of period	'	'	'	2,067
Purchases	'	'	'	0
Settlements	'	'	'	0
Gains recognized as regulatory assets	'	'	'	0
Transfers out of Level 3	'	'	'	-2,067	[1]
Balance at end of period	'	0	'	0
Mortgage-backed Securities	'	'	'	'
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward]	'	'	'	'
Balance at beginning of period	'	'	'	30,209
Purchases	'	'	'	0
Settlements	'	'	'	0
Gains recognized as regulatory assets	'	'	'	0
Transfers out of Level 3	'	'	'	-30,209	[1]
Balance at end of period	'	$0	'	$0
[1]	Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements.

Fair_Value_of_Financial_Assets5

Fair Value of Financial Assets and Liabilities, Final Contractual Maturity Dates of Debt Securities in Nuclear Decommissioning Fund (Details) (USD $)	Sep. 30, 2014
In Thousands, unless otherwise specified
Final Contractual Maturity [Abstract]	'
Due in 1 Year or Less	$1,110
Due in 1 to 5 Years	54,332
Due in 5 to 10 Years	121,622
Due after 10 Years	223,473
Total	400,537
Government securities	'
Final Contractual Maturity [Abstract]	'
Due in 1 Year or Less	0
Due in 1 to 5 Years	0
Due in 5 to 10 Years	0
Due after 10 Years	29,726
Total	29,726
U.S. corporate bonds	'
Final Contractual Maturity [Abstract]	'
Due in 1 Year or Less	303
Due in 1 to 5 Years	15,878
Due in 5 to 10 Years	62,985
Due after 10 Years	82
Total	79,248
International corporate bonds	'
Final Contractual Maturity [Abstract]	'
Due in 1 Year or Less	0
Due in 1 to 5 Years	4,266
Due in 5 to 10 Years	13,347
Due after 10 Years	0
Total	17,613
Municipal bonds	'
Final Contractual Maturity [Abstract]	'
Due in 1 Year or Less	807
Due in 1 to 5 Years	34,188
Due in 5 to 10 Years	41,744
Due after 10 Years	164,168
Total	240,907
Asset-backed Securities	'
Final Contractual Maturity [Abstract]	'
Due in 1 Year or Less	0
Due in 1 to 5 Years	0
Due in 5 to 10 Years	3,546
Due after 10 Years	5,801
Total	9,347
Mortgage-backed Securities	'
Final Contractual Maturity [Abstract]	'
Due in 1 Year or Less	0
Due in 1 to 5 Years	0
Due in 5 to 10 Years	0
Due after 10 Years	23,696
Total	$23,696

Fair_Value_of_Financial_Assets6

Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified	MWh		MWh
Interest Rate Swap	'		'
Interest Rate Derivatives [Abstract]	'		'
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months	-0.8		'
Electric Commodity (in megawatt hours)	'		'
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract]	'		'
Notional amount	64,032,000	[1],[2]	52,107,000	[1],[2]
Natural Gas Commodity (in million British thermal units)	'		'
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract]	'		'
Notional amount	5,702,000	[1],[2]	2,470,000	[1],[2]
Vehicle Fuel Commodity (in gallons)	'		'
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract]	'		'
Notional amount	182,000	[1],[2]	265,000	[1],[2]
[1]	Amounts are not reflective of net positions in the underlying commodities.
[2]	Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.

Fair_Value_of_Financial_Assets7

Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) (USD $)	3 Months Ended				9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]	'		'		'		'
Derivative instruments designated as fair value hedges	$0		$0		$0		$0
Recognized gains (losses) from fair value hedges or related hedged transactions	0		0		0		0
Cash Flow Hedges	'		'		'		'
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]	'		'		'		'
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss	-42,000		20,000		-32,000		-7,000
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	341,000		337,000		1,005,000		1,001,000
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		0		0
Pre-tax gains (losses) recognized during the period in income	0		0		0		0
Cash Flow Hedges | Interest Rate	'		'		'		'
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]	'		'		'		'
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss	0		0		0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	350,000	[1]	350,000	[1]	1,038,000	[1]	1,038,000	[1]
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		0		0
Pre-tax gains (losses) recognized during the period in income	0		0		0		0
Cash Flow Hedges | Vehicle Fuel And Other Commodity	'		'		'		'
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]	'		'		'		'
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss	-42,000		20,000		-32,000		-7,000
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	-9,000	[2]	-13,000	[2]	-33,000	[2]	-37,000	[2]
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		0		0
Pre-tax gains (losses) recognized during the period in income	0		0		0		0
Other Derivative Instruments	'		'		'		'
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]	'		'		'		'
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss	0		0		0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	-2,515,000		872,000		-6,555,000		61,267,000
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	5,457,000		9,823,000		-28,236,000		-38,816,000
Pre-tax gains (losses) recognized during the period in income	-1,656,000		7,094,000		1,329,000		9,371,000
Other Derivative Instruments | Commodity Trading	'		'		'		'
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]	'		'		'		'
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss	0		0		0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		0		0
Pre-tax gains (losses) recognized during the period in income	-1,656,000	[3]	7,094,000	[3]	1,266,000	[3]	9,371,000	[3]
Other Derivative Instruments | Electric Commodity	'		'		'		'
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]	'		'		'		'
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss	0		0		0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	-2,212,000		921,000		-13,660,000		61,314,000
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	5,457,000	[4]	9,823,000	[4]	-18,930,000	[4]	-38,816,000	[4]
Pre-tax gains (losses) recognized during the period in income	0		0		0		0
Other Derivative Instruments | Natural Gas Commodity	'		'		'		'
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]	'		'		'		'
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss	0		0		0		0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	-303,000		-49,000		7,105,000		-47,000
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		-9,306,000	[5]	0
Pre-tax gains (losses) recognized during the period in income	0		0		-580,000	[5]	0
Other Derivative Instruments | Other Commodity	'		'		'		'
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]	'		'		'		'
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss	'		'		0		'
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	'		'		0		'
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	'		'		0		'
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	'		'		0		'
Pre-tax gains (losses) recognized during the period in income	'		'		$643,000	[3]	'
[1]	Amounts are recorded to interest charges.
[2]	Amounts are recorded to O&M expenses.
[3]	Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.
[4]	Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.
[5]	Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

Fair_Value_of_Financial_Assets8

Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities, Counterparty Credit Risk (Details) (Credit Concentration Risk, USD $)	Sep. 30, 2014
In Millions, unless otherwise specified	Counterparty
Consideration of Credit Risk and Concentrations [Abstract]	'
Number of most significant counterparties for wholesale, trading and non trading commodity activities with credit exposure	10
Investment Grade Ratings from Standard Poors, Moodys, or Fitch Ratings	'
Consideration of Credit Risk and Concentrations [Abstract]	'
Number of most significant counterparties for wholesale, trading and non trading commodity activities with credit exposure	8
Wholesale, trading and non trading commodity credit exposure for the most significant counterparties	21.4
Percentage of wholesale, trading and non trading commodity credit exposure for the most significant counterparties	22.00%
No Investment Grade Ratings from External Credit Rating Agencies	'
Consideration of Credit Risk and Concentrations [Abstract]	'
Number of most significant counterparties for wholesale, trading and non trading commodity activities with credit exposure	2
Wholesale, trading and non trading commodity credit exposure for the most significant counterparties	6.4
Percentage of wholesale, trading and non trading commodity credit exposure for the most significant counterparties	6.00%

Fair_Value_of_Financial_Assets9

Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'	'
Derivative instruments in a gross liability position	$0	$0
Collateral posted related to adequate assurance clauses in derivative contracts	$0	$0

Recovered_Sheet1

Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Collateral, Obligation to Return Cash, Offset	$0		$0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	3,900,000		4,200,000
Other Current Assets	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	82,565,000		66,726,000
Other Noncurrent Assets	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	12,835,000		36,881,000
Other Current Liabilities	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	14,169,000		13,066,000
Other Noncurrent Liabilities	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	136,364,000		151,651,000
Fair Value Measured on a Recurring Basis | Other Current Assets	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	68,646,000		43,306,000
Fair Value Measured on a Recurring Basis | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	0		48,000
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	18,126,000		12,303,000
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	46,784,000		28,969,000
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	3,736,000		1,986,000
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	10,861,000		26,398,000
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	'		0
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	10,861,000		26,398,000
Fair Value Measured on a Recurring Basis | Other Current Liabilities	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	422,000		0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	0		'
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	422,000		0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	661,000		4,245,000
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	3,000		'
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	658,000		4,245,000
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Electric Commodity	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	'		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	0		'
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	0		'
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	22,650,000		19,888,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	2,000		48,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	18,912,000		17,854,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Electric Commodity	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	3,736,000		1,986,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	13,269,000		32,090,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	'		16,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	13,269,000		32,074,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	9,760,000		8,108,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	2,000		'
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	9,758,000		8,108,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	3,069,000		14,382,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	3,000		'
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	3,066,000		14,382,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	53,492,000		31,859,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	4,609,000		1,167,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Electric Commodity	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	48,883,000		30,692,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	0		3,395,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	'		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	0		3,395,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	2,099,000		3,527,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	0		'
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	0		1,804,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	2,099,000		1,723,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	0		'
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	76,142,000		51,747,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	2,000		48,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	23,521,000		19,021,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instruments | Electric Commodity	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	48,883,000		30,692,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	3,736,000		1,986,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	13,269,000		35,485,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	'		16,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	13,269,000		35,469,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	11,859,000		11,635,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	2,000		'
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	9,758,000		9,912,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Electric Commodity	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	2,099,000		1,723,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	3,069,000		14,382,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	3,000		'
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	3,066,000		14,382,000
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Assets	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	-7,496,000	[1]	-8,441,000	[2]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	-2,000	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Assets | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	-5,395,000	[1]	-6,718,000	[2]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Assets | Other Derivative Instruments | Electric Commodity	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	-2,099,000	[1]	-1,723,000	[2]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Noncurrent Assets	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	-2,408,000	[1]	-9,087,000	[2]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Noncurrent Assets | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	'		-16,000	[2]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	-2,408,000	[1]	-9,071,000	[2]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Liabilities	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	-11,437,000	[1]	-11,635,000	[2]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	-2,000	[1]	'
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Liabilities | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	-9,336,000	[1]	-9,912,000	[2]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Current Liabilities | Other Derivative Instruments | Electric Commodity	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	-2,099,000	[1]	-1,723,000	[2]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Noncurrent Liabilities	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	-2,408,000	[1]	-10,137,000	[2]
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	0	[1]	'
Fair Value Measured on a Recurring Basis | Counterparty Netting | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	-2,408,000	[1]	-10,137,000	[2]
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	13,919,000	[3]	23,420,000	[3]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	1,974,000	[3]	10,483,000	[3]
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	13,747,000	[3]	13,066,000	[3]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements	'		'
Derivatives, Fair Value [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	$135,703,000	[3]	$147,406,000	[3]
[1]	NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Sept. 30, 2014. At Sept. 30, 2014, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $3.9 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
[2]	NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2013. At Dec. 31, 2013, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $4.2 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
[3]	In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

Recovered_Sheet2

Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) (Commodity Contract, USD $)	3 Months Ended				9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Commodity Contract	'		'		'		'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]	'		'		'		'
Balance at beginning of period	$71,452,000		$47,218,000		$31,727,000		$16,649,000
Purchases	1,159,000		155,000		82,848,000		51,541,000
Settlements	-11,685,000		-9,342,000		-84,449,000		-30,294,000
Transfers out of Level 3	-1,093,000		0		-1,093,000		0
Gains recognized in earnings	1,480,000	[1]	4,008,000	[1]	8,917,000	[1]	3,729,000	[1]
Gains (losses) recognized as regulatory assets and liabilities	-9,920,000		-571,000		13,443,000		-157,000
Balance at end of period	51,393,000		41,468,000		51,393,000		41,468,000
Transfers into Level 3	$0		$0		$0		$0
[1]	These amounts relate to commodity derivatives held at the end of the period.

Recovered_Sheet3

Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Carrying Amount	'	'
Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Long-term debt, including current portion	$4,188,471	$3,888,732
Fair Value	'	'
Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Long-term debt, including current portion	$4,655,826	$4,099,745

Other_Expense_Income_Net_Detai

Other (Expense) Income, Net (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Other Income and Expenses [Abstract]	'	'	'	'
Interest income	$247	$389	$4,001	$4,041
Other nonoperating income	25	17	431	138
Insurance policy expense	-756	-1,553	-3,383	-4,176
Other (expense) income, net	($484)	($1,147)	$1,049	$3

Segment_Information_Details

Segment Information (Details) (USD $)	3 Months Ended				9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Segment Reporting Information [Line Items]	'		'		'		'
Operating revenues	$1,190,213		$1,217,476		$3,739,298		$3,495,556
Net income (loss)	134,469		155,106		318,099		334,772
Affiliate electric revenue	116,192		79,589		354,515		300,725
Regulated Electric	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Operating revenues	1,121,339		1,157,324		3,190,952		3,080,168
Net income (loss)	134,969		149,939		284,035		298,133
Regulated Natural Gas	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Operating revenues	62,482		53,865		528,891		397,000
Net income (loss)	-5,545		-6,448		21,555		17,286
All Other	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Operating revenues	6,819		6,618		20,794		19,416
Net income (loss)	5,045		11,615		12,509		19,353
Operating Segments	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Operating revenues	1,190,213	[1],[2]	1,217,476	[1],[2]	3,739,298	[3],[4]	3,495,556	[3],[4]
Operating Segments | Regulated Electric	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Operating revenues	1,121,055	[2]	1,157,134	[2]	3,190,252	[3]	3,079,679	[3]
Operating Segments | Regulated Natural Gas	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Operating revenues	62,339	[1]	53,724	[1]	528,252	[4]	396,461	[4]
Operating Segments | All Other	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Operating revenues	6,819		6,618		20,794		19,416
Intersegment Eliminations	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Operating revenues	-427		-331		-1,339		-1,028
Intersegment Eliminations | Regulated Electric	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Operating revenues	284		190		700		489
Intersegment Eliminations | Regulated Natural Gas	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Operating revenues	143		141		639		539
Intersegment Eliminations | All Other	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Operating revenues	$0		$0		$0		$0
[1]	Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended Sept. 30, 2014 and 2013.
[2]	Operating revenues include $116 million and $80 million of affiliate electric revenue for the three months ended Sept. 30, 2014 and 2013, respectively.
[3]	Operating revenues include $355 million and $301 million of affiliate electric revenue for the nine months ended Sept. 30, 2014 and 2013, respectively.
[4]	Operating revenues include an immaterial amount of affiliate gas revenue for the nine months ended Sept. 30, 2014 and 2013, respectively.

Benefit_Plans_and_Other_Postre2

Benefit Plans and Other Postretirement Benefits (Details) (USD $)	1 Months Ended	3 Months Ended		9 Months Ended
	Jan. 31, 2014	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Pension Benefits	'	'	'	'	'
Components of Net Periodic Benefit Cost [Abstract]	'	'	'	'	'
Service cost	'	$7,425,000	$8,292,000	$22,275,000	$24,875,000
Interest cost	'	11,827,000	10,934,000	35,481,000	32,801,000
Expected return on plan assets	'	-15,730,000	-15,788,000	-47,190,000	-47,364,000
Amortization of transition obligation	'	0	0	0	0
Amortization of prior service cost (credit)	'	234,000	514,000	702,000	1,542,000
Amortization of net loss	'	11,196,000	13,247,000	33,588,000	39,741,000
Net periodic benefit cost	'	14,952,000	17,199,000	44,856,000	51,595,000
Costs not recognized due to the effects of regulation	'	-7,312,000	-13,048,000	-22,383,000	-26,592,000
Net benefit cost recognized for financial reporting	'	7,640,000	4,151,000	22,473,000	25,003,000
Total contributions to the pension plans during the period	52,100,000	'	'	'	'
Postretirement Health Care Benefits	'	'	'	'	'
Components of Net Periodic Benefit Cost [Abstract]	'	'	'	'	'
Service cost	'	47,000	30,000	140,000	90,000
Interest cost	'	1,248,000	1,225,000	3,745,000	3,675,000
Expected return on plan assets	'	-75,000	-104,000	-226,000	-312,000
Amortization of transition obligation	'	0	8,000	0	24,000
Amortization of prior service cost (credit)	'	-759,000	-759,000	-2,277,000	-2,277,000
Amortization of net loss	'	854,000	1,318,000	2,562,000	3,954,000
Net periodic benefit cost	'	1,315,000	1,718,000	3,944,000	5,154,000
Costs not recognized due to the effects of regulation	'	0	0	0	0
Net benefit cost recognized for financial reporting	'	1,315,000	1,718,000	3,944,000	5,154,000
Xcel Energy Inc. | Pension Benefits	'	'	'	'	'
Components of Net Periodic Benefit Cost [Abstract]	'	'	'	'	'
Total contributions to the pension plans during the period	$130,000,000	'	'	'	'
Number of Xcel Energy's pension plans to which contributions were made	3	'	'	'	'

Other_Comprehensive_Income_Det

Other Comprehensive Income (Details) (USD $)	3 Months Ended				9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'		'		'		'
Accumulated other comprehensive income (loss) at beginning of period	($21,282)		($22,817)		($21,729)		($23,199)
Other comprehensive income (loss) before reclassifications	-23		126		20		75
(Gains) losses reclassified from net accumulated other comprehensive loss	192		214		596		647
Net current period other comprehensive income (loss)	169		340		616		722
Accumulated other comprehensive income (loss) at end of period	-21,113		-22,477		-21,113		-22,477
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Operating and maintenance expenses	296,707		294,831		902,808		854,533
Total, pre-tax	-210,182		-226,688		-490,606		-486,180
Tax benefit	75,713		71,582		172,507		151,408
Amounts Reclassified from Accumulated Other Comprehensive Loss	'		'		'		'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Total, net of tax	192		214		596		647
Gains and Losses on Cash Flow Hedges	'		'		'		'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'		'		'		'
Accumulated other comprehensive income (loss) at beginning of period	-20,210		-21,024		-20,609		-21,393
Other comprehensive income (loss) before reclassifications	-25		14		-19		-5
(Gains) losses reclassified from net accumulated other comprehensive loss	187		192		580		580
Net current period other comprehensive income (loss)	162		206		561		575
Accumulated other comprehensive income (loss) at end of period	-20,048		-20,818		-20,048		-20,818
Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss	'		'		'		'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Total, pre-tax	341		337		1,005		1,001
Tax benefit	-154		-145		-425		-421
Total, net of tax	187		192		580		580
Gains and Losses on Cash Flow Hedges | Interest Rate Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss	'		'		'		'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Interest charges	350	[1]	350	[1]	1,038	[1]	1,038	[1]
Gains and Losses on Cash Flow Hedges | Vehicle Fuel Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss	'		'		'		'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Operating and maintenance expenses	-9	[2]	-13	[2]	-33	[2]	-37	[2]
Unrealized Gains and Losses on Marketable Securities	'		'		'		'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'		'		'		'
Accumulated other comprehensive income (loss) at beginning of period	110		-131		73		-99
Other comprehensive income (loss) before reclassifications	2		112		39		80
(Gains) losses reclassified from net accumulated other comprehensive loss	0		0		0		0
Net current period other comprehensive income (loss)	2		112		39		80
Accumulated other comprehensive income (loss) at end of period	112		-19		112		-19
Defined Benefit Pension and Postretirement Items	'		'		'		'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'		'		'		'
Accumulated other comprehensive income (loss) at beginning of period	-1,182		-1,662		-1,193		-1,707
Other comprehensive income (loss) before reclassifications	0		0		0		0
(Gains) losses reclassified from net accumulated other comprehensive loss	5		22		16		67
Net current period other comprehensive income (loss)	5		22		16		67
Accumulated other comprehensive income (loss) at end of period	-1,177		-1,640		-1,177		-1,640
Defined Benefit Pension and Postretirement Items | Amounts Reclassified from Accumulated Other Comprehensive Loss	'		'		'		'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Amortization of net loss	59	[3]	85	[3]	175	[3]	255	[3]
Prior service credit	-49	[3]	-47	[3]	-146	[3]	-141	[3]
Transition obligation	'		'		0	[3]	1	[3]
Total, pre-tax	10		38		29		115
Tax benefit	-5		-16		-13		-48
Total, net of tax	$5		$22		$16		$67
[1]	Included in interest charges.
[2]	Included in O&M expenses.
[3]	Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for details regarding these benefit plans.