Northern States Power 10-Q 3 Aug 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Aug. 03, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	NORTHERN STATES POWER CO
Entity Central Index Key	1,123,852
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	2,015
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2015

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Operating revenues
Electric, non-affiliates	$ 882,042	$ 884,339	$ 1,763,321	$ 1,830,874
Electric, affiliates	117,830	116,518	242,705	238,323
Natural gas	75,239	116,381	354,706	465,913
Other	6,863	7,521	13,724	13,975
Total operating revenues	1,081,974	1,124,759	2,374,456	2,549,085
Operating expenses
Electric fuel and purchased power	384,479	395,130	783,199	853,213
Cost of natural gas sold and transported	37,419	74,427	238,608	337,308
Cost of sales — other	4,467	4,174	8,794	8,301
Operating and maintenance expenses	311,512	308,520	625,562	606,101
Conservation program expenses	14,877	30,291	32,089	66,908
Depreciation and amortization	116,245	101,906	234,320	201,091
Taxes (other than income taxes)	58,487	55,015	122,319	117,175
Loss on Monticello LCM/EPU project	0	0	124,226	0
Total operating expenses	927,486	969,463	2,169,117	2,190,097
Operating income	154,488	155,296	205,339	358,988
Other (expense) income, net	(276)	(471)	1,685	1,533
Allowance for funds used during construction — equity	5,684	5,995	11,614	11,259
Interest charges and financing costs
Interest charges — includes other financing costs of $1,637, $1,619, $3,246 and $3,212, respectively	49,094	49,089	100,856	96,541
Allowance for funds used during construction — debt	(2,840)	(2,730)	(5,754)	(5,185)
Total interest charges and financing costs	46,254	46,359	95,102	91,356
Income before income taxes	113,642	114,461	123,536	280,424
Income taxes	39,461	39,195	42,431	96,794
Net income	$ 74,181	$ 75,266	$ 81,105	$ 183,630

CONSOLIDATED STATEMENTS OF INC3

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Interest charges and financing costs
Other financing costs	$ 1,637	$ 1,619	$ 3,246	$ 3,212

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Comprehensive income:
Net income	$ 74,181	$ 75,266	$ 81,105	$ 183,630
Pension and retiree medical benefits:
Amortization of (gains) losses included in net periodic benefit cost, net of tax of $(2), $4, $(10) and $8, respectively	(6)	6	(12)	11
Derivative instruments:
Net fair value increase, net of tax of $6, $7, $3, and $4, respectively	9	10	2	6
Reclassification of losses to net income, net of tax of $148, $138, $293 and $271, respectively	214	200	423	393
Total derivative instruments, net of tax	223	210	425	399
Marketable securities:
Net fair value increase, net of tax of $1, $0, $2, and $26, respectively	1	0	2	37
Other comprehensive income	218	216	415	447
Comprehensive income	$ 74,399	$ 75,482	$ 81,520	$ 184,077

CONSOLIDATED STATEMENTS OF COM5

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, tax	$ (2)	$ 4	$ (10)	$ 8
Derivative instruments:
Net fair value (decrease) increase, tax	6	7	3	4
Reclassification of losses to net income, tax	148	138	293	271
Marketable securities:
Net fair value increase, tax	$ 1	$ 0	$ 2	$ 26

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Operating activities
Net income	$ 81,105	$ 183,630
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	237,103	203,803
Nuclear fuel amortization	49,454	60,466
Deferred income taxes	62,445	75,185
Amortization of investment tax credits	(866)	(910)
Allowance for equity funds used during construction	(11,614)	(11,259)
Loss on Monticello LCM/EPU project	124,226	0
Net realized and unrealized hedging and derivative transactions	6,442	(1,132)
Changes in operating assets and liabilities:
Accounts receivable	78,369	(42,406)
Accrued unbilled revenues	40,527	46,614
Inventories	5,774	39,086
Other current assets	37,783	(7,177)
Accounts payable	(35,275)	(88,173)
Net regulatory assets and liabilities	15,320	67,529
Other current liabilities	(2,478)	(33,407)
Pension and other employee benefit obligations	(29,920)	(47,456)
Change in other noncurrent assets	(33)	33,355
Change in other noncurrent liabilities	(17,436)	(21,633)
Net cash provided by operating activities	640,926	456,115
Investing activities
Utility capital/construction expenditures	(610,731)	(590,432)
Allowance for equity funds used during construction	11,614	11,259
Proceeds from insurance recoveries	27,237	6,000
Purchases of investments in external decommissioning fund	(640,100)	(404,780)
Proceeds from the sale of investments in external decommissioning fund	636,669	401,488
Investments in utility money pool arrangement	(39,900)	(236,000)
Repayments from utility money pool arrangement	39,900	236,000
Other, net	(1,151)	(1,267)
Net cash used in investing activities	(576,462)	(577,732)
Financing activities
Repayments of short-term borrowings, net	(25,000)	(104,000)
Borrowings under utility money pool arrangement	144,500	313,000
Repayments under utility money pool arrangement	(144,500)	(347,000)
(Repayments of) proceeds from Issuance of Long-term Debt	(46)	295,534
Capital contributions from parent	125,935	95,000
Dividends paid to parent	(133,671)	(118,492)
Net cash (used in) provided by financing activities	(32,782)	134,042
Net change in cash and cash equivalents	31,682	12,425
Cash and cash equivalents at beginning of period	40,597	42,920
Cash and cash equivalents at end of period	72,279	55,345
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(93,318)	(87,595)
Cash received (paid) for income taxes, net	59,175	(8,355)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 85,735	$ 143,407

CONSOLIDATED BALANCE SHEETS (UN

CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 72,279	$ 40,597
Accounts receivable, net	293,761	367,696
Accounts receivable from affiliates	19,633	24,067
Accrued unbilled revenues	211,060	251,587
Inventories	284,594	290,287
Regulatory assets	201,523	235,487
Derivative instruments	42,498	60,164
Deferred income taxes	119,010	76,016
Prepayments and other	79,500	142,443
Total current assets	1,323,858	1,488,344
Property, plant and equipment, net	11,801,899	11,661,620
Other assets
Nuclear decommissioning fund and other investments	1,784,676	1,735,316
Regulatory assets	1,062,407	1,051,834
Derivative instruments	19,769	15,434
Other	33,441	34,768
Total other assets	2,900,293	2,837,352
Total assets	16,026,050	15,987,316
Current liabilities
Current portion of long-term debt	250,011	250,013
Short-term debt	117,000	142,000
Accounts payable	325,807	470,507
Accounts payable to affiliates	59,872	50,545
Regulatory liabilities	105,796	171,608
Taxes accrued	164,237	198,509
Accrued interest	60,878	61,339
Dividends payable to parent	65,087	77,802
Derivative instruments	17,267	12,294
Other	250,883	217,215
Total current liabilities	1,416,838	1,651,832
Deferred credits and other liabilities
Deferred income taxes	2,557,126	2,429,143
Deferred investment tax credits	26,701	27,567
Regulatory liabilities	471,420	451,783
Asset retirement obligations	2,251,668	2,186,174
Derivative instruments	127,202	135,036
Pension and employee benefit obligations	310,670	340,774
Other	135,681	123,165
Total deferred credits and other liabilities	$ 5,880,468	$ 5,693,642
Commitments and contingencies
Capitalization
Long-term debt	$ 3,939,072	$ 3,938,669
Common stock — authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares outstanding at June 30, 2015 and Dec. 31, 2014, respectively	10	10
Additional paid in capital	3,087,589	2,961,654
Retained earnings	1,722,472	1,762,323
Accumulated other comprehensive loss	(20,399)	(20,814)
Total common stockholder’s equity	4,789,672	4,703,173
Total liabilities and equity	$ 16,026,050	$ 15,987,316

CONSOLIDATED BALANCE SHEETS (U8

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares	Jun. 30, 2015	Dec. 31, 2014
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

Management's Opinion

Management's Opinion	6 Months Ended
	Jun. 30, 2015
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 June 30, 2015 and Dec. 31, 2014 ; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 2015 and 2014 ; and its cash flows for the six months ended June 30, 2015 and 2014 . All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 2015 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, 2014 balance sheet information has been derived from the audited 2014 consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2014 . 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, 2014 , filed with the SEC on Feb. 20, 2015. 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 Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2015
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, 2014 , appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

Accounting Pronouncements

Accounting Pronouncements	6 Months Ended
	Jun. 30, 2015
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 (FASB) 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. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. As a result of the FASB’s deferral of the standard’s required implementation date in July 2015, the guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. NSP-Minnesota is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements. Consolidation — In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02) , which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15. 2015, and early adoption is permitted. NSP-Minnesota is currently evaluating the impact of adopting ASU 2015-02 on its consolidated financial statements. Presentation of Debt Issuance Costs — In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03) , which amends existing guidance to require the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of an asset. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the prescribed reclassification of assets to an offset of debt on the consolidated balance sheets, NSP-Minnesota does not expect the implementation of ASU 2015-03 to have a material impact on its consolidated financial statements. Fair Value Measurement — In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (Accounting Standards Update (ASU) No. 2015-07), which removes the requirement to categorize within the fair value hierarchy the fair values for investments measured using a net asset value methodology. This guidance will be effective on a retrospective basis for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the reduced disclosure requirements, NSP-Minnesota does not expect the implementation of ASU 2015-07 to have a material impact on its consolidated financial statements.

Selected Balance Sheet Data

Selected Balance Sheet Data	6 Months Ended
	Jun. 30, 2015
Balance Sheet Related Disclosures [Abstract]
Selected Balance Sheet Data	Selected Balance Sheet Data (Thousands of Dollars) June 30, 2015 Dec. 31, 2014 Accounts receivable, net Accounts receivable $ 312,702 $ 390,633 Less allowance for bad debts (18,941 ) (22,937 ) $ 293,761 $ 367,696 (Thousands of Dollars) June 30, 2015 Dec. 31, 2014 Inventories Materials and supplies $ 166,383 $ 157,376 Fuel 99,402 77,139 Natural gas 18,809 55,772 $ 284,594 $ 290,287 (Thousands of Dollars) June 30, 2015 Dec. 31, 2014 Property, plant and equipment, net Electric plant $ 15,175,091 $ 14,831,286 Natural gas plant 1,192,119 1,177,021 Common and other property 575,241 568,287 Construction work in progress 641,152 706,979 Total property, plant and equipment 17,583,603 17,283,573 Less accumulated depreciation (6,180,843 ) (6,012,145 ) Nuclear fuel 2,405,823 2,347,422 Less accumulated amortization (2,006,684 ) (1,957,230 ) $ 11,801,899 $ 11,661,620

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Except to the extent noted below, Note 6 to the consolidated financial statements included in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2014 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference. 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 2009 federal income tax return expires in March 2016. 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 June 30, 2015 , the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $12 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014. As of June 30, 2015, the IRS has begun the appeals process; however, 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 June 30, 2015 , 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) June 30, 2015 Dec. 31, 2014 Unrecognized tax benefit — Permanent tax positions $ 12.4 $ 12.2 Unrecognized tax benefit — Temporary tax positions 21.5 18.2 Total unrecognized tax benefit $ 33.9 $ 30.4 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) June 30, 2015 Dec. 31, 2014 NOL and tax credit carryforwards $ (12.6 ) $ (10.8 ) It is reasonably possible that NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS appeals process progresses and state audits resume. As the IRS appeals process 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 June 30, 2015 and Dec. 31, 2014 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2015 or Dec. 31, 2014 .

Rate Matters

Rate Matters	6 Months Ended
	Jun. 30, 2015
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, 2014 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference. Pending and Recently Concluded 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 was 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 included a proposed rate moderation plan for 2014 and 2015. In December 2013, the MPUC approved interim rates of $127 million , effective Jan. 3, 2014, subject to refund. In 2014, NSP-Minnesota revised its requested rate increase to $115.3 million for 2014 and to $106.0 million for 2015, for a total combined unadjusted increase of $221.3 million . In May 2015, the MPUC ordered a 2014 rate increase and a 2015 step increase. The total increase was estimated to be $166 million , or 5.9 percent , based on a 9.72 percent ROE and 52.50 percent equity ratio. The MPUC also approved a three -year, decoupling pilot with a 3 percent cap on base revenue for the residential and small commercial and industrial classes, based on actual sales, effective Jan. 1, 2016. The decoupling mechanism would eliminate the impact of changes in electric sales due to conservation and weather variability for these classes. In July 2015, the MPUC deliberated on requests for reconsideration of its order. The MPUC determined the Monticello Extended Power Uprate (EPU) project is not used-and-useful until final approval related to the full EPU uprate condition is received from the Nuclear Regulatory Commission (NRC). NSP-Minnesota expects that $13.8 million will be excluded from final rates, as approval from the NRC had not been received as of June 30, 2015. Monticello achieved the full EPU uprate level of 671 megawatts (MW) in June 2015 and received final NRC compliance approval in July 2015, thereby satisfying the used-and-useful conditions established by the MPUC. The MPUC also approved 2015 interim rates effective March 3, 2015 and stated that the 2014 interim rate refund obligation be netted against the 2015 interim rate revenue under-collections. The MPUC’s decision resulted in an estimated 2015 annual rate increase of $149.4 million or 5.3 percent . NSP-Minnesota anticipates reducing the 2014 refund obligation by approximately $6 million for the change in the interest rate applied to interim refunds and other items. The following tables outline NSP-Minnesota’s filed request and the impact of the MPUC’s decisions made in May and July: 2014 Rate Request (Millions of Dollars) NSP-Minnesota MPUC May Decision NSP-Minnesota’s filed rate request $ 192.7 $ 192.7 Sales forecast (with true-up to 12 months of actual weather-normalized sales) (38.5 ) (37.5 ) ROE — (31.9 ) Monticello EPU cost recovery (12.2 ) (37.6 ) Property taxes (with true-up to actual 2014 accruals) (13.2 ) (13.2 ) Prairie Island EPU cost recovery (5.1 ) (5.0 ) Health care, pension and other benefits (1.9 ) (3.1 ) Other, net (6.5 ) (5.5 ) Total 2014 $ 115.3 $ 58.9 2015 Rate Request (Millions of Dollars) NSP-Minnesota MPUC May Decision NSP-Minnesota’s filed rate request $ 98.5 $ 98.5 Monticello EPU cost recovery 11.7 35.4 Depreciation / Retirements — (0.5 ) Property taxes (3.3 ) (3.3 ) Production tax credits to be included in base rates (11.1 ) (11.1 ) U.S. Department of Energy (DOE) settlement proceeds 10.1 10.1 Emission chemicals (1.6 ) (1.6 ) Other, net 1.7 (2.3 ) Total 2015 step increase - prior to Monticello Life Cycle Management (LCM)/EPU cost disallowance $ 106.0 $ 125.2 Total for 2014 and 2015 step increase - prior to Monticello LCM/EPU cost disallowance $ 221.3 $ 184.1 Monticello LCM/EPU cost disallowance — (18.0 ) Total for 2014 and 2015 step increase - including Monticello LCM/EPU cost disallowance $ 221.3 $ 166.1 (Millions of Dollars) MPUC July Decision 2015 annual rate increase - based on MPUC May order $ 166.1 Reconsideration/clarification adjustments: 2015 Monticello EPU used-and-useful adjustment (13.8 ) 2014 property tax final true-up (3.1 ) Other, net 0.2 Total 2015 annual rate increase $ 149.4 Impact of interim rate effective March 3, 2015 (3.6 ) Estimated 2015 revenue impact $ 145.8 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 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). In 2008, project expenditures were initially estimated 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. In March 2015, the MPUC voted to allow for full recovery, including a return, on approximately $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. Further, the MPUC determined that only 50 percent of the investment was considered used-and-useful for 2014. As a result of these determinations and assuming the other state commissions within the NSP System jurisdictions adopt the MPUC’s decisions, Xcel Energy recorded an estimated pre-tax loss of $129 million in the first quarter of 2015. The remaining book value of the Monticello project represents the present value of the estimated future cash flows allowed for by the MPUC. 2015 Transmission Cost Recovery (TCR) Rate Filing — In October 2014, NSP-Minnesota submitted its 2015 TCR filing with the MPUC, requesting recovery of $65.8 million of 2015 transmission investment costs not included in electric base rates. The request for 2015 was reduced to approximately $63.8 million , which was approved by the MPUC in May 2015, subject to future adjustments replacing forecasted amounts with actual investment costs. The MPUC also set rates so that NSP-Minnesota will recover its remaining 2015 and forecasted 2016 revenue requirements through the end of 2016. New rates were implemented in July 2015, subject to true-up. Recently Concluded 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 electric rates by $15.6 million annually, or 8.0 percent , effective Jan. 1, 2015. Interim rates of $15.6 million , subject to refund, went into effect in January 2015. In June 2015, the SDPUC approved a settlement agreement allowing a base rate increase of approximately $6.9 million , or 3.6 percent , and providing revisions to the existing Infrastructure rider, which will recover additional net revenue of $0.9 million . Combined, the overall revenue increase in base rates and the Infrastructure rider for 2015 is approximately $7.8 million , or 4.0 percent . New rates began in July 2015. In addition, there is a moratorium on base rate increases until Jan. 1, 2018. The settlement also includes an earnings test with a sharing mechanism. If South Dakota’s weather normalized earnings exceed a certain level, NSP-Minnesota will refund 50 percent of the excess earnings to customers. Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC) Midcontinent Independent System Operator, Inc. (MISO) ROE Complaint/ROE Adder — In November 2013, a group of customers filed a complaint at the FERC against MISO transmission owners (TOs), including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE in 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 June 2014, the FERC issued an order adopting a new ROE methodology, which requires electric utilities to use a two -step discounted cash flow analysis that incorporates both short-term and long-term growth projections to estimate the cost of equity. The FERC set the ROE complaint against the MISO TOs for settlement and hearing procedures. The FERC directed parties to apply the new ROE methodology, but denied the complaints related to equity capital structures and ROE adders. The FERC established a Nov. 12, 2013 refund effective date. The settlement procedures were unsuccessful. In January 2015, the ROE complaint was set for full hearing procedures. The complainants and intervenors filed testimony recommending an ROE between 8.67 percent and 9.54 percent . The FERC staff recommended an ROE of 8.68 percent . The MISO TOs recommended an ROE not less than 10.8 percent . A hearing is scheduled for August 2015, with an administrative law judge (ALJ) initial decision to be issued by November 2015 and a FERC order issued no earlier than 2016. In November 2014, certain MISO TOs filed a request for FERC approval of a 50 basis point RTO membership ROE adder, with collection deferred until resolution of the ROE complaint. In January 2015, the FERC approved the ROE adder, subject to the outcome of the ROE complaint. The total ROE, including the RTO membership adder, may not exceed the top of the discounted cash flow range under the new ROE methodology. In February 2015, an intervenor in the November 2013 ROE complaint filed a second complaint proposing to reduce the MISO region ROE to 8.67 percent , prior to any 50 basis point RTO adder. In June 2015, the FERC set the second ROE complaint for a hearing process, establishing a Feb. 12, 2015 refund effective date. An ALJ initial decision is expected in June 2016 with a FERC decision in late 2016 or in 2017. The FERC decision would continue the ROE refund obligation initiated under the November 2013 complaint through May 2016. On July 20, 2015, the MISO TOs sought rehearing of the FERC decision to allow back-to-back complaints involving the same issue with consecutive refund periods, arguing this ruling is contrary to the governing statute. FERC action on the rehearing request is pending. NSP-Minnesota recorded a current liability representing the current best estimate of a refund obligation associated with the new ROE as of June 30, 2015. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $7 million and $9 million annually for the NSP System.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Except to the extent noted below and in Note 5, 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, 2014 appropriately represent, in all material respects, the current status of commitments and contingent liabilities, 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 June 30, 2015 and Dec. 31, 2014 , 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) June 30, 2015 Dec. 31, 2014 Guarantees issued and outstanding $ 4.8 $ 4.8
Environmental Loss Contingency Disclosure [Text Block]	Environmental Contingencies Fargo, N.D. Manufactured Gas Plant (MGP) Site — In May 2015, in connection with a city water main replacement and street improvement project in Fargo, N.D., underground pipes, tars, and impacted soils, which may be related to a former MGP site operated by NSP-Minnesota or a prior company, were discovered. After initial reports and discussions with the City of Fargo and the North Dakota Department of Health, NSP-Minnesota removed the impacted soils and other materials from the project area. At this time, NSP-Minnesota’s investigation of the site is considered preliminary as information is still being gathered. As of June 30, 2015, NSP-Minnesota recorded a liability of $2.1 million related to further investigation and additional planned activities. Uncertainties include the nature and cost of the additional remediation efforts that may be necessary, the ability to recover costs from insurance carriers and the potential for contributions from entities that may be identified as potentially responsible parties. Therefore, the total cost of remediation, NSP-Minnesota’s potential liability and amounts allocable to the North Dakota and Minnesota jurisdictions related to the site cannot currently be reasonably estimated. In July 2015, NSP-Minnesota filed a request with the North Dakota Public Service Commission (NDPSC) for approval to initially defer the portion of investigation and response costs allocable to the North Dakota jurisdiction. Environmental Requirements Water Federal Clean Water Act (CWA) Waters of the United States Rule — In June 2015, the Environmental Protection Agency (EPA) and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The expansion of the term “Waters of the U.S.” will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. The rule will go into effect beginning in August 2015. NSP-Minnesota does not anticipate the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. Air Cross-State Air Pollution Rule (CSAPR) — CSAPR addresses long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO 2 ) and nitrous oxide (NOx) from utilities in the eastern half of the United States, including Minnesota, using an emissions trading program. In August 2012, the United States District Court of Appeals for the District of Columbia Circuit (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 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 (CAA) 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 were considered on remand. In July 2015, the D.C. Circuit issued an opinion which found the reduction budgets exceed what is necessary for Texas to reduce its impact on downwind states that do not meet ambient air quality standards. The D.C. Circuit remanded the matter to the EPA to reconsider the emission budgets. While the EPA reconsiders emission budgets, the D.C. Circuit left CSAPR in effect. In October 2014, the D.C. Circuit granted the EPA’s request to begin to implement CSAPR by imposing its 2012 compliance obligations starting in January 2015. While the litigation continues, the EPA is administering the CSAPR in 2015. NSP-Minnesota can operate within its CSAPR emission allowance allocations. CSAPR compliance in 2015 is not having a material impact on the results of operations, financial position or cash flows. Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. In 2014, the U.S. Supreme Court decided to review the D.C. Circuit’s decision that upheld the MATS standard. By April 2015, the MATS compliance deadline, NSP-Minnesota had met the EGU MATS rule through a combination of emission control projects and controls required by other programs preceding MATS, such as regional haze and state mercury regulations. NSP-Minnesota also retired two coal units at the Black Dog plant. On June 29, 2015, the U.S. Supreme Court found that the EPA acted unreasonably by not considering the cost to regulate mercury and other hazardous air pollutants. The D.C. Circuit, on remand, will decide whether to leave MATS in effect while the EPA considers such costs in making a new determination. NSP-Minnesota believes EGU MATS costs will be recoverable through regulatory mechanisms and does not anticipate a material impact on the results of operations, financial position or cash flows. Regional Haze Rules — The regional haze program is designed to address widespread 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 SO 2 , 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 SO 2 . The MPCA concluded selective catalytic reductions (SCRs) should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs. The combustion controls were installed first and the scrubber upgrades were completed in December 2014, at a cost of $46.9 million . NSP-Minnesota anticipates these costs will be fully recoverable in rates. 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 EGUs 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 Minnesota 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. 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 certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota’s Sherco Units 1 and 2. The EPA is required to determine whether there is RAVI-type impairment in these parks and identify the potential source of the impairment. 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 (Minnesota District Court) 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 May 2015, NSP-Minnesota, the EPA and the six environmental advocacy organizations filed a settlement agreement in the Minnesota District Court. The agreement anticipates a federal rulemaking that would impose stricter SO 2 emission limits on Sherco Units 1, 2 and 3, without making a RAVI attribution finding or a RAVI BART determination. The emission limits for Units 1 and 2 reflect the success of a recently completed control project. The Unit 3 emission limits will be met through changes in the operation of the existing scrubber. The Minnesota District Court issued an order staying the litigation for the time needed to complete the actions required by the settlement agreement. The plaintiffs agreed to withdraw their complaint with prejudice when those actions are completed. Plaintiffs also agreed not to request a RAVI certification for Sherco Units 1, 2 and/or 3 in the future. As required by the CAA, the EPA published notice of the proposed settlement in the Federal Register. The EPA reviewed the public comments in July 2015 and notified the Minnesota District Court that the settlement agreement is final. The EPA has seven months to recommend and adopt a rule which will set the agreed-upon SO 2 emissions. NSP-Minnesota does not anticipate the costs of compliance with the proposed settlement will have a material impact on the results of operations, financial position or cash flows. Implementation of the National Ambient Air Quality Standard (NAAQS) for SO 2 — The EPA adopted a more stringent NAAQS for SO 2 in 2010. In 2013, the EPA designated areas as not attaining the revised NAAQS, which did not include any areas where NSP-Minnesota operates power plants. However, many other areas of the country were unable to be classified by the EPA due to a lack of air monitors. Following a lawsuit alleging that the EPA had not completed its area designations in the time required by the CAA and under a consent decree the EPA is requiring states to evaluate areas in three phases. If an area is designated nonattainment, the respective states will need to evaluate all SO 2 sources in the area. The state would then submit an implementation plan for the respective areas which would be due in 18 months, designed to achieve the NAAQS within five years. It is anticipated the areas near NSP-Minnesota’s power plants would be evaluated by December 2017. NSP-Minnesota cannot evaluate the impacts of this ruling until the designation of nonattainment areas is made and any required state plans are developed.
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 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 contracts 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 spent fuel storage after 2016; such costs could be the subject of future litigation. In December 2014, NSP-Minnesota received a settlement payment of $32.8 million . NSP-Minnesota has received a total of $214.7 million of settlement proceeds as of June 30, 2015 . On May 15, 2015, NSP-Minnesota submitted a claim for an additional $13.4 million . 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	6 Months Ended
	Jun. 30, 2015
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 June 30, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 250 $ 250 Amount outstanding at period end — — Average amount outstanding 6 12 Maximum amount outstanding 50 150 Weighted average interest rate, computed on a daily basis 0.54 % 0.21 % Weighted average interest rate at period end N/A N/A 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 June 30, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 500 $ 500 Amount outstanding at period end 117 142 Average amount outstanding 95 111 Maximum amount outstanding 208 397 Weighted average interest rate, computed on a daily basis 0.41 % 0.26 % Weighted average interest rate at period end 0.42 0.53 Letters of Credit — NSP-Minnesota uses letters of credit, generally with terms of one year , to provide financial guarantees for certain operating obligations. At June 30, 2015 and Dec. 31, 2014 , there were $ 26.5 million and $24.1 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 June 30, 2015 , NSP-Minnesota had the following committed credit facility available (in millions of dollars): Credit Facility (a) Drawn (b) Available $ 500 $ 144 $ 356 (a) This credit facility expires in October 2019. (b) Includes outstanding commercial paper and 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 June 30, 2015 and Dec. 31, 2014 .

Fair Value of Financial Assets

Fair Value of Financial Assets and Liabilities	6 Months Ended
	Jun. 30, 2015
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, Electric Reliability Council of Texas, Southwest Power Pool, Inc. and New York Independent System Operator, generally referred to as financial transmission rights (FTR). 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 Prairie Island (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 $335.3 million and $312.1 million at June 30, 2015 and Dec. 31, 2014 , respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $31.4 million and $74.1 million at June 30, 2015 and Dec. 31, 2014 , 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 June 30, 2015 and Dec. 31, 2014 : June 30, 2015 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Total Nuclear decommissioning fund (a) Cash equivalents $ 12,446 $ 12,446 $ — $ — $ 12,446 Commingled funds 451,398 — 499,782 — 499,782 International equity funds 123,123 — 121,502 — 121,502 Private equity investments 95,067 — — 133,993 133,993 Real estate 49,369 — — 70,834 70,834 Debt securities: Government securities 24,408 — 22,183 — 22,183 U.S. corporate bonds 69,194 — 66,096 — 66,096 International corporate bonds 16,506 — 16,294 — 16,294 Municipal bonds 209,103 — 210,898 — 210,898 Asset-backed securities 2,831 — 2,851 — 2,851 Mortgage-backed securities 12,039 — 12,219 — 12,219 Equity securities: Common stock 382,755 583,031 — — 583,031 Total $ 1,448,239 $ 595,477 $ 951,825 $ 204,827 $ 1,752,129 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $32.5 million of miscellaneous investments. Dec. 31, 2014 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Total Nuclear decommissioning fund (a) Cash equivalents $ 24,184 $ 24,184 $ — $ — $ 24,184 Commingled funds 470,013 — 465,615 — 465,615 International equity funds 80,454 — 78,721 — 78,721 Private equity investments 73,936 — — 101,237 101,237 Real estate 43,859 — — 64,249 64,249 Debt securities: Government securities 30,674 — 28,808 — 28,808 U.S. corporate bonds 81,463 — 77,562 — 77,562 International corporate bonds 16,950 — 16,341 — 16,341 Municipal bonds 242,282 — 249,201 — 249,201 Asset-backed securities 9,131 — 9,250 — 9,250 Mortgage-backed securities 23,225 — 23,895 — 23,895 Equity securities: Common stock 369,751 564,858 — — 564,858 Total $ 1,465,922 $ 589,042 $ 949,393 $ 165,486 $ 1,703,921 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $31.4 million of miscellaneous investments. The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three and six months ended June 30, 2015 and 2014 : (Thousands of Dollars) April 1, 2015 Purchases Settlements Gains Assets (a) June 30, 2015 Private equity investments $ 113,619 $ 8,749 $ — $ 11,625 $ 133,993 Real estate 67,774 4,271 (1,241 ) 30 70,834 Total $ 181,393 $ 13,020 $ (1,241 ) $ 11,655 $ 204,827 (Thousands of Dollars) April 1, 2014 Purchases Settlements Gains (a) June 30, 2014 Private equity investments $ 73,801 $ 2,184 $ — $ 5,138 $ 81,123 Real estate 62,954 197 — 2,507 65,658 Total $ 136,755 $ 2,381 $ — $ 7,645 $ 146,781 (Thousands of Dollars) Jan. 1, 2015 Purchases Settlements Gains Assets (a) June 30, 2015 Private equity investments $ 101,237 $ 21,131 $ — $ 11,625 $ 133,993 Real estate 64,249 8,132 (2,622 ) 1,075 70,834 Total $ 165,486 $ 29,263 $ (2,622 ) $ 12,700 $ 204,827 (Thousands of Dollars) Jan. 1, 2014 Purchases Settlements Gains Assets (a) June 30, 2014 Private equity investments $ 62,696 $ 10,953 $ — $ 7,474 $ 81,123 Real estate 57,368 3,856 — 4,434 65,658 Total $ 120,064 $ 14,809 $ — $ 11,908 $ 146,781 (a) Gains are deferred as a component of the regulatory assets for nuclear decommissioning. The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at June 30, 2015 : Final Contractual Maturity (Thousands of Dollars) Due in 1 Year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total Government securities $ — $ — $ — $ 22,183 $ 22,183 U.S. corporate bonds — 14,684 54,005 (2,593 ) 66,096 International corporate bonds — 3,951 11,325 1,018 16,294 Municipal bonds 361 32,427 41,313 136,797 210,898 Asset-backed securities — — 2,851 — 2,851 Mortgage-backed securities — — — 12,219 12,219 Debt securities $ 361 $ 51,062 $ 109,494 $ 169,624 $ 330,541 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 June 30, 2015 , 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 derivatives. At June 30, 2015 , 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 six months ended June 30, 2015 and 2014. At June 30, 2015 , net losses related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of net losses 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 June 30, 2015 and Dec. 31, 2014 : (Amounts in Thousands) (a)(b) June 30, 2015 Dec. 31, 2014 Megawatt hours of electricity 83,839 49,431 Million British thermal units of natural gas 942 173 Gallons of vehicle fuel 116 155 (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 six months ended June 30, 2015 and 2014 on accumulated other comprehensive loss, regulatory assets and liabilities and income: Three Months Ended June 30, 2015 Pre-Tax Fair Value Pre-Tax (Gains) Losses Pre-Tax Gains (Thousands of Dollars) Accumulated Regulatory Accumulated Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 346 (a) $ — $ — Vehicle fuel and other commodity 15 — 16 (b) — — Total $ 15 $ — $ 362 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 4,210 (c) Electric commodity — (3,517 ) — (6,327 ) (d) — Natural gas commodity — 56 — — — Total $ — $ (3,461 ) $ — $ (6,327 ) $ 4,210 Six Months Ended June 30, 2015 Pre-Tax Fair Value Pre-Tax (Gains) Losses Pre-Tax Gains (Thousands of Dollars) Accumulated Regulatory Accumulated Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 686 (a) $ — $ — Vehicle fuel and other commodity 5 — 30 (b) — — Total $ 5 $ — $ 716 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 7,902 (c) Electric commodity — (12,223 ) — (11,520 ) (d) — Natural gas commodity — 18 — (2,751 ) (e) 3,008 (e) Total $ — $ (12,205 ) $ — $ (14,271 ) $ 10,910 Three Months Ended June 30, 2014 Pre-Tax Fair Value Pre-Tax (Gains) Losses Pre-Tax Gains (Thousands of Dollars) Accumulated Regulatory Accumulated Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 346 (a) $ — $ — Vehicle fuel and other commodity 17 — (8 ) (b) — — Total $ 17 $ — $ 338 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 5,175 (c) Electric commodity — (16,347 ) — (6,461 ) (d) — Natural gas commodity — (493 ) — — — Other commodity — — — — 643 (c) Total $ — $ (16,840 ) $ — $ (6,461 ) $ 5,818 Six Months Ended June 30, 2014 Pre-Tax Fair Value Pre-Tax (Gains) Losses Pre-Tax Gains (Losses) (Thousands of Dollars) Accumulated Regulatory Accumulated Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 688 (a) $ — $ — Vehicle fuel and other commodity 10 — (24 ) (b) — — Total $ 10 $ — $ 664 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 2,922 (c) Electric commodity — (11,448 ) — (24,387 ) (d) — Natural gas commodity — 7,408 — (9,306 ) (e) (580 ) (e) Other commodity — — — — 643 (c) Total $ — $ (4,040 ) $ — $ (33,693 ) $ 2,985 (a) Amounts are recorded to interest charges. (b) Amounts are recorded to operating and maintenance (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 six months ended June 30, 2015 and 2014 . 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 June 30, 2015 , five of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $24.3 million or 31 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 five significant counterparties, comprising $14.7 million or 19 percent of this credit exposure, were 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 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 June 30, 2015 and Dec. 31, 2014 , 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 June 30, 2015 and Dec. 31, 2014 . Recurring Fair Value Measurements — The following tables present for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at June 30, 2015 : June 30, 2015 Fair Value Fair Value Total Counterparty Netting (b) (Thousands of Dollars) Level 1 Level 2 Level 3 Total Current derivative assets Other derivative instruments: Commodity trading $ — $ 11,592 $ 7,927 $ 19,519 $ (6,848 ) $ 12,671 Electric commodity — — 29,822 29,822 (531 ) 29,291 Natural gas commodity — 56 — 56 — 56 Total current derivative assets $ — $ 11,648 $ 37,749 $ 49,397 $ (7,379 ) 42,018 PPAs (a) 480 Current derivative instruments $ 42,498 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 23,771 $ — $ 23,771 $ (5,504 ) $ 18,267 Total noncurrent derivative assets $ — $ 23,771 $ — $ 23,771 $ (5,504 ) 18,267 PPAs (a) 1,502 Noncurrent derivative instruments $ 19,769 June 30, 2015 Fair Value Fair Value Total Counterparty Netting (b) (Thousands of Dollars) Level 1 Level 2 Level 3 Total Current derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 58 $ — $ 58 $ — $ 58 Other derivative instruments: Commodity trading — 8,337 1,855 10,192 (7,097 ) 3,095 Electric commodity — — 531 531 (531 ) — Total current derivative liabilities $ — $ 8,395 $ 2,386 $ 10,781 $ (7,628 ) 3,153 PPAs (a) 14,114 Current derivative instruments $ 17,267 Noncurrent derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 27 $ — $ 27 $ — $ 27 Other derivative instruments: Commodity trading — 13,853 — 13,853 (11,731 ) 2,122 Total noncurrent derivative liabilities $ — $ 13,880 $ — $ 13,880 $ (11,731 ) 2,149 PPAs (a) 125,053 Noncurrent derivative instruments $ 127,202 (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 June 30, 2015 . At June 30, 2015 , derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $6.5 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, 2014 : Dec. 31, 2014 Fair Value Fair Value Total Counterparty Netting (b) (Thousands of Dollars) Level 1 Level 2 Level 3 Total Current derivative assets Other derivative instruments: Commodity trading $ — $ 14,326 $ 4,732 $ 19,058 $ (3,240 ) $ 15,818 Electric commodity — — 37,051 37,051 (1,512 ) 35,539 Natural gas commodity — 295 — 295 (4 ) 291 Total current derivative assets $ — $ 14,621 $ 41,783 $ 56,404 $ (4,756 ) 51,648 PPAs (a) 8,516 Current derivative instruments $ 60,164 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 17,617 $ — $ 17,617 $ (4,151 ) $ 13,466 Total noncurrent derivative assets $ — $ 17,617 $ — $ 17,617 $ (4,151 ) 13,466 PPAs (a) 1,968 Noncurrent derivative instruments $ 15,434 Dec. 31, 2014 Fair Value Fair Value Total Counterparty Netting (b) (Thousands of Dollars) Level 1 Level 2 Level 3 Total Current derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 65 $ — $ 65 $ — $ 65 Other derivative instruments: Commodity trading — 7,974 — 7,974 (7,974 ) — Electric commodity — — 1,512 1,512 (1,512 ) — Total current derivative liabilities $ — $ 8,039 $ 1,512 $ 9,551 $ (9,486 ) 65 PPAs (a) 12,229 Current derivative instruments $ 12,294 Noncurrent derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 56 $ — $ 56 $ — $ 56 Other derivative instruments: Commodity trading — 6,890 — 6,890 (6,033 ) 857 Total noncurrent derivative liabilities $ — $ 6,946 $ — $ 6,946 $ (6,033 ) 913 PPAs (a) 134,123 Noncurrent derivative instruments $ 135,036 (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, 2014 . At Dec. 31, 2014 , derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $6.6 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 six months ended June 30, 2015 and 2014 : Three Months Ended June 30 (Thousands of Dollars) 2015 2014 Balance at April 1 $ 10,972 $ 18,426 Purchases 40,162 81,689 Settlements (7,294 ) (20,056 ) Net transactions recorded during the period: Gains recognized in earnings (a) 1,220 6,438 Losses recognized as regulatory assets and liabilities (9,697 ) (15,045 ) Balance at June 30 $ 35,363 $ 71,452 Six Months Ended June 30 (Thousands of Dollars) 2015 2014 Balance at Jan. 1 $ 40,271 $ 31,727 Purchases 41,025 81,689 Settlements (18,845 ) (72,764 ) Net transactions recorded during the period: Gains recognized in earnings (a) 1,280 7,437 (Losses) gains recognized as regulatory assets and liabilities (28,368 ) 23,363 Balance at June 30 $ 35,363 $ 71,452 (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. There were no transfers of amounts between levels for derivative instruments for the three and six months ended June 30, 2015 and 2014. Fair Value of Long-Term Debt As of June 30, 2015 and Dec. 31, 2014 , other financial instruments for which the carrying amount did not equal fair value were as follows: June 30, 2015 Dec. 31, 2014 (Thousands of Dollars) Carrying Amount Fair Value Carrying Fair Value Long-term debt, including current portion $ 4,189,083 $ 4,568,614 $ 4,188,682 $ 4,803,735 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 June 30, 2015 and Dec. 31, 2014 , 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	6 Months Ended
	Jun. 30, 2015
Other Income and Expenses [Abstract]
Other (Expense) Income, Net	Other (Expense) Income, Net Other (expense) income, net consisted of the following: Three Months Ended June 30 Six Months Ended June 30 (Thousands of Dollars) 2015 2014 2015 2014 Interest income $ 92 $ 1,045 $ 3,424 $ 3,754 Other nonoperating income 60 38 92 406 Insurance policy expense (428 ) (1,554 ) (1,831 ) (2,627 ) Other (expense) income, net $ (276 ) $ (471 ) $ 1,685 $ 1,533

Segment Information

Segment Information	6 Months Ended
	Jun. 30, 2015
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 June 30, 2015 Operating revenues (a)(b) $ 999,872 $ 75,239 $ 6,863 $ — $ 1,081,974 Intersegment revenues 253 106 — (359 ) — Total revenues $ 1,000,125 $ 75,345 $ 6,863 $ (359 ) $ 1,081,974 Net income (loss) $ 90,697 $ (16,422 ) $ (94 ) $ — $ 74,181 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended June 30, 2014 Operating revenues (a)(b) $ 1,000,857 $ 116,381 $ 7,521 $ — $ 1,124,759 Intersegment revenues 252 220 — (472 ) — Total revenues $ 1,001,109 $ 116,601 $ 7,521 $ (472 ) $ 1,124,759 Net income $ 70,811 $ 41 $ 4,414 $ — $ 75,266 (a) Operating revenues include $118 million and $117 million of affiliate electric revenue for the three months ended June 30, 2015 and 2014 , respectively. (b) Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended June 30, 2015 and 2014 , respectively. (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Six Months Ended June 30, 2015 Operating revenues (a)(b) $ 2,006,026 $ 354,706 $ 13,724 $ — $ 2,374,456 Intersegment revenues 386 516 — (902 ) — Total revenues $ 2,006,412 $ 355,222 $ 13,724 $ (902 ) $ 2,374,456 Net income (loss) $ 61,098 (c) $ 23,850 $ (3,843 ) $ — $ 81,105 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Six Months Ended June 30, 2014 Operating revenues (a)(b) $ 2,069,197 $ 465,913 $ 13,975 $ — $ 2,549,085 Intersegment revenues 416 496 — (912 ) — Total revenues $ 2,069,613 $ 466,409 $ 13,975 $ (912 ) $ 2,549,085 Net income $ 149,066 $ 27,100 $ 7,464 $ — $ 183,630 (a) Operating revenues include $243 million and $238 million of affiliate electric revenue for the six months ended June 30, 2015 and 2014 , respectively. (b) Operating revenues include an immaterial amount of affiliate gas revenue for the six months ended June 30, 2015 and 2014 , respectively. (c) Includes a net of tax charge related to the Monticello LCM/EPU project. See Note 5.

Benefit Plans and Other Postret

Benefit Plans and Other Postretirement Benefits	6 Months Ended
	Jun. 30, 2015
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 June 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Care Benefits Service cost $ 7,889 $ 7,425 $ 40 $ 46 Interest cost 10,803 11,827 953 1,249 Expected return on plan assets (15,707 ) (15,730 ) (30 ) (76 ) Amortization of prior service cost (credit) 234 234 (759 ) (759 ) Amortization of net loss 11,548 11,196 523 854 Net periodic benefit cost 14,767 14,952 727 1,314 Costs not recognized due to the effects of regulation (7,843 ) (7,312 ) — — Net benefit cost recognized for financial reporting $ 6,924 $ 7,640 $ 727 $ 1,314 Six Months Ended June 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Care Benefits Service cost $ 15,778 $ 14,850 $ 80 $ 93 Interest cost 21,607 23,654 1,907 2,497 Expected return on plan assets (31,415 ) (31,460 ) (60 ) (151 ) Amortization of prior service cost (credit) 468 468 (1,518 ) (1,518 ) Amortization of net loss 23,096 22,392 1,046 1,708 Net periodic benefit cost 29,534 29,904 1,455 2,629 Costs not recognized due to the effects of regulation (15,685 ) (15,071 ) — — Net benefit cost recognized for financial reporting $ 13,849 $ 14,833 $ 1,455 $ 2,629 In January 2015, contributions of $90.0 million were made across four of Xcel Energy’s pension plans, of which $32.7 million was attributable to NSP-Minnesota. Xcel Energy does not expect additional pension contributions during 2015.

Other Comprehensive Income

Other Comprehensive Income	6 Months Ended
	Jun. 30, 2015
Stockholders' Equity Note [Abstract]
Other Comprehensive Income	Other Comprehensive Income Changes in accumulated other comprehensive income (loss), net of tax, for the three and six months ended June 30, 2015 and 2014 were as follows: Three Months Ended June 30, 2015 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains on Marketable Securities Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive (loss) income at April 1 $ (19,707 ) $ 106 $ (1,016 ) $ (20,617 ) Other comprehensive (loss) income before reclassifications 9 1 — 10 Losses (gains) reclassified from net accumulated other comprehensive loss 214 — (6 ) 208 Net current period other comprehensive income (loss) 223 1 (6 ) 218 Accumulated other comprehensive (loss) income at June 30 $ (19,484 ) $ 107 $ (1,022 ) $ (20,399 ) Three Months Ended June 30, 2014 (Thousands of Dollars) Gains and Unrealized Defined Benefit Total Accumulated other comprehensive loss at April 1 $ (20,420 ) $ 110 $ (1,188 ) $ (21,498 ) Other comprehensive loss before reclassifications 10 — — 10 Losses reclassified from net accumulated other comprehensive loss 200 — 6 206 Net current period other comprehensive income 210 — 6 216 Accumulated other comprehensive loss at June 30 $ (20,210 ) $ 110 $ (1,182 ) $ (21,282 ) Six Months Ended June 30, 2015 (Thousands of Dollars) Gains and Unrealized Defined Benefit Total Accumulated other comprehensive (loss) income at Jan. 1 $ (19,909 ) $ 105 $ (1,010 ) $ (20,814 ) Other comprehensive (loss) income before reclassifications 2 2 — 4 Losses (gains) reclassified from net accumulated other comprehensive loss 423 — (12 ) 411 Net current period other comprehensive income 425 2 (12 ) 415 Accumulated other comprehensive (loss) income at June 30 $ (19,484 ) $ 107 $ (1,022 ) $ (20,399 ) Six Months Ended June 30, 2014 (Thousands of Dollars) Gains and Unrealized Defined Benefit Total Accumulated other comprehensive (loss) income at Jan. 1 $ (20,609 ) $ 73 $ (1,193 ) $ (21,729 ) Other comprehensive (loss) income before reclassifications 6 37 — 43 Losses reclassified from net accumulated other comprehensive loss 393 — 11 404 Net current period other comprehensive income 399 37 11 447 Accumulated other comprehensive (loss) income at June 30 $ (20,210 ) $ 110 $ (1,182 ) $ (21,282 ) Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2015 and 2014 were as follows: Amounts Reclassified from (Thousands of Dollars) Three Months Ended June 30, 2015 Three Months Ended June 30, 2014 (Gains) losses on cash flow hedges: Interest rate derivatives $ 346 (a) $ 346 (a) Vehicle fuel derivatives 16 (b) (8 ) (b) Total, pre-tax 362 338 Tax benefit (148 ) (138 ) Total, net of tax 214 200 Defined benefit pension and postretirement (gains) losses: Amortization of net loss 40 (c) 58 (c) Prior service credit (48 ) (c) (48 ) (c) Total, pre-tax (8 ) 10 Tax expense (benefit) 2 (4 ) Total, net of tax (6 ) 6 Total amounts reclassified, net of tax $ 208 $ 206 Amounts Reclassified from (Thousands of Dollars) Six Months Ended June 30, 2015 Six Months Ended June 30, 2014 (Gains) losses on cash flow hedges: Interest rate derivatives $ 686 (a) $ 688 (a) Vehicle fuel derivatives 30 (b) (24 ) (b) Total, pre-tax 716 664 Tax benefit (293 ) (271 ) Total, net of tax 423 393 Defined benefit pension and postretirement (gains) losses: Amortization of net loss 77 (c) 116 (c) Prior service credit (99 ) (c) (97 ) (c) Total, pre-tax (22 ) 19 Tax expense (benefit) 10 (8 ) Total, net of tax (12 ) 11 Total amounts reclassified, net of tax $ 411 $ 404 (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)	6 Months Ended
	Jun. 30, 2015
Balance Sheet Related Disclosures [Abstract]
Accounts receivable, net	(Thousands of Dollars) June 30, 2015 Dec. 31, 2014 Accounts receivable, net Accounts receivable $ 312,702 $ 390,633 Less allowance for bad debts (18,941 ) (22,937 ) $ 293,761 $ 367,696
Inventories	(Thousands of Dollars) June 30, 2015 Dec. 31, 2014 Inventories Materials and supplies $ 166,383 $ 157,376 Fuel 99,402 77,139 Natural gas 18,809 55,772 $ 284,594 $ 290,287
Property, plant and equipment, net	(Thousands of Dollars) June 30, 2015 Dec. 31, 2014 Property, plant and equipment, net Electric plant $ 15,175,091 $ 14,831,286 Natural gas plant 1,192,119 1,177,021 Common and other property 575,241 568,287 Construction work in progress 641,152 706,979 Total property, plant and equipment 17,583,603 17,283,573 Less accumulated depreciation (6,180,843 ) (6,012,145 ) Nuclear fuel 2,405,823 2,347,422 Less accumulated amortization (2,006,684 ) (1,957,230 ) $ 11,801,899 $ 11,661,620

Income Taxes (Tables)

Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Reconciliation of Unrecognized Tax Benefits	A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) June 30, 2015 Dec. 31, 2014 Unrecognized tax benefit — Permanent tax positions $ 12.4 $ 12.2 Unrecognized tax benefit — Temporary tax positions 21.5 18.2 Total unrecognized tax benefit $ 33.9 $ 30.4
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) June 30, 2015 Dec. 31, 2014 NOL and tax credit carryforwards $ (12.6 ) $ (10.8 )

Rate Matters (Tables)

Rate Matters (Tables)	6 Months Ended
	Jun. 30, 2015
Public Utilities, General Disclosures [Abstract]
NSP-Minnesota's 2014 Electric Rate Case [Table Text Block]	The following tables outline NSP-Minnesota’s filed request and the impact of the MPUC’s decisions made in May and July: 2014 Rate Request (Millions of Dollars) NSP-Minnesota MPUC May Decision NSP-Minnesota’s filed rate request $ 192.7 $ 192.7 Sales forecast (with true-up to 12 months of actual weather-normalized sales) (38.5 ) (37.5 ) ROE — (31.9 ) Monticello EPU cost recovery (12.2 ) (37.6 ) Property taxes (with true-up to actual 2014 accruals) (13.2 ) (13.2 ) Prairie Island EPU cost recovery (5.1 ) (5.0 ) Health care, pension and other benefits (1.9 ) (3.1 ) Other, net (6.5 ) (5.5 ) Total 2014 $ 115.3 $ 58.9 2015 Rate Request (Millions of Dollars) NSP-Minnesota MPUC May Decision NSP-Minnesota’s filed rate request $ 98.5 $ 98.5 Monticello EPU cost recovery 11.7 35.4 Depreciation / Retirements — (0.5 ) Property taxes (3.3 ) (3.3 ) Production tax credits to be included in base rates (11.1 ) (11.1 ) U.S. Department of Energy (DOE) settlement proceeds 10.1 10.1 Emission chemicals (1.6 ) (1.6 ) Other, net 1.7 (2.3 ) Total 2015 step increase - prior to Monticello Life Cycle Management (LCM)/EPU cost disallowance $ 106.0 $ 125.2 Total for 2014 and 2015 step increase - prior to Monticello LCM/EPU cost disallowance $ 221.3 $ 184.1 Monticello LCM/EPU cost disallowance — (18.0 ) Total for 2014 and 2015 step increase - including Monticello LCM/EPU cost disallowance $ 221.3 $ 166.1 (Millions of Dollars) MPUC July Decision 2015 annual rate increase - based on MPUC May order $ 166.1 Reconsideration/clarification adjustments: 2015 Monticello EPU used-and-useful adjustment (13.8 ) 2014 property tax final true-up (3.1 ) Other, net 0.2 Total 2015 annual rate increase $ 149.4 Impact of interim rate effective March 3, 2015 (3.6 ) Estimated 2015 revenue impact $ 145.8

Commitments and Contingencies S

Commitments and Contingencies Schedule of Guarantor Obligations (Tables)	6 Months Ended
	Jun. 30, 2015
Commitments and Contingencies Disclosure [Abstract]
Guarantees Issued and Outstanding	The following table presents the guarantee issued and outstanding for NSP-Minnesota: (Millions of Dollars) June 30, 2015 Dec. 31, 2014 Guarantees issued and outstanding $ 4.8 $ 4.8

Borrowings and Other Financin26

Borrowings and Other Financing Instruments (Tables)	6 Months Ended
	Jun. 30, 2015
Borrowings and Other Financing Instruments [Abstract]
Credit Facilities	At June 30, 2015 , NSP-Minnesota had the following committed credit facility available (in millions of dollars): Credit Facility (a) Drawn (b) Available $ 500 $ 144 $ 356 (a) This credit facility expires in October 2019. (b) Includes outstanding commercial paper and 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 June 30, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 250 $ 250 Amount outstanding at period end — — Average amount outstanding 6 12 Maximum amount outstanding 50 150 Weighted average interest rate, computed on a daily basis 0.54 % 0.21 % Weighted average interest rate at period end N/A N/A
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 June 30, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 500 $ 500 Amount outstanding at period end 117 142 Average amount outstanding 95 111 Maximum amount outstanding 208 397 Weighted average interest rate, computed on a daily basis 0.41 % 0.26 % Weighted average interest rate at period end 0.42 0.53

Fair Value of Financial Asset27

Fair Value of Financial Assets and Liabilities (Tables)	6 Months Ended
	Jun. 30, 2015
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 June 30, 2015 and Dec. 31, 2014 : June 30, 2015 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Total Nuclear decommissioning fund (a) Cash equivalents $ 12,446 $ 12,446 $ — $ — $ 12,446 Commingled funds 451,398 — 499,782 — 499,782 International equity funds 123,123 — 121,502 — 121,502 Private equity investments 95,067 — — 133,993 133,993 Real estate 49,369 — — 70,834 70,834 Debt securities: Government securities 24,408 — 22,183 — 22,183 U.S. corporate bonds 69,194 — 66,096 — 66,096 International corporate bonds 16,506 — 16,294 — 16,294 Municipal bonds 209,103 — 210,898 — 210,898 Asset-backed securities 2,831 — 2,851 — 2,851 Mortgage-backed securities 12,039 — 12,219 — 12,219 Equity securities: Common stock 382,755 583,031 — — 583,031 Total $ 1,448,239 $ 595,477 $ 951,825 $ 204,827 $ 1,752,129 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $32.5 million of miscellaneous investments. Dec. 31, 2014 Fair Value (Thousands of Dollars) Cost Level 1 Level 2 Level 3 Total Nuclear decommissioning fund (a) Cash equivalents $ 24,184 $ 24,184 $ — $ — $ 24,184 Commingled funds 470,013 — 465,615 — 465,615 International equity funds 80,454 — 78,721 — 78,721 Private equity investments 73,936 — — 101,237 101,237 Real estate 43,859 — — 64,249 64,249 Debt securities: Government securities 30,674 — 28,808 — 28,808 U.S. corporate bonds 81,463 — 77,562 — 77,562 International corporate bonds 16,950 — 16,341 — 16,341 Municipal bonds 242,282 — 249,201 — 249,201 Asset-backed securities 9,131 — 9,250 — 9,250 Mortgage-backed securities 23,225 — 23,895 — 23,895 Equity securities: Common stock 369,751 564,858 — — 564,858 Total $ 1,465,922 $ 589,042 $ 949,393 $ 165,486 $ 1,703,921 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $31.4 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 six months ended June 30, 2015 and 2014 : (Thousands of Dollars) April 1, 2015 Purchases Settlements Gains Assets (a) June 30, 2015 Private equity investments $ 113,619 $ 8,749 $ — $ 11,625 $ 133,993 Real estate 67,774 4,271 (1,241 ) 30 70,834 Total $ 181,393 $ 13,020 $ (1,241 ) $ 11,655 $ 204,827 (Thousands of Dollars) April 1, 2014 Purchases Settlements Gains (a) June 30, 2014 Private equity investments $ 73,801 $ 2,184 $ — $ 5,138 $ 81,123 Real estate 62,954 197 — 2,507 65,658 Total $ 136,755 $ 2,381 $ — $ 7,645 $ 146,781 (Thousands of Dollars) Jan. 1, 2015 Purchases Settlements Gains Assets (a) June 30, 2015 Private equity investments $ 101,237 $ 21,131 $ — $ 11,625 $ 133,993 Real estate 64,249 8,132 (2,622 ) 1,075 70,834 Total $ 165,486 $ 29,263 $ (2,622 ) $ 12,700 $ 204,827 (Thousands of Dollars) Jan. 1, 2014 Purchases Settlements Gains Assets (a) June 30, 2014 Private equity investments $ 62,696 $ 10,953 $ — $ 7,474 $ 81,123 Real estate 57,368 3,856 — 4,434 65,658 Total $ 120,064 $ 14,809 $ — $ 11,908 $ 146,781 (a) Gains are deferred as a component of the regulatory assets for nuclear decommissioning.
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 June 30, 2015 : Final Contractual Maturity (Thousands of Dollars) Due in 1 Year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total Government securities $ — $ — $ — $ 22,183 $ 22,183 U.S. corporate bonds — 14,684 54,005 (2,593 ) 66,096 International corporate bonds — 3,951 11,325 1,018 16,294 Municipal bonds 361 32,427 41,313 136,797 210,898 Asset-backed securities — — 2,851 — 2,851 Mortgage-backed securities — — — 12,219 12,219 Debt securities $ 361 $ 51,062 $ 109,494 $ 169,624 $ 330,541
Gross Notional Amounts of Commodity Forwards, Options, and FTRs	The following table details the gross notional amounts of commodity forwards, options and FTRs at June 30, 2015 and Dec. 31, 2014 : (Amounts in Thousands) (a)(b) June 30, 2015 Dec. 31, 2014 Megawatt hours of electricity 83,839 49,431 Million British thermal units of natural gas 942 173 Gallons of vehicle fuel 116 155 (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 six months ended June 30, 2015 and 2014 on accumulated other comprehensive loss, regulatory assets and liabilities and income: Three Months Ended June 30, 2015 Pre-Tax Fair Value Pre-Tax (Gains) Losses Pre-Tax Gains (Thousands of Dollars) Accumulated Regulatory Accumulated Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 346 (a) $ — $ — Vehicle fuel and other commodity 15 — 16 (b) — — Total $ 15 $ — $ 362 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 4,210 (c) Electric commodity — (3,517 ) — (6,327 ) (d) — Natural gas commodity — 56 — — — Total $ — $ (3,461 ) $ — $ (6,327 ) $ 4,210 Six Months Ended June 30, 2015 Pre-Tax Fair Value Pre-Tax (Gains) Losses Pre-Tax Gains (Thousands of Dollars) Accumulated Regulatory Accumulated Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 686 (a) $ — $ — Vehicle fuel and other commodity 5 — 30 (b) — — Total $ 5 $ — $ 716 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 7,902 (c) Electric commodity — (12,223 ) — (11,520 ) (d) — Natural gas commodity — 18 — (2,751 ) (e) 3,008 (e) Total $ — $ (12,205 ) $ — $ (14,271 ) $ 10,910 Three Months Ended June 30, 2014 Pre-Tax Fair Value Pre-Tax (Gains) Losses Pre-Tax Gains (Thousands of Dollars) Accumulated Regulatory Accumulated Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 346 (a) $ — $ — Vehicle fuel and other commodity 17 — (8 ) (b) — — Total $ 17 $ — $ 338 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 5,175 (c) Electric commodity — (16,347 ) — (6,461 ) (d) — Natural gas commodity — (493 ) — — — Other commodity — — — — 643 (c) Total $ — $ (16,840 ) $ — $ (6,461 ) $ 5,818 Six Months Ended June 30, 2014 Pre-Tax Fair Value Pre-Tax (Gains) Losses Pre-Tax Gains (Losses) (Thousands of Dollars) Accumulated Regulatory Accumulated Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 688 (a) $ — $ — Vehicle fuel and other commodity 10 — (24 ) (b) — — Total $ 10 $ — $ 664 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 2,922 (c) Electric commodity — (11,448 ) — (24,387 ) (d) — Natural gas commodity — 7,408 — (9,306 ) (e) (580 ) (e) Other commodity — — — — 643 (c) Total $ — $ (4,040 ) $ — $ (33,693 ) $ 2,985 (a) Amounts are recorded to interest charges. (b) Amounts are recorded to operating and maintenance (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 tables present for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at June 30, 2015 : June 30, 2015 Fair Value Fair Value Total Counterparty Netting (b) (Thousands of Dollars) Level 1 Level 2 Level 3 Total Current derivative assets Other derivative instruments: Commodity trading $ — $ 11,592 $ 7,927 $ 19,519 $ (6,848 ) $ 12,671 Electric commodity — — 29,822 29,822 (531 ) 29,291 Natural gas commodity — 56 — 56 — 56 Total current derivative assets $ — $ 11,648 $ 37,749 $ 49,397 $ (7,379 ) 42,018 PPAs (a) 480 Current derivative instruments $ 42,498 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 23,771 $ — $ 23,771 $ (5,504 ) $ 18,267 Total noncurrent derivative assets $ — $ 23,771 $ — $ 23,771 $ (5,504 ) 18,267 PPAs (a) 1,502 Noncurrent derivative instruments $ 19,769 June 30, 2015 Fair Value Fair Value Total Counterparty Netting (b) (Thousands of Dollars) Level 1 Level 2 Level 3 Total Current derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 58 $ — $ 58 $ — $ 58 Other derivative instruments: Commodity trading — 8,337 1,855 10,192 (7,097 ) 3,095 Electric commodity — — 531 531 (531 ) — Total current derivative liabilities $ — $ 8,395 $ 2,386 $ 10,781 $ (7,628 ) 3,153 PPAs (a) 14,114 Current derivative instruments $ 17,267 Noncurrent derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 27 $ — $ 27 $ — $ 27 Other derivative instruments: Commodity trading — 13,853 — 13,853 (11,731 ) 2,122 Total noncurrent derivative liabilities $ — $ 13,880 $ — $ 13,880 $ (11,731 ) 2,149 PPAs (a) 125,053 Noncurrent derivative instruments $ 127,202 (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 June 30, 2015 . At June 30, 2015 , derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $6.5 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, 2014 : Dec. 31, 2014 Fair Value Fair Value Total Counterparty Netting (b) (Thousands of Dollars) Level 1 Level 2 Level 3 Total Current derivative assets Other derivative instruments: Commodity trading $ — $ 14,326 $ 4,732 $ 19,058 $ (3,240 ) $ 15,818 Electric commodity — — 37,051 37,051 (1,512 ) 35,539 Natural gas commodity — 295 — 295 (4 ) 291 Total current derivative assets $ — $ 14,621 $ 41,783 $ 56,404 $ (4,756 ) 51,648 PPAs (a) 8,516 Current derivative instruments $ 60,164 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 17,617 $ — $ 17,617 $ (4,151 ) $ 13,466 Total noncurrent derivative assets $ — $ 17,617 $ — $ 17,617 $ (4,151 ) 13,466 PPAs (a) 1,968 Noncurrent derivative instruments $ 15,434 Dec. 31, 2014 Fair Value Fair Value Total Counterparty Netting (b) (Thousands of Dollars) Level 1 Level 2 Level 3 Total Current derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 65 $ — $ 65 $ — $ 65 Other derivative instruments: Commodity trading — 7,974 — 7,974 (7,974 ) — Electric commodity — — 1,512 1,512 (1,512 ) — Total current derivative liabilities $ — $ 8,039 $ 1,512 $ 9,551 $ (9,486 ) 65 PPAs (a) 12,229 Current derivative instruments $ 12,294 Noncurrent derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 56 $ — $ 56 $ — $ 56 Other derivative instruments: Commodity trading — 6,890 — 6,890 (6,033 ) 857 Total noncurrent derivative liabilities $ — $ 6,946 $ — $ 6,946 $ (6,033 ) 913 PPAs (a) 134,123 Noncurrent derivative instruments $ 135,036 (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, 2014 . At Dec. 31, 2014 , derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $6.6 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 six months ended June 30, 2015 and 2014 : Three Months Ended June 30 (Thousands of Dollars) 2015 2014 Balance at April 1 $ 10,972 $ 18,426 Purchases 40,162 81,689 Settlements (7,294 ) (20,056 ) Net transactions recorded during the period: Gains recognized in earnings (a) 1,220 6,438 Losses recognized as regulatory assets and liabilities (9,697 ) (15,045 ) Balance at June 30 $ 35,363 $ 71,452 Six Months Ended June 30 (Thousands of Dollars) 2015 2014 Balance at Jan. 1 $ 40,271 $ 31,727 Purchases 41,025 81,689 Settlements (18,845 ) (72,764 ) Net transactions recorded during the period: Gains recognized in earnings (a) 1,280 7,437 (Losses) gains recognized as regulatory assets and liabilities (28,368 ) 23,363 Balance at June 30 $ 35,363 $ 71,452 (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 June 30, 2015 and Dec. 31, 2014 , other financial instruments for which the carrying amount did not equal fair value were as follows: June 30, 2015 Dec. 31, 2014 (Thousands of Dollars) Carrying Amount Fair Value Carrying Fair Value Long-term debt, including current portion $ 4,189,083 $ 4,568,614 $ 4,188,682 $ 4,803,735

Other (Expense) Income, Net (Ta

Other (Expense) Income, Net (Tables)	6 Months Ended
	Jun. 30, 2015
Other Income and Expenses [Abstract]
Other (Expense) Income, Net	Other (expense) income, net consisted of the following: Three Months Ended June 30 Six Months Ended June 30 (Thousands of Dollars) 2015 2014 2015 2014 Interest income $ 92 $ 1,045 $ 3,424 $ 3,754 Other nonoperating income 60 38 92 406 Insurance policy expense (428 ) (1,554 ) (1,831 ) (2,627 ) Other (expense) income, net $ (276 ) $ (471 ) $ 1,685 $ 1,533

Segment Information (Tables)

Segment Information (Tables)	6 Months Ended
	Jun. 30, 2015
Segment Reporting [Abstract]
Results by Reportable Segment	(Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended June 30, 2015 Operating revenues (a)(b) $ 999,872 $ 75,239 $ 6,863 $ — $ 1,081,974 Intersegment revenues 253 106 — (359 ) — Total revenues $ 1,000,125 $ 75,345 $ 6,863 $ (359 ) $ 1,081,974 Net income (loss) $ 90,697 $ (16,422 ) $ (94 ) $ — $ 74,181 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended June 30, 2014 Operating revenues (a)(b) $ 1,000,857 $ 116,381 $ 7,521 $ — $ 1,124,759 Intersegment revenues 252 220 — (472 ) — Total revenues $ 1,001,109 $ 116,601 $ 7,521 $ (472 ) $ 1,124,759 Net income $ 70,811 $ 41 $ 4,414 $ — $ 75,266 (a) Operating revenues include $118 million and $117 million of affiliate electric revenue for the three months ended June 30, 2015 and 2014 , respectively. (b) Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended June 30, 2015 and 2014 , respectively. (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Six Months Ended June 30, 2015 Operating revenues (a)(b) $ 2,006,026 $ 354,706 $ 13,724 $ — $ 2,374,456 Intersegment revenues 386 516 — (902 ) — Total revenues $ 2,006,412 $ 355,222 $ 13,724 $ (902 ) $ 2,374,456 Net income (loss) $ 61,098 (c) $ 23,850 $ (3,843 ) $ — $ 81,105 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Six Months Ended June 30, 2014 Operating revenues (a)(b) $ 2,069,197 $ 465,913 $ 13,975 $ — $ 2,549,085 Intersegment revenues 416 496 — (912 ) — Total revenues $ 2,069,613 $ 466,409 $ 13,975 $ (912 ) $ 2,549,085 Net income $ 149,066 $ 27,100 $ 7,464 $ — $ 183,630 (a) Operating revenues include $243 million and $238 million of affiliate electric revenue for the six months ended June 30, 2015 and 2014 , respectively. (b) Operating revenues include an immaterial amount of affiliate gas revenue for the six months ended June 30, 2015 and 2014 , respectively. (c) Includes a net of tax charge related to the Monticello LCM/EPU project. See Note 5.

Benefit Plans and Other Postr30

Benefit Plans and Other Postretirement Benefits (Tables)	6 Months Ended
	Jun. 30, 2015
Compensation and Retirement Disclosure [Abstract]
Components of Net Periodic Benefit Cost (Credit)	Components of Net Periodic Benefit Cost Three Months Ended June 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Care Benefits Service cost $ 7,889 $ 7,425 $ 40 $ 46 Interest cost 10,803 11,827 953 1,249 Expected return on plan assets (15,707 ) (15,730 ) (30 ) (76 ) Amortization of prior service cost (credit) 234 234 (759 ) (759 ) Amortization of net loss 11,548 11,196 523 854 Net periodic benefit cost 14,767 14,952 727 1,314 Costs not recognized due to the effects of regulation (7,843 ) (7,312 ) — — Net benefit cost recognized for financial reporting $ 6,924 $ 7,640 $ 727 $ 1,314 Six Months Ended June 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Care Benefits Service cost $ 15,778 $ 14,850 $ 80 $ 93 Interest cost 21,607 23,654 1,907 2,497 Expected return on plan assets (31,415 ) (31,460 ) (60 ) (151 ) Amortization of prior service cost (credit) 468 468 (1,518 ) (1,518 ) Amortization of net loss 23,096 22,392 1,046 1,708 Net periodic benefit cost 29,534 29,904 1,455 2,629 Costs not recognized due to the effects of regulation (15,685 ) (15,071 ) — — Net benefit cost recognized for financial reporting $ 13,849 $ 14,833 $ 1,455 $ 2,629

Other Comprehensive Income (Tab

Other Comprehensive Income (Tables)	6 Months Ended
	Jun. 30, 2015
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 six months ended June 30, 2015 and 2014 were as follows: Three Months Ended June 30, 2015 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Unrealized Gains on Marketable Securities Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive (loss) income at April 1 $ (19,707 ) $ 106 $ (1,016 ) $ (20,617 ) Other comprehensive (loss) income before reclassifications 9 1 — 10 Losses (gains) reclassified from net accumulated other comprehensive loss 214 — (6 ) 208 Net current period other comprehensive income (loss) 223 1 (6 ) 218 Accumulated other comprehensive (loss) income at June 30 $ (19,484 ) $ 107 $ (1,022 ) $ (20,399 ) Three Months Ended June 30, 2014 (Thousands of Dollars) Gains and Unrealized Defined Benefit Total Accumulated other comprehensive loss at April 1 $ (20,420 ) $ 110 $ (1,188 ) $ (21,498 ) Other comprehensive loss before reclassifications 10 — — 10 Losses reclassified from net accumulated other comprehensive loss 200 — 6 206 Net current period other comprehensive income 210 — 6 216 Accumulated other comprehensive loss at June 30 $ (20,210 ) $ 110 $ (1,182 ) $ (21,282 ) Six Months Ended June 30, 2015 (Thousands of Dollars) Gains and Unrealized Defined Benefit Total Accumulated other comprehensive (loss) income at Jan. 1 $ (19,909 ) $ 105 $ (1,010 ) $ (20,814 ) Other comprehensive (loss) income before reclassifications 2 2 — 4 Losses (gains) reclassified from net accumulated other comprehensive loss 423 — (12 ) 411 Net current period other comprehensive income 425 2 (12 ) 415 Accumulated other comprehensive (loss) income at June 30 $ (19,484 ) $ 107 $ (1,022 ) $ (20,399 ) Six Months Ended June 30, 2014 (Thousands of Dollars) Gains and Unrealized Defined Benefit Total Accumulated other comprehensive (loss) income at Jan. 1 $ (20,609 ) $ 73 $ (1,193 ) $ (21,729 ) Other comprehensive (loss) income before reclassifications 6 37 — 43 Losses reclassified from net accumulated other comprehensive loss 393 — 11 404 Net current period other comprehensive income 399 37 11 447 Accumulated other comprehensive (loss) income at June 30 $ (20,210 ) $ 110 $ (1,182 ) $ (21,282 )
Reclassifications out of Accumulated Other Comprehensive Loss	Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2015 and 2014 were as follows: Amounts Reclassified from (Thousands of Dollars) Three Months Ended June 30, 2015 Three Months Ended June 30, 2014 (Gains) losses on cash flow hedges: Interest rate derivatives $ 346 (a) $ 346 (a) Vehicle fuel derivatives 16 (b) (8 ) (b) Total, pre-tax 362 338 Tax benefit (148 ) (138 ) Total, net of tax 214 200 Defined benefit pension and postretirement (gains) losses: Amortization of net loss 40 (c) 58 (c) Prior service credit (48 ) (c) (48 ) (c) Total, pre-tax (8 ) 10 Tax expense (benefit) 2 (4 ) Total, net of tax (6 ) 6 Total amounts reclassified, net of tax $ 208 $ 206 Amounts Reclassified from (Thousands of Dollars) Six Months Ended June 30, 2015 Six Months Ended June 30, 2014 (Gains) losses on cash flow hedges: Interest rate derivatives $ 686 (a) $ 688 (a) Vehicle fuel derivatives 30 (b) (24 ) (b) Total, pre-tax 716 664 Tax benefit (293 ) (271 ) Total, net of tax 423 393 Defined benefit pension and postretirement (gains) losses: Amortization of net loss 77 (c) 116 (c) Prior service credit (99 ) (c) (97 ) (c) Total, pre-tax (22 ) 19 Tax expense (benefit) 10 (8 ) Total, net of tax (12 ) 11 Total amounts reclassified, net of tax $ 411 $ 404 (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 ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$ 312,702	$ 390,633
Less allowance for bad debts	(18,941)	(22,937)
Accounts receivable, net	$ 293,761	$ 367,696

Selected Balance Sheet Data, In

Selected Balance Sheet Data, Inventories (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Public Utilities, Inventory [Line Items]
Inventories	$ 284,594	$ 290,287
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	166,383	157,376
Fuel
Public Utilities, Inventory [Line Items]
Inventories	99,402	77,139
Natural gas
Public Utilities, Inventory [Line Items]
Inventories	$ 18,809	$ 55,772

Selected Balance Sheet Data, Pr

Selected Balance Sheet Data, Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 17,583,603	$ 17,283,573
Less accumulated depreciation	(6,180,843)	(6,012,145)
Property, plant and equipment, net	11,801,899	11,661,620
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	15,175,091	14,831,286
Natural gas plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	1,192,119	1,177,021
Common and other property
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	575,241	568,287
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	641,152	706,979
Nuclear fuel
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	2,405,823	2,347,422
Less accumulated depreciation	$ (2,006,684)	$ (1,957,230)

Income Taxes (Details)

Income Taxes (Details) - USD ($)	3 Months Ended	6 Months Ended
	Sep. 30, 2012	Jun. 30, 2015	Dec. 31, 2014
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions		$ 12,400,000	$ 12,200,000
Unrecognized tax benefit — Temporary tax positions		21,500,000	18,200,000
Total unrecognized tax benefit		33,900,000	30,400,000
NOL and tax credit carryforwards		(12,600,000)	$ (10,800,000)
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
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Earliest year subject to examination		2,009
Year(s) under examination	2010 and 2011
Year of carryback claim under examination	2,009
Potential Tax Adjustments		$ 12,000,000
State Jurisdiction (Minnesota)
Tax Audits [Abstract]
Earliest year subject to examination		2,009

Rate Matters (Details)

Rate Matters (Details) $ in Thousands

1 Months Ended

3 Months Ended

6 Months Ended

12 Months Ended

Jul. 31, 2015USD ($)

Jun. 30, 2015USD ($)MW

May. 31, 2015USD ($)

Mar. 31, 2015USD ($)

Feb. 28, 2015

Jan. 31, 2015USD ($)

Nov. 30, 2014

Oct. 31, 2014USD ($)

Jun. 30, 2014USD ($)

Dec. 31, 2013USD ($)

Nov. 30, 2013USD ($)

Jun. 30, 2015USD ($)

Mar. 31, 2015USD ($)

Jun. 30, 2014USD ($)

Jun. 30, 2015USD ($)MW

Jun. 30, 2014USD ($)

Dec. 31, 2014USD ($)

Rate Matters [Abstract]

Loss on Monticello LCM/EPU project

$ 0

$ 0

$ 124,226

$ 0

NSP-Minnesota | 2014 Electric Rate Case [Member]

Rate Matters [Abstract]

Public Utilities, number of years rate case is applicable for (in years)

2 years

Public Utilities, Requested Return on Equity, Percentage

10.25%

Public Utilities, Requested Equity Capital Structure, Percentage

52.50%

Amount of public utility's amended unadjusted cumulative multi-year increase (decrease)

$ 221,300

Facility generating capacity (in MW) | MW

671

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

0

Amount of public utility's amended estimated adjusted cumulative multi-year rate increase (decrease)

221,300

NSP-Minnesota | Electric Rate Case 2014, Rates 2014 [Member]

Rate Matters [Abstract]

Public Utilities, Requested Rate Base, Amount

$ 6,670,000

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 192,700

Public Utilities, Requested Rate Increase (Decrease), Percentage

6.90%

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

115,300

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

(38,500)

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 public utility related to Monticello EPU costs

(12,200)

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

(13,200)

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

(5,100)

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

(1,900)

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

(6,500)

NSP-Minnesota | Electric Rate Case 2014, Rates 2015 [Member]

Rate Matters [Abstract]

Public Utilities, Requested Rate Base, Amount

$ 412,000

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 98,000

98,500

Public Utilities, Requested Rate Increase (Decrease), Percentage

3.50%

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

106,000

Amount of public utility's amended unadjusted cumulative multi-year increase (decrease)

221,300

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

11,700

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

(3,300)

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

1,700

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

0

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

(11,100)

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

10,100

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

(1,600)

NSP-Minnesota | Nuclear Project Prudency Investigation [Member]

Rate Matters [Abstract]

Costs for nuclear project, Amount

665,000

Total capitalized nuclear project costs

748,000

Initial estimated nuclear project expenditures

$ 320,000

Loss on Monticello LCM/EPU project

$ 129,000

NSP-Minnesota | MPUC Proceeding - Transmission Cost Recovery Rider Filing 2015 [Member]

Rate Matters [Abstract]

Public Utilities, Projected incremental revenue from rider in 2015

$ 65,800

Public Utilities, Approved Increase (Decrease) to Rider Revenue, Amount

$ 63,800

NSP-Minnesota | Electric Rate Case 2015 [Member]

Rate Matters [Abstract]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 15,600

Public Utilities, Requested Rate Increase (Decrease), Percentage

8.00%

Public Utilities, Interim Rate Increase (Decrease), Amount

$ 15,600

NSP-Minnesota | FERC Proceeding, MISO ROE Complaint [Member]

Rate Matters [Abstract]

Public Utilities, Base return on equity charged to customers through transmission formula rates

12.38%

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

50.00%

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

8.67%

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

9.54%

Public Utilities, ROE applicable to transmission formula rates in the MISO region, recommended by third parties

8.67%

9.15%

Public Utilities, Incremental ROE basis point increase (decrease) recommended by third parties

50

NSP-Minnesota | Minnesota Public Utilities Commission [Member] | 2014 Electric Rate Case [Member]

Rate Matters [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 166,000

Public Utilities, Approved Rate Increase (Decrease), Percentage

5.90%

Public Utilities, Approved Return on Equity, Percentage

9.72%

Public Utilities, Approved Equity Capital Structure, Percentage

52.50%

Public Utilities, number of years of decoupling pilot for the residential and small commercial and industrial (C&I) class

3 years

Public Utilities, amount of percent cap on base revenue for three year revenue decoupling pilot for the residential and small commercial and industrial (C&I) class

3.00%

Public Utilities; Approved adjustment to requested rate increase (decrease) related to Monticello EPU costs

$ (18,000)

Public Utilities, Unadjusted cumulative multi-year increase (decrease), approved.

184,100

Public Utilities, Estimated adjusted cumulative multi-year increase (decrease), approved.

166,100

NSP-Minnesota | Minnesota Public Utilities Commission [Member] | Electric Rate Case 2014, Rates 2014 [Member]

Rate Matters [Abstract]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 192,700

Public Utilities, Interim Rate Increase (Decrease), Amount

$ 127,000

Public Utilities, Approved Rate Increase (Decrease), Amount

58,900

Public Utilities, Approved adjustment to requested rate increase (decrease) related to an increase to sales forecast

(37,500)

Public Utilities, Approved adjustment to requested rate increase (decrease) related to a lower return on equity

(31,900)

Public Utilities; Approved adjustment to requested rate increase (decrease) related to Monticello EPU costs

(37,600)

Public Utilities, Approved adjustment to requested rate increase (decrease) related to property taxes

(13,200)

Public Utilities, Approved adjustment to requested rate increase (decrease) related to amortization of Prairie Island EPU costs

(5,000)

Public Utilities, Approved adjustment to requested rate increase (decrease) related to health care, pension and other benefits

(3,100)

Public Utilities, Approved adjustment to requested rate increase (decrease) related to other costs

(5,500)

NSP-Minnesota | Minnesota Public Utilities Commission [Member] | Electric Rate Case 2014, Rates 2015 [Member]

Rate Matters [Abstract]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 98,500

Public Utilities, Approved Rate Increase (Decrease), Amount

125,200

Public Utilities; Approved adjustment to requested rate increase (decrease) related to Monticello EPU costs

35,400

Public Utilities, Approved adjustment to requested rate increase (decrease) related to property taxes

(3,300)

Public Utilities, Approved adjustment to requested rate increase (decrease) related to other costs

(2,300)

Public Utilities, Approved adjustment to requested rate increase (decrease) related to depreciation expense

(500)

Public Utilities, Approved adjustment to requested rate increase (decrease) related to PTCs moving to base rates

(11,100)

Public Utilities, Approved adjustment to requested rate increase (decrease) related to DOE settlement proceeds

10,100

Public Utilities, Approved adjustment to requested rate increase (decrease) related to emission chemicals

$ (1,600)

NSP-Minnesota | Minnesota Public Utilities Commission [Member] | Nuclear Project Prudency Investigation [Member]

Rate Matters [Abstract]

Public Utilities, Amount of recoverable investment, with return

$ 415,000

Amount of recoverable investment, without a return

$ 333,000

Public Utilities, Percentage of investment considered used and useful

50.00%

NSP-Minnesota | South Dakota Public Utilities Commission [Member] | Electric Rate Case 2015 [Member]

Rate Matters [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 6,900

Public Utilities, Approved Rate Increase (Decrease), Percentage

3.60%

Public Utilities, Approved Increase (Decrease) to Rider Revenue, Amount

$ 900

Public Utilities, Approved Overall Revenue Increase (Decrease), Amount

$ 7,800

Percentage of excess earnings to be refunded due to earnings test

50.00%

NSP-Minnesota | South Dakota Public Utilities Commission [Member] | South Dakota Public Utilities Commission [Member]

Rate Matters [Abstract]

Public Utilities, Approved Overall Revenue Increase (Decrease), Percent

4.00%

NSP-Minnesota | Federal Energy Regulatory Commission (FERC) [Member] | FERC Proceeding, MISO ROE Complaint [Member]

Rate Matters [Abstract]

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

2

Public Utilities, Incremental ROE basis point increase (decrease) recommended by third parties

50

NSP-Minnesota | FERC Staff [Member] | FERC Proceeding, MISO ROE Complaint [Member]

Rate Matters [Abstract]

Public Utilities, ROE applicable to transmission formula rates in the MISO region, recommended by third parties

8.68%

NSP-Minnesota | MISO TOs [Member] | FERC Proceeding, MISO ROE Complaint [Member]

Rate Matters [Abstract]

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

10.80%

Minimum | NSP-Minnesota | Nuclear Project Prudency Investigation [Member]

Rate Matters [Abstract]

Facility generating capacity (in MW) | MW

600

Minimum | NSP-Minnesota | FERC Proceeding, MISO ROE Complaint [Member]

Rate Matters [Abstract]

Public Utilities, Increase (decrease) in transmission revenue, net of expense, due to the new ROE methodology

(7,000)

Maximum | NSP-Minnesota | Nuclear Project Prudency Investigation [Member]

Rate Matters [Abstract]

Facility generating capacity (in MW) | MW

671

Maximum | NSP-Minnesota | FERC Proceeding, MISO ROE Complaint [Member]

Rate Matters [Abstract]

Public Utilities, Increase (decrease) in transmission revenue, net of expense, due to the new ROE methodology

$ (9,000)

Subsequent Event | NSP-Minnesota | Minnesota Public Utilities Commission [Member] | 2014 Electric Rate Case [Member]

Rate Matters [Abstract]

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 149,400

Public Utilities, Approved Rate Increase (Decrease), Percentage

5.30%

Public Utilities, Approved adjustment to requested rate increase (decrease) related to Monticello EPU used-and-useful date

$ (13,800)

Estimated revenue impact

145,800

Public Utilities, Estimated increase (decrease) to interim rate refund obligation related to change in interest rate and other items

(6,000)

Subsequent Event | NSP-Minnesota | Minnesota Public Utilities Commission [Member] | Electric Rate Case 2014, Rates 2014 [Member]

Rate Matters [Abstract]

Public Utilities, Approved adjustment to requested rate increase (decrease) related to property taxes

(3,100)

Subsequent Event | NSP-Minnesota | Minnesota Public Utilities Commission [Member] | Electric Rate Case 2014, Rates 2015 [Member]

Rate Matters [Abstract]

Public Utilities, Approved adjustment to requested rate increase (decrease) related to Monticello EPU used-and-useful date

(13,800)

Public Utilities, Approved adjustment to requested rate increase (decrease) related to other costs

200

Public Utilities, Increase (decrease) to revenue impact related to interim rate effective date

$ (3,600)

Commitments and Contingencies,

Commitments and Contingencies, Purchased Power Agreements (Details) - MW	3 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Independent Power Producing Entities
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	1,069	1,069
Purchase Power Agreement Duration, Maximum (year)	2,028	2,028
Payment or Performance Guarantee
Purchased Power Agreements [Abstract]
Lease Guarantee Expiration (year)	2,019	2,019

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies, Guarantees and Indemnifications (Details) - Payment or Performance Guarantee - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Guarantor Obligations [Line Items]
Lease Guarantee Expiration (year)	2,019	2,019
Guarantees issued and outstanding	$ 4.8	$ 4.8

Commitments and Contingencies39

Commitments and Contingencies, Environmental Contingencies (Details) $ in Millions	1 Months Ended		6 Months Ended
	Jul. 31, 2015	Apr. 30, 2012MW	Jun. 30, 2015USD ($)	May. 31, 2015Parties	Dec. 31, 2014USD ($)	Apr. 30, 2014Issue
Cross-State Air Pollution Rule
Environmental Requirements [Abstract]
Number of issues on which the D.C. Circuit overturned the CSAPR | Issue						2
Electric Generating Unit Mercury and Air Toxics Standards Rule [Member]
Environmental Requirements [Abstract]
Generating capacity (in MW) | MW		25
Number of years before affected facilities must demonstrate compliance, low end of range		3 years
Number of years before affected facilities must demonstrate compliance, high end of range		4 years
Regional Haze Rules
Environmental Requirements [Abstract]
Amount spent on installation of emission controls					$ 46.9
Reasonably Attributable Visibility Impairment [Member]
Environmental Requirements [Abstract]
Number of environmental advocacy organizations who filed a settlement agreement in the Minnesota District Court with NSP-Minnesota and the EPA | Parties				6
Implementation of the National Ambient Air Quality Standard for sulfur dioxide [Member]
Environmental Requirements [Abstract]
Number of phases under a consent decree which the EPA is requiring states to evaluate areas for attainment			3
Number of months in which the state would have to submit an implementation plan for the respective nonattainment areas			18 months
Number of years for the state to achieve the designated attainment standard			5 years
Subsequent Event | Reasonably Attributable Visibility Impairment [Member]
Environmental Requirements [Abstract]
Number of months the EPA has to recommend and adopt a rule which will set the agreed-upon sulfur dioxide emissions	7 months
Fargo MGP Site [Member]
Environmental Requirements [Abstract]
Liability for estimated cost of remediating MGP site			$ 2.1

Commitments and Contingencies40

Commitments and Contingencies, Legal Contingencies (Details) - NSP-Minnesota - USD ($)	May. 15, 2015	Dec. 31, 2014	Jul. 31, 2011	Sep. 30, 2007	Jun. 30, 2015
Fibrominn Fuel Handling Dispute
Legal Contingencies [Abstract]
Minimum amount of damages claimed by plaintiff					$ 20,000,000
Accrual for legal contingency					0
Nuclear Waste Disposal Litigation
Legal Contingencies [Abstract]
Damages awarded				$ 116,500,000
Cash payment received under settlement agreement		$ 32,800,000	$ 100,000,000		214,700,000
Storage costs for spent nuclear fuel					$ 100,000,000
Litigation Settlement, Amount of Claim	$ 13,400,000

Borrowings and Other Financin41

Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Short-term Debt [Line Items]
Amount outstanding at period end	$ 117,000	$ 142,000
Money Pool
Short-term Debt [Line Items]
Borrowing limit	250,000	250,000
Amount outstanding at period end	0	0
Average amount outstanding	6,000	12,000
Maximum amount outstanding	$ 50,000	$ 150,000
Weighted average interest rate, computed on a daily basis (percentage)	0.54%	0.21%
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	$ 500,000	$ 500,000
Amount outstanding at period end	117,000	142,000
Average amount outstanding	95,000	111,000
Maximum amount outstanding	$ 208,000	$ 397,000
Weighted average interest rate, computed on a daily basis (percentage)	0.41%	0.26%
Weighted average interest rate at period end (percentage)	0.42%	0.53%

Borrowings and Other Financin42

Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Short-term debt	$ 117,000	$ 142,000
Letter of Credit
Line of Credit Facility [Line Items]
Short-term debt	$ 26,500	$ 24,100
Letter of Credit | Letter of Credit
Line of Credit Facility [Line Items]
Term of letters of credit (in years)	1 year

Borrowings and Other Financin43

Borrowings and Other Financing Instruments, Credit Facility (Details) - Credit Facility	Jun. 30, 2015USD ($)
Line of Credit Facility [Line Items]
Credit Facility	$ 500,000,000
Drawn	144,000,000
Available	356,000,000
Direct advances on the credit facility outstanding	$ 0

Fair Value of Financial Asset44

Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities (Details)	6 Months Ended
	Jun. 30, 2015
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 Asset45

Fair Value of Financial Assets and Liabilities, Cost and Fair Value of Nuclear Decommissioning Fund (Details) - USD ($) $ in Thousands	Jun. 30, 2015		Dec. 31, 2014
Available-for-sale Securities [Abstract]
Unrealized gains for the nuclear decommissioning fund	$ 335,300		$ 312,100
Unrealized losses and other than temporary impairments for the nuclear decommissioning fund	31,400		74,100
Investments [Abstract]
Miscellaneous investments	32,500		31,400
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	12,446		24,184
Available-for-sale Securities [Abstract]
Available-for-sale Securities	1,448,239		1,465,922
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Commingled funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities	451,398		470,013
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | International equity funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities	123,123		80,454
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Private equity investments
Available-for-sale Securities [Abstract]
Available-for-sale Securities	95,067		73,936
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Real estate
Available-for-sale Securities [Abstract]
Available-for-sale Securities	49,369		43,859
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Government securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	24,408		30,674
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	69,194		81,463
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	16,506		16,950
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Municipal bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	209,103		242,282
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	2,831		9,131
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	12,039		23,225
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Common stock
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Equity Securities	382,755		369,751
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	12,446		24,184
Available-for-sale Securities [Abstract]
Available-for-sale Securities	1,752,129	[1]	1,703,921	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Commingled funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities	499,782		465,615
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | International equity funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities	121,502		78,721
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Private equity investments
Available-for-sale Securities [Abstract]
Available-for-sale Securities	133,993		101,237
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Real estate
Available-for-sale Securities [Abstract]
Available-for-sale Securities	70,834		64,249
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	22,183		28,808
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	66,096		77,562
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	16,294		16,341
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	210,898		249,201
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	2,851		9,250
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	12,219		23,895
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	583,031		564,858
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	12,446		24,184
Available-for-sale Securities [Abstract]
Available-for-sale Securities	595,477		589,042
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		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		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	583,031		564,858
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	951,825		949,393
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	499,782		465,615
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	121,502		78,721
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	22,183		28,808
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	66,096		77,562
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	16,294		16,341
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	210,898		249,201
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	2,851		9,250
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	12,219		23,895
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	204,827		165,486
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	133,993		101,237
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	70,834		64,249
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		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		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 $32.5 million of miscellaneous investments.
[2]	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $31.4 million of miscellaneous investments.

Fair Value of Financial Asset46

Fair Value of Financial Assets and Liabilities, Changes in Level 3 Nuclear Decommissioning Fund (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward]
Balance at beginning of period		$ 181,393	$ 136,755	$ 165,486	$ 120,064
Purchases		13,020	2,381	29,263	14,809
Settlements		(1,241)	0	(2,622)	0
Gains recognized as regulatory assets	[1]	11,655	7,645	12,700	11,908
Balance at end of period		204,827	146,781	204,827	146,781
Private equity investments
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward]
Balance at beginning of period		113,619	73,801	101,237	62,696
Purchases		8,749	2,184	21,131	10,953
Settlements		0	0	0	0
Gains recognized as regulatory assets	[1]	11,625	5,138	11,625	7,474
Balance at end of period		133,993	81,123	133,993	81,123
Real estate
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward]
Balance at beginning of period		67,774	62,954	64,249	57,368
Purchases		4,271	197	8,132	3,856
Settlements		(1,241)	0	(2,622)	0
Gains recognized as regulatory assets	[1]	30	2,507	1,075	4,434
Balance at end of period		$ 70,834	$ 65,658	$ 70,834	$ 65,658
[1]	Gains are deferred as a component of the regulatory assets for nuclear decommissioning.

Fair Value of Financial Asset47

Fair Value of Financial Assets and Liabilities, Final Contractual Maturity Dates of Debt Securities in Nuclear Decommissioning Fund (Details) $ in Thousands	Jun. 30, 2015USD ($)
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	$ 361
Due in 1 to 5 Years	51,062
Due in 5 to 10 Years	109,494
Due after 10 Years	169,624
Total	330,541
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	22,183
Total	22,183
U.S. corporate bonds
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	0
Due in 1 to 5 Years	14,684
Due in 5 to 10 Years	54,005
Due after 10 Years	(2,593)
Total	66,096
International corporate bonds
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	0
Due in 1 to 5 Years	3,951
Due in 5 to 10 Years	11,325
Due after 10 Years	1,018
Total	16,294
Municipal bonds
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	361
Due in 1 to 5 Years	32,427
Due in 5 to 10 Years	41,313
Due after 10 Years	136,797
Total	210,898
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	2,851
Due after 10 Years	0
Total	2,851
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	12,219
Total	$ 12,219

Fair Value of Financial Asset48

Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) gal in Thousands, MWh in Thousands, MMBTU in Thousands, $ in Millions		Jun. 30, 2015USD ($)MMBTUMWhgalCounterparty	Dec. 31, 2014MMBTUMWhgal
Commodity Derivatives [Abstract]
Amount of accumulated other comprehensive gains (losses) related to commodity derivatives expected to be reclassified into earnings within the next twelve months		$ (0.1)
Credit Concentration Risk
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty		10
Credit Concentration Risk | External Credit Rating, Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty		5
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties		$ 24.3
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		31.00%
Credit Concentration Risk | 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 | Counterparty		5
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties		$ 14.7
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		19.00%
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]
Derivative, Nonmonetary Notional amount | MWh	[1],[2]	83,839	49,431
Natural Gas Commodity (in million British thermal units)
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract]
Derivative, Nonmonetary Notional amount | MMBTU	[1],[2]	942	173
Vehicle Fuel Commodity (in gallons)
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract]
Derivative, Nonmonetary Notional amount | gal	[1],[2]	116	155
[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 Asset49

Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($)		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015		Jun. 30, 2014
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
Designated as Hedging Instrument | 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		15,000	17,000	5,000		10,000
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		362,000	338,000	716,000		664,000
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
Designated as Hedging Instrument | 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	[1]	346,000	346,000	686,000		688,000
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
Designated as Hedging Instrument | 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		15,000	17,000	5,000		10,000
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	[2]	16,000	(8,000)	30,000		(24,000)
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
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		(3,461,000)	(16,840,000)	(12,205,000)		(4,040,000)
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)		(6,327,000)	(6,461,000)	(14,271,000)		(33,693,000)
Pre-tax gains (losses) recognized during the period in income		4,210,000	5,818,000	10,910,000		2,985,000
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	[3]	4,210,000	5,175,000	7,902,000		2,922,000
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		(3,517,000)	(16,347,000)	(12,223,000)		(11,448,000)
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)	[4]	(6,327,000)	(6,461,000)	(11,520,000)		(24,387,000)
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		56,000	(493,000)	18,000		7,408,000
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	(2,751,000)	[5]	(9,306,000)	[5]
Pre-tax gains (losses) recognized during the period in income		$ 0	0	$ 3,008,000	[5]	(580,000)	[5]
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			0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities			0			0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss			0			0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)			0			0
Pre-tax gains (losses) recognized during the period in income	[3]		$ 643,000			$ 643,000
[1]	Amounts are recorded to interest charges.
[2]	Amounts are recorded to operating and maintenance (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 Asset50

Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) - USD ($)	Jun. 30, 2015	Dec. 31, 2014
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

Fair Value of Financial Asset51

Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Thousands	Jun. 30, 2015		Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	$ 6,500		$ 6,600
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0		0
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	42,498		60,164
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	19,769		15,434
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	17,267		12,294
Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	127,202		135,036
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	42,018		51,648
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	12,671		15,818
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	29,291		35,539
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	56		291
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	18,267		13,466
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	18,267		13,466
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	58		65
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	3,153		65
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	3,095		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 | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	27		56
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	2,149		913
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	2,122		857
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 | 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 | 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 | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
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
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 | 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 | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
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 | Other Derivative Instruments
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 | 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	11,648		14,621
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	11,592		14,326
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	56		295
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	23,771		17,617
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	23,771		17,617
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	58		65
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	8,395		8,039
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	8,337		7,974
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 | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	27		56
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	13,880		6,946
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	13,853		6,890
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	37,749		41,783
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	7,927		4,732
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	29,822		37,051
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		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		0
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		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	2,386		1,512
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	1,855		0
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	531		1,512
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		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments
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 | 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 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	49,397		56,404
Fair Value Measured on a Recurring Basis | Fair Value | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	19,519		19,058
Fair Value Measured on a Recurring Basis | Fair Value | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	29,822		37,051
Fair Value Measured on a Recurring Basis | Fair Value | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	56		295
Fair Value Measured on a Recurring Basis | Fair Value | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	23,771		17,617
Fair Value Measured on a Recurring Basis | Fair Value | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	23,771		17,617
Fair Value Measured on a Recurring Basis | Fair Value | 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	58		65
Fair Value Measured on a Recurring Basis | Fair Value | Other Current Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	10,781		9,551
Fair Value Measured on a Recurring Basis | Fair Value | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	10,192		7,974
Fair Value Measured on a Recurring Basis | Fair Value | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	531		1,512
Fair Value Measured on a Recurring Basis | Fair Value | 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	27		56
Fair Value Measured on a Recurring Basis | Fair Value | Other Noncurrent Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	13,880		6,946
Fair Value Measured on a Recurring Basis | Fair Value | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	13,853		6,890
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	(7,379)	[1]	(4,756)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	(6,848)	[1]	(3,240)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	(531)	[1]	(1,512)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	[1]	(4)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	(5,504)	[1]	(4,151)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	(5,504)	[1]	(4,151)	[2]
Fair Value Measured on a Recurring Basis | 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	0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(7,628)	[1]	(9,486)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(7,097)	[1]	(7,974)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(531)	[1]	(1,512)	[2]
Fair Value Measured on a Recurring Basis | 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]	0	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(11,731)	[1]	(6,033)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(11,731)	[1]	(6,033)	[2]
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	480	[3]	8,516	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,502	[3]	1,968	[4]
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	14,114	[3]	12,229	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 125,053	[3]	$ 134,123	[4]
[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 June 30, 2015. At June 30, 2015, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $6.5 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, 2014. At Dec. 31, 2014, derivative assets and liabilities include no obligations to return cash collateral and the rights to reclaim cash collateral of $6.6 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.
[4]	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.

Fair Value of Financial Asset52

Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) - Commodity Contract - USD ($)		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period		$ 10,972,000	$ 18,426,000	$ 40,271,000	$ 31,727,000
Purchases		40,162,000	81,689,000	41,025,000	81,689,000
Settlements		(7,294,000)	(20,056,000)	(18,845,000)	(72,764,000)
Transfers out of Level 3		0	0	0	0
Gains recognized in earnings	[1]	1,220,000	6,438,000	1,280,000	7,437,000
(Losses) gains recognized as regulatory assets and liabilities		(9,697,000)	(15,045,000)	(28,368,000)	23,363,000
Balance at end of period		35,363,000	71,452,000	35,363,000	71,452,000
Transfers into Level 3		$ 0	$ 0	$ 0	$ 0
[1]	These amounts relate to commodity derivatives held at the end of the period.

Fair Value of Financial Asset53

Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 4,189,083	$ 4,188,682
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 4,568,614	$ 4,803,735

Other (Expense) Income, Net (De

Other (Expense) Income, Net (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Other Income and Expenses [Abstract]
Interest income	$ 92	$ 1,045	$ 3,424	$ 3,754
Other nonoperating income	60	38	92	406
Insurance policy expense	(428)	(1,554)	(1,831)	(2,627)
Other (expense) income, net	$ (276)	$ (471)	$ 1,685	$ 1,533

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2015		Jun. 30, 2014		Jun. 30, 2015		Jun. 30, 2014
Segment Reporting Information [Line Items]
Operating revenues	$ 1,081,974		$ 1,124,759		$ 2,374,456		$ 2,549,085
Net income (loss)	74,181		75,266		81,105		183,630
Affiliate electric revenue	117,830		116,518		242,705		238,323
Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	1,000,125		1,001,109		2,006,412		2,069,613
Net income (loss)	90,697		70,811		61,098	[1]	149,066
Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	75,345		116,601		355,222		466,409
Net income (loss)	(16,422)		41		23,850		27,100
All Other
Segment Reporting Information [Line Items]
Operating revenues	6,863		7,521		13,724		13,975
Net income (loss)	(94)		4,414		(3,843)		7,464
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	1,081,974	[2],[3]	1,124,759	[2],[3]	2,374,456	[4],[5]	2,549,085	[1],[4]
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	999,872	[2]	1,000,857	[2]	2,006,026	[4]	2,069,197	[4]
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	75,239		116,381		354,706		465,913
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues	6,863	[3]	7,521	[3]	13,724	[5]	13,975	[3]
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues	(359)		(472)		(902)		(912)
Net income (loss)	0		0		0		0
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	253		252		386		416
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	106		220		516		496
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Operating revenues	$ 0		$ 0		$ 0		$ 0
[1]	Includes a net of tax charge related to the Monticello LCM/EPU project. See Note 5.
[2]	Operating revenues include $118 million and $117 million of affiliate electric revenue for the three months ended June 30, 2015 and 2014, respectively.
[3]	Operating revenues include an immaterial amount of affiliate gas revenue for the three months ended June 30, 2015 and 2014, respectively.
[4]	Operating revenues include $243 million and $238 million of affiliate electric revenue for the six months ended June 30, 2015 and 2014, respectively.
[5]	Operating revenues include an immaterial amount of affiliate gas revenue for the six months ended June 30, 2015 and 2014, respectively.

Benefit Plans and Other Postr56

Benefit Plans and Other Postretirement Benefits (Details) $ in Thousands	1 Months Ended	3 Months Ended		6 Months Ended
	Jan. 31, 2015USD ($)Plan	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)
Pension Benefits
Components of Net Periodic Benefit Cost [Abstract]
Service cost		$ 7,889	$ 7,425	$ 15,778	$ 14,850
Interest cost		10,803	11,827	21,607	23,654
Expected return on plan assets		(15,707)	(15,730)	(31,415)	(31,460)
Amortization of prior service cost (credit)		234	234	468	468
Amortization of net loss		11,548	11,196	23,096	22,392
Net periodic benefit cost		14,767	14,952	29,534	29,904
Costs not recognized due to the effects of regulation		(7,843)	(7,312)	(15,685)	(15,071)
Net benefit cost (credit) recognized for financial reporting		6,924	7,640	13,849	14,833
Total contributions to the pension plans during the period	$ 32,700
Postretirement Health Care Benefits
Components of Net Periodic Benefit Cost [Abstract]
Service cost		40	46	80	93
Interest cost		953	1,249	1,907	2,497
Expected return on plan assets		(30)	(76)	(60)	(151)
Amortization of prior service cost (credit)		(759)	(759)	(1,518)	(1,518)
Amortization of net loss		523	854	1,046	1,708
Net periodic benefit cost		727	1,314	1,455	2,629
Costs not recognized due to the effects of regulation		0	0	0	0
Net benefit cost (credit) recognized for financial reporting		$ 727	$ 1,314	$ 1,455	$ 2,629
Xcel Energy Inc. | Pension Benefits
Components of Net Periodic Benefit Cost [Abstract]
Total contributions to the pension plans during the period	$ 90,000
Number of Xcel Energy's pension plans to which contributions were made | Plan	4

Other Comprehensive Income (Det

Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss) at beginning of period	$ (20,617)	$ (21,498)	$ (20,814)	$ (21,729)
Other comprehensive income (loss) before reclassifications	10	10	4	43
(Gains) losses reclassified from net accumulated other comprehensive loss	208	206	411	404
Net current period other comprehensive income (loss)	218	216	415	447
Accumulated other comprehensive income (loss) at end of period	(20,399)	(21,282)	(20,399)	(21,282)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operating and maintenance expenses	311,512	308,520	625,562	606,101
Total, pre-tax	(113,642)	(114,461)	(123,536)	(280,424)
Tax benefit	39,461	39,195	42,431	96,794
Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, net of tax	208	206	411	404
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	(19,707)	(20,420)	(19,909)	(20,609)
Other comprehensive income (loss) before reclassifications	9	10	2	6
(Gains) losses reclassified from net accumulated other comprehensive loss	214	200	423	393
Net current period other comprehensive income (loss)	223	210	425	399
Accumulated other comprehensive income (loss) at end of period	(19,484)	(20,210)	(19,484)	(20,210)
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	362	338	716	664
Tax benefit	(148)	(138)	(293)	(271)
Total, net of tax	214	200	423	393
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	346	346	686	688
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	16	(8)	30	(24)
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	106	110	105	73
Other comprehensive income (loss) before reclassifications	1	0	2	37
(Gains) losses reclassified from net accumulated other comprehensive loss	0	0	0	0
Net current period other comprehensive income (loss)	1	0	2	37
Accumulated other comprehensive income (loss) at end of period	107	110	107	110
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	(1,016)	(1,188)	(1,010)	(1,193)
Other comprehensive income (loss) before reclassifications	0	0	0	0
(Gains) losses reclassified from net accumulated other comprehensive loss	(6)	6	(12)	11
Net current period other comprehensive income (loss)	(6)	6	(12)	11
Accumulated other comprehensive income (loss) at end of period	(1,022)	(1,182)	(1,022)	(1,182)
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	40	58	77	116
Prior service credit	(48)	(48)	(99)	(97)
Total, pre-tax	(8)	10	(22)	19
Tax benefit	2	(4)	10	(8)
Total, net of tax	$ (6)	$ 6	$ (12)	$ 11