10-Q

F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2012

or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-31387

Northern States Power Company

(Exact name of registrant as specified in its charter)

Minnesota	41-1967505
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
414 Nicollet Mall
Minneapolis, Minnesota	55401
(Address of principal executive offices)	(Zip Code)

(612) 330-5500

 (Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  xYes  oNo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  xYes  oNo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o	Accelerated filer o
Non-accelerated filer x	Smaller reporting company o
(Do not check if smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  oYes  xNo

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class	Outstanding at Aug. 3, 2012
Common Stock, $0.01 par value	1,000,000 shares

Northern States Power Company (a Minnesota corporation) meets the conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H (2) to such Form 10-Q.

TABLE OF CONTENTS

PART I— FINANCIAL INFORMATION
Item l —	Financial Statements (Unaudited)	3
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 4 —	Controls and Procedures	33
PART II — OTHER INFORMATION
Item 1 —	Legal Proceedings	33
Item 1A —	Risk Factors	33
Item 4 —	Mine Safety Disclosures	33
Item 5 —	Other Information	33
Item 6 —	Exhibits	34
SIGNATURES		35

Certifications Pursuant to Section 302	1
Certifications Pursuant to Section 906	1
Statement Pursuant to Private Litigation	1

This Form 10-Q is filed by Northern States Power Company, a Minnesota corporation (NSP-Minnesota).  NSP-Minnesota is a wholly owned subsidiary of Xcel Energy Inc.  Xcel Energy Inc. wholly owns the following subsidiaries: NSP-Minnesota; Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado, a Colorado corporation (PSCo); and Southwestern Public Service Company, a New Mexico corporation (SPS).  NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are also referred to collectively as utility subsidiaries.  Additional information on Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) is available on various filings with the Securities and Exchange Commission (SEC).

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PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended June 30						Six Months Ended June 30
	2012			2011			2012			2011
Operating revenues
Electric	$	908,050		$	908,070		$	1,782,434		$	1,812,207
Natural gas		59,069			96,922			255,583			380,648
Other		5,417			5,534			11,292			10,563
Total operating revenues		972,536			1,010,526			2,049,309			2,203,418
Operating expenses
Electric fuel and purchased power		362,146			378,597			727,474			752,674
Cost of natural gas sold and transported		25,545			56,970			159,735			258,212
Cost of sales — other		2,972			2,865			6,089			5,791
Operating and maintenance expenses		271,611			261,626			532,641			516,840
Conservation program expenses		22,487			29,926			50,171			68,412
Depreciation and amortization		99,923			104,355			198,903			204,828
Taxes (other than income taxes)		48,374			40,334			102,142			85,987
Total operating expenses		833,058			874,673			1,777,155			1,892,744
Operating income		139,478			135,853			272,154			310,674
Other (expense) income, net		(882	)		(1,205	)		1,523			1,679
Allowance for funds used during construction — equity		9,179			10,146			17,214			19,739
Interest charges and financing costs
Interest charges — includes other financing costs of $1,476, $1,616, $2,953 and $3,042, respectively		52,282			52,313			104,402			103,928
Allowance for funds used during construction — debt		(4,937	)		(5,961	)		(9,215	)		(11,284	)
Total interest charges and financing costs		47,345			46,352			95,187			92,644
Income before income taxes		100,430			98,442			195,704			239,448
Income taxes		36,118			33,219			54,406			82,050
Net income	$	64,312		$	65,223		$	141,298		$	157,398

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended June 30						Six Months Ended June 30
	2012			2011			2012			2011
Net income	$	64,312		$	65,223		$	141,298		$	157,398
Other comprehensive (loss) income
Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $30, $24, $56 and $48, respectively		44			34			81			68
Derivative instruments:
Net fair value (decrease) increase, net of tax of $(11,680), $(6), $(3,163) and $72, respectively		(16,970	)		(8	)		(4,597	)		105
Reclassification of gains to net income, net of tax of $(23), $(32), $(45) and $(44), respectively		(34	)		(46	)		(67	)		(61	)
		(17,004	)		(54	)		(4,664	)		44
Marketable securities:
Net fair value increase, net of tax of $84, $0, $120 and $34, respectively		122			-			174			50
Other comprehensive (loss) income		(16,838	)		(20	)		(4,409	)		162
Comprehensive income	$	47,474		$	65,203		$	136,889		$	157,560

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Six Months Ended June 30
	2012			2011
Operating activities
Net income	$	141,298		$	157,398
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		201,290			207,493
Nuclear fuel amortization		49,765			43,732
Deferred income taxes		91,672			85,421
Amortization of investment tax credits		(1,351	)		(1,347	)
Allowance for equity funds used during construction		(17,214	)		(19,739	)
Net derivative gains		(626	)		(4,401	)
Changes in operating assets and liabilities:
Accounts receivable		(83,951	)		24,654
Accrued unbilled revenues		39,555			57,260
Inventories		57,811			47,168
Other current assets		(25,456	)		(538	)
Accounts payable		(62,066	)		46,431
Net regulatory assets and liabilities		(7,165	)		(8,480	)
Other current liabilities		(29,202	)		(10,792	)
Pension and other employee benefit obligations		(73,610	)		(43,484	)
Change in other noncurrent assets		(23,952	)		(2,586	)
Change in other noncurrent liabilities		(5,607	)		(26,893	)
Net cash provided by operating activities		251,191			551,297
Investing activities
Utility capital/construction expenditures		(469,026	)		(622,360	)
Proceeds from insurance recoveries		24,000			-
Merricourt refund		-			101,261
Merricourt deposit		-			(90,833	)
Allowance for equity funds used during construction		17,214			19,739
Purchases of investments in external decommissioning fund		(371,361	)		(1,226,490	)
Proceeds from the sale of investments in external decommissioning fund		371,361			1,226,504
Investments in utility money pool arrangement		-			(432,000	)
Repayments from utility money pool arrangement		-			432,000
Advances to affiliate		-			(111,300	)
Advances from affiliate		-			148,300
Change in restricted cash		94,959			-
Other, net		(1,333	)		(3,691	)
Net cash used in investing activities		(334,186	)		(558,870	)
Financing activities
(Repayments of) proceeds from short-term borrowings, net		(26,000	)		5,000
Borrowings under utility money pool arrangement		555,000			300
Repayments under utility money pool arrangement		(475,000	)		(300	)
Repayments of long-term debt, including reacquisition premiums		-			(30	)
Capital contributions from parent		145,621			125,000
Dividends paid to parent		(116,081	)		(116,007	)
Net cash provided by financing activities		83,540			13,963
Net change in cash and cash equivalents		545			6,390
Cash and cash equivalents at beginning of period		26,005			38,408
Cash and cash equivalents at end of period	$	26,550		$	44,798
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(96,391	)	$	(89,977	)
Cash paid for income taxes, net		(21,957	)		(4,211	)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	170,877		$	23,513

See Notes to Consolidated Financial Statements

5

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in thousands, except share and per share data)

	June 30, 2012			Dec. 31, 2011
Assets
Current assets
Cash and cash equivalents	$	26,550		$	26,005
Restricted cash		328			95,287
Accounts receivable, net		289,292			314,577
Accounts receivable from affiliates		30,751			18,033
Accrued unbilled revenues		191,748			231,303
Inventories		244,037			301,848
Regulatory assets		173,028			141,709
Derivative instruments		74,891			51,517
Prepayments and other		81,956			45,219
Total current assets		1,112,581			1,225,498
Property, plant and equipment, net		9,311,126			8,982,834
Other assets
Nuclear decommissioning fund and other investments		1,409,952			1,357,538
Regulatory assets		873,819			872,014
Derivative instruments		71,814			80,689
Other		59,576			36,638
Total other assets		2,415,161			2,346,879
Total assets	$	12,838,868		$	12,555,211
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	450,005		$	450,000
Short-term debt		-			26,000
Borrowings under utility money pool arrangement		145,000			65,000
Accounts payable		405,233			322,979
Accounts payable to affiliates		48,435			47,651
Regulatory liabilities		68,754			132,574
Taxes accrued		123,864			158,319
Accrued interest		66,565			68,362
Dividends payable to parent		59,022			58,054
Derivative instruments		60,659			65,781
Provision for rate refund		82,419			69,746
Other		76,761			94,990
Total current liabilities		1,586,717			1,559,456
Deferred credits and other liabilities
Deferred income taxes		1,784,589			1,666,005
Deferred investment tax credits		31,048			31,743
Regulatory liabilities		430,764			439,029
Asset retirement obligations		1,623,642			1,581,896
Derivative instruments		180,016			184,190
Pension and employee benefit obligations		339,861			413,755
Other		82,598			65,464
Total deferred credits and other liabilities		4,472,518			4,382,082
Commitments and contingencies
Capitalization
Long-term debt		2,889,396			2,888,897
Common stock – authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares outstanding at June 30, 2012 and Dec. 31, 2011, respectively		10			10
Additional paid in capital		2,512,012			2,366,391
Retained earnings		1,396,976			1,372,727
Accumulated other comprehensive loss		(18,761	)		(14,352	)
Total common stockholder's equity		3,890,237			3,724,776
Total liabilities and equity	$	12,838,868		$	12,555,211

See Notes to Consolidated Financial Statements

6

NSP-MINNESOTA AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

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, 2012 and Dec. 31, 2011; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 2012 and 2011; and its cash flows for the six months ended June 30, 2012 and 2011.  All adjustments are of a normal, recurring nature, except as otherwise disclosed.  Management has also evaluated the impact of events occurring after June 30, 2012 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, 2011 balance sheet information has been derived from the audited 2011 consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2011.  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, 2011, filed with the SEC on Feb. 27, 2012.  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.

1. 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, 2011, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2. Accounting Pronouncements

Recently Adopted

Fair Value Measurement — In May 2011, the Financial Accounting Standards Board (FASB) issued Fair Value Measurement (Topic 820) — Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (Accounting Standards Update (ASU) No. 2011-04), which provides clarifications regarding existing fair value measurement principles and disclosure requirements, and also specific new guidance for items such as measurement of instruments classified within stockholders’ equity.  These requirements were effective for interim and annual periods beginning after Dec. 15, 2011.  NSP-Minnesota implemented the accounting and disclosure guidance effective Jan. 1, 2012, and the implementation did not have a material impact on its consolidated financial statements.  For required fair value measurement disclosures, see Note 8.

Comprehensive Income — In June 2011, the FASB issued Comprehensive Income (Topic 220) — Presentation of Comprehensive Income (ASU No. 2011-05), which requires the presentation of the components of net income, the components of other comprehensive income (OCI) and total comprehensive income in either a single continuous financial statement of comprehensive income or in two separate, but consecutive financial statements of net income and comprehensive income.  These updates do not affect the items reported in OCI or the guidance for reclassifying such items to net income.  These requirements were effective for interim and annual periods beginning after Dec. 15, 2011.  NSP-Minnesota implemented the financial statement presentation guidance effective Jan. 1, 2012.

Recently Issued

Balance Sheet Offsetting — In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements.  These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets, and are effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods.  NSP-Minnesota does not expect the implementation of this disclosure guidance to have a material impact on its consolidated financial statements.

7

3.  Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2012			Dec. 31, 2011
Accounts receivable, net
Accounts receivable	$	309,043		$	337,581
Less allowance for bad debts		(19,751	)		(23,004	)
	$	289,292		$	314,577
Inventories
Materials and supplies	$	130,458		$	124,961
Fuel		89,030			113,711
Natural gas		24,549			63,176
	$	244,037		$	301,848
Property, plant and equipment, net
Electric plant	$	12,026,539		$	11,948,041
Natural gas plant		1,010,389			1,006,163
Common and other property		465,887			525,139
Construction work in progress		874,927			639,246
Total property, plant and equipment		14,377,742			14,118,589
Less accumulated depreciation		(5,462,566	)		(5,433,106	)
Nuclear fuel		2,087,663			1,939,299
Less accumulated amortization		(1,691,713	)		(1,641,948	)
	$	9,311,126		$	8,982,834

4. Income Taxes

Except to the extent noted below, the circumstances set forth in Note 6 to the consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2011 appropriately represent, 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 2007 federal income tax return expired in September 2011.  The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expires in September 2012.As of June 30, 2012, there was no federal income tax audit in progress.

State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns.  As of June 30, 2012, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2008.  As of June 30, 2012, there were 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, 2012		Dec. 31, 2011
Unrecognized tax benefit — Permanent tax positions	$	3.3	$	3.3
Unrecognized tax benefit — Temporary tax positions		12.6		13.4
Unrecognized tax benefit balance	$	15.9	$	16.7

8

The unrecognized tax benefit balance was 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, 2012			Dec. 31, 2011
NOL and tax credit carryforwards	$	(17.2	)	$	(18.1	)

It is reasonably possible that NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the Internal Revenue Service and state audits resume.  At this time, due to the uncertain nature of the audit process, an overall range of possible change cannot be reasonably estimated.

The payable for interest related to unrecognized tax benefits is offset by the interest benefit associated with NOL and tax credit carryforwards.  The receivable and payable for interest related to unrecognized tax benefits at June 30, 2012 and Dec. 31, 2011, respectively, were not material.  No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2012 or Dec. 31, 2011.

Federal Tax Loss Carryback Claims — NSP-Minnesota completed an analysis in the first quarter of 2012 on the eligibility of certain expenses that qualified for an extended carryback beyond the typical two-year carryback period.  As a result of a higher tax rate in prior years, NSP-Minnesota recognized a discrete tax benefit of approximately $15 million in the first quarter of 2012.

5.  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, 2011 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Recently Concluded Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)

Minnesota Electric Rate Case— In November 2010, NSP-Minnesota filed a request with the MPUC to increase electric rates in Minnesota for 2011 by approximately $150 million, or an increase of 5.62 percent, and an additional increase of $48.3 million, or 1.81 percent, in 2012.  The rate filing was based on a 2011 forecast test year, a requested return on equity (ROE) of 11.25 percent, an electric rate base of $5.6 billion and an equity ratio of 52.56 percent.  The MPUC approved an interim rate increase of $123 million, subject to refund, effective Jan. 2, 2011.  In August 2011, NSP-Minnesota submitted supplemental testimony, revising its requested rate increase to approximately $122 million for 2011 and an additional increase of approximately $29 million in 2012.

In November 2011, NSP-Minnesota reached a settlement agreement with certain customer intervenors.  In February 2012, NSP-Minnesota filed to reduce the interim rate request to $72.8 million to align with the settlement agreement.  In March 2012, the MPUC approved the settlement.  In May 2012, the MPUC issued an order approving the following:

· A rate increase of approximately $58 million in 2011 and an incremental rate increase of $14.8 million in 2012 based on an ROE of 10.37 percent and an equity ratio of 52.56 percent.

· A reduction to depreciation expense and NSP-Minnesota’s rate request by $30 million.

As of June 30, 2012 and Dec. 31, 2011, NSP-Minnesota recorded a provision for revenue subject to refund of approximately $80 million and $67 million, respectively.

Minnesota Property Tax Deferral Request — In December 2011, NSP-Minnesota filed a request to defer incremental 2012 property taxes that would not be recovered in base rates, estimated to be approximately $24 million, or alternatively that a property tax rider be approved.  In June 2012, the MPUC denied NSP-Minnesota’s request for deferred accounting for incremental property taxes and also denied the request for a property tax rider.   There were no incremental 2012 property taxes deferred as a regulatory asset.

Recently Concluded Regulatory Proceedings — North Dakota Public Service Commission (NDPSC)

North Dakota Electric Rate Case — In December 2010, NSP-Minnesota filed a request with the NDPSC to increase 2011 electric rates in North Dakota by approximately $19.8 million, or an increase of 12 percent, and a step increase of $4.2 million, or 2.6 percent, in 2012.  The rate filing was based on a 2011 forecast test year and included a requested ROE of 11.25 percent, an electric rate base of approximately $328 million and an equity ratio of 52.56 percent.  The NDPSC approved an interim rate increase of approximately $17.4 million, subject to refund, effective Feb. 18, 2011.

9

In May 2011, NSP-Minnesota revised its rate request to approximately $18.0 million, or an increase of 11 percent, for 2011 and $2.4 million, or 1.4 percent, for the additional step increase in 2012.  In February 2012, the NDPSC approved the settlement agreement, which provided for a rate increase of $13.7 million in 2011 and an additional step increase of $2.0 million in 2012, based on a 10.4 percent ROE and black box settlement for all other issues.  To address 2012 sales coming in below forecast revenue projections, the settlement includes a true-up to 2012 non-fuel revenues plus the settlement rate increase.  NSP-Minnesota implemented final rates in May 2012 and issued refunds in June 2012.

Pending and Recently Concluded Regulatory Proceedings — South Dakota Public Utilities Commission (SDPUC)

South Dakota 2011 Electric Rate Case — In June 2011, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $14.6 million annually, effective in 2012.  The proposed increase included $0.7 million in revenues currently recovered through automatic recovery mechanisms.  The request was based on a 2010 historic test year adjusted for known and measurable changes, a requested ROE of 11 percent, a rate base of $323.4 million and an equity ratio of 52.48 percent.  On Jan. 2, 2012, interim rates of $12.7 million were implemented.  In June 2012, the SDPUC authorized a rate increase of approximately $8.0 million, based on an ROE of 9.25 percent, and an equity ratio of 53 percent.  On July 17, 2012, the SDPUC approved implementation of final rates on Aug. 1, 2012, with refunds to be issued in September 2012.

South Dakota 2012 Electric Rate Case—On June 29, 2012, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $19.4 million annually.  The request was based on a 2011 historic test year adjusted for certain known and measurable changes for 2012 and 2013, a requested ROE of 10.65 percent, an average rate base of $367.5 million, and an equity ratio of 52.89 percent.  A SDPUC decision is expected in late 2012 or early 2013.

6.  Commitments and Contingencies

Except as noted below and in Note 5 to the consolidated financial statements in this Quarterly Report on Form 10-Q, the circumstances set forth in Notes 10, 11 and 12 to the consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2011 appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to NSP-Minnesota’s financial position.

Purchased Power Agreements

Under certain purchased power agreements, NSP-Minnesota purchases power from independent power producing entities that own natural gas or biomass fueled power plants 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 purchased power agreements create a variable interest in the associated independent power producing entity.

NSP-Minnesota had approximately 1,064 megawatts (MW) of capacity under long-term purchased power agreements as of June 30, 2012 and Dec. 31, 2011 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 the year 2028.

Guarantees and Indemnifications

In connection with the acquisition of the 201 MW Nobles wind project in 2011, NSP-Minnesota agreed to indemnify the seller for losses arising out of a breach of certain representations and warranties.  NSP-Minnesota’s indemnification obligation is capped at $20 million, in the aggregate, at June 30, 2012 and Dec. 31, 2011.  The indemnification obligation expires in March 2013.  NSP-Minnesota has not recorded a liability related to this indemnity, and it had no assets held as collateral related to this agreement at June 30, 2012 or Dec. 31, 2011.

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Environmental Contingencies

Environmental Requirements

Greenhouse Gas (GHG) New Source Performance Standard Proposal (NSPS) and Emission Guideline for Existing Sources — In April 2012, the U.S. Environmental Protection Agency (EPA) proposed a GHG NSPS for newly constructed power plants.  The proposal requires that carbon dioxide (CO2) emission rates be equal to those achieved by a natural gas combined-cycle plant, even if the plant is coal-fired.  The EPA also proposed that NSPS not apply to modified or reconstructed existing power plants and noted that, pursuant to its general NSPS regulations, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program.  Xcel Energy submitted comments on the proposed GHG NSPS in June 2012.  It is not possible to evaluate the impact of this regulation until its final requirements are known.

The EPA also plans to propose GHG regulations applicable to emissions from existing power plants under the Clean Air Act (CAA).  It is not known when the EPA will propose new standards for existing sources.

Cross-State Air Pollution Rule (CSAPR) — In July 2011, the EPA issued its CSAPR to address long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO2) and nitrogen oxide (NOx) from utilities located in the eastern half of the United States, including Minnesota.  The CSAPR sets more stringent requirements than the proposed Clean Air Transport Rule.  The rule also creates an emissions trading program.

On Dec. 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a stay of the CSAPR, pending completion of judicial review.  Oral arguments in the case were held in April 2012 and it is anticipated the D.C. Circuit will rule on the challenges to the CSAPR during the summer of 2012.  It is not known at this time whether the CSAPR will be upheld, reversed or will require modifications pursuant to a future D.C. Circuit decision.

If the CSAPR is upheld and unmodified, NSP-Minnesota would likely utilize a combination of emissions reductions through upgrades to its existing SO2 control technology at Sherco Units 1 and 2, which is estimated to cost a total of $10 million through 2014, and system operating changes to Black Dog and Sherco Units 1 and 2.  Costs for the Sherco Units 1 and 2 SO2 control technology are discussed below in the regional haze rules as SO2 reductions are part of the compliance plan for both the CSAPR and the regional haze rules.  If available, NSP-Minnesota would also consider allowance purchases.  In addition, NSP-Minnesota has filed a petition for reconsideration with the EPA and a petition for review of the CSAPR with the D.C. Circuit seeking the allocation of additional emission allowances to NSP-Minnesota.  NSP-Minnesota contends that the EPA’s method of allocating allowances arbitrarily resulted in fewer allowances for its Riverside and High Bridge plants than should have been awarded to reflect their operations during the baseline period, which included coal-fired operations prior to their conversion to natural gas.  In April 2012, NSP-Minnesota appealed to the D.C. Circuit on a final rule that the EPA issued that made changes to certain allowance allocations under the CSAPR, seeking to secure additional allocations for its Riverside and High Bridge plants.  If successful, additional allowances would reduce NSP-Minnesota’s costs to comply with the CSAPR.  The D.C. Circuit held this appeal in abeyance until it issues its decision.

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective 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.  NSP-Minnesota believes these costs will be recoverable through regulatory mechanisms and does not expect a material impact on results of operations, financial position or cash flows.

Regional Haze Rules — In 2005, the EPA finalized amendments to its regional haze rules regarding provisions that require the installation and operation of emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the United States.  NSP-Minnesota generating facilities are subject to BART requirements.  Individual states were required to identify the facilities located in their states that will have to reduce SO2, NOx and PM emissions under BART and then set emissions limits for those facilities.

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In December 2009, the Minnesota Pollution Control Agency (MPCA) approved the regional haze state implementation plan (SIP), which has been submitted to the EPA for approval.  The MPCA selected the BART controls for Sherco Units 1 and 2 to improve visibility in the national parks.  The MPCA concluded Selective Catalytic Reduction (SCR) should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs.  The MPCA’s BART controls for Sherco Units 1 and 2 consist of combustion controls for NOx and scrubber upgrades for SO2.  The combustion controls have been installed on Sherco Units 1 and 2, and the scrubber upgrades are scheduled to be installed by 2015.  At this time, the estimated cost for meeting the BART, regional haze and other CAA requirements is approximately $50 million, of which $20 million has already been spent on projects to reduce NOx emissions on Sherco Units 1 and 2.  NSP-Minnesota anticipates that all costs associated with BART compliance will be fully recoverable through regulatory recovery mechanisms.

In June 2011, the EPA provided comments to the MPCA on the SIP, stating that the EPA’s preliminary review indicates that SCR controls should be added to Sherco Units 1 and 2.  The MPCA has since proposed that the CSAPR should be considered BART for EGUs and the EPA proposed that states be allowed to find that CSAPR compliance meets BART requirements for EGUs, and specifically that Minnesota’s proposal to find the CSAPR to meet BART requirements should be approved, if finalized by the state.

In April 2012, the MPCA approved a supplement to the 2009 regional haze SIP finding that the CSAPR meets BART for EGUs in Minnesota.  The supplement also made a source-specific BART determination for Sherco Units 1 and 2 that requires installation of the combustion controls for NOx and scrubber upgrades for SO2 by January 2015.  In May 2012, the EPA adopted a final rule that allows states to determine whether CSAPR compliance meets BART requirements.  In June 2012, the EPA issued its final approval of the Minnesota SIP for EGUs.

In addition to the regional haze rules identified in the EPA’s visibility program, and addressed in the MPCA’s SIP discussed above, there are other visibility rules related to a program called the Reasonably Attributable Visibility Impairment (RAVI) program.  In October 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 make its own determination as to whether Sherco Units 1 and 2 cause or contribute to RAVI and, if so, whether the level of controls required by the MPCA is appropriate.  The EPA plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the RAVI program.  It is not yet known when the EPA will publish a proposal under RAVI, or what that proposal will entail.  In May 2012, a notice of intent to sue was filed with the EPA by the following organizations: National Parks Conservation Association, Minnesota Center for Environmental Advocacy, Friends of the Boundary Waters Wilderness, Voyagers National Park Association, Fresh Energy and Sierra Club.  The notice advised the EPA of the parties’ intent to sue the EPA in 180 days to attempt to require the EPA to determine BART for the Sherco Units 1 and 2 under the RAVI program.  It is not yet known how the EPA intends to respond to this notice.

Revisions to National Ambient Air Quality Standards (NAAQS) for PM — In June 2012, the EPA proposed to lower the primary (health-based) NAAQS for annual average fine PM and to retain the current daily standard for fine PM.  In areas in which NSP-Minnesota operates power plants, current monitored air concentrations are below the range of the proposed annual primary standard.  The EPA also proposed to add a secondary (welfare-based) NAAQS to improve visibility, primarily in urban areas.  NSP-Minnesota expects the proposed visibility standard would likely be met where NSP-Minnesota operates power plants based on currently available information.  A final rule is expected in December 2012 and the EPA is expected to designate non-compliant locations by December 2014.  If such areas are identified, states would then study the sources of the nonattainment and make emission reduction plans to attain the standards.  It is not possible to evaluate the impact of this regulation further until its final requirements are known.

Legal Contingencies

Lawsuits and claims arise in the normal course of business.  Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition.  The ultimate outcome of these matters cannot presently be determined.  Accordingly, the ultimate resolution of these matters could have a material effect on NSP-Minnesota’s consolidated financial position, results of operations, and cash flows.

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Environmental Litigation

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In February 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U.S. District Court for the Northern District of California against Xcel Energy Inc., the parent company of NSP-Minnesota, and 23 other utility, oil, gas and coal companies.  Plaintiffs claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village.  Xcel Energy Inc. believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss in June 2008.  In October 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds.  In November 2009, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).  In November 2011, oral arguments were presented.  It is unknown when the Ninth Circuit will render a final opinion.  The amount of damages claimed by plaintiffs is unknown, but likely includes the cost of relocating the village of Kivalina.  Plaintiffs’ alleged relocation is estimated to cost between $95 million to $400 million.  While Xcel Energy Inc. believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it could potentially have a material impact on NSP-Minnesota’s consolidated results of operations, cash flows or financial position.  No accrual has been recorded for this matter.

Comer vs. Xcel Energy Inc. et al. — In May 2011, less than a year after their initial lawsuit was dismissed, plaintiffs in this purported class action lawsuit filed a second lawsuit against more than 85 utility, oil, chemical and coal companies in U.S. District Court in Mississippi.  The complaint alleges defendants’ CO2 emissions intensified the strength of Hurricane Katrina and increased the damage plaintiffs purportedly sustained to their property.  Plaintiffs base their claims on public and private nuisance, trespass and negligence.  Among the defendants named in the complaint are Xcel Energy Inc. and NSP-Minnesota.  The amount of damages claimed by plaintiffs is unknown.  The defendants, including Xcel Energy Inc., believe this lawsuit is without merit and filed a motion to dismiss the lawsuit.  In March 2012, the U.S. District Court granted this motion for dismissal.  In April 2012, plaintiffs appealed this decision to the U.S. Court of Appeals for the Fifth Circuit.While Xcel Energy Inc. believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it could potentially have a material impact on NSP-Minnesota’s consolidated results of operations, cash flows or financial position.  No accrual has been recorded for this matter.

Employment, Tort and Commercial Litigation

Merricourt Wind Project Litigation — In April 2011, NSP-Minnesota terminated its agreements with enXco Development Corporation (enXco) for the development of a 150 MW wind project in southeastern North Dakota.  NSP-Minnesota’s decision to terminate the agreements was based in large part on the adverse impact this project could have on endangered or threatened species protected by federal law and the uncertainty in cost and timing in mitigating this impact.  NSP-Minnesota also terminated the agreements due to enXco’s nonperformance of certain other conditions, including failure to obtain a Certificate of Site Compatibility and the failure to close on the contracts by an agreed upon date of March 31, 2011.  NSP-Minnesota recorded a $101 million deposit in the first quarter of 2011, which was collected in April 2011.  In May 2011, NSP-Minnesota filed a declaratory judgment action in U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreements and enXco also filed a separate lawsuit in the same court seeking, among other things, in excess of $240 million for an alleged breach of contract.  NSP-Minnesota believes enXco’s lawsuit is without merit and filed a motion to dismiss.  In September 2011, the U.S. District Court denied the motion to dismiss.  The trial is set to begin in late 2012 or early 2013.  While NSP-Minnesota believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it could potentially have a material impact on NSP-Minnesota’s consolidated results of operations, cash flows or financial position.  No accrual has been recorded for this matter.

7.  Borrowings and Other Financing Instruments

Commercial Paper — NSP-Minnesota meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility.  The following table presents commercial paper outstanding for NSP-Minnesota:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2012			Twelve Months Ended Dec. 31, 2011
Borrowing limit	$	500		$	500
Amount outstandingat period end		-			26
Average amount outstanding		52			7
Maximum amount outstanding		89			80
Weighted average interest rate, computed on a daily basis		0.41	%		0.34	%
Weighted average interest rate at period end		N/A			0.45

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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 amount exceeding available capacity under the credit agreement.  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, 2012, NSP-Minnesota had the following committed credit facility available (in millions of dollars):

Credit Facility		Drawn (a)		Available
$	500.0	$	8.7	$	491.3

(a) Includes outstanding letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility.  NSP-Minnesota had no direct advances on the credit facility outstanding at June 30, 2012 and Dec. 31, 2011.

Amended Credit Agreement —In July 2012, NSP-Minnesota entered into an amended five-year credit agreement with a syndicate of banks, replacing the previous four-year credit agreement. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with an improvement in pricing and an extension of maturity from March 2015 to July 2017. The Eurodollar borrowing margin on the line of credit was reduced from a range of 100 to 200 basis points per year, to a range of 87.5 to 175 basis points per year based on applicable long-term credit ratings. The commitment fees, calculated on the unused portion of the line of credit, were reduced from a range of 10 to 35 basis points per year, to a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.

NSP-Minnesota has the right to request an extension of the revolving termination date for two additional one-year periods, subject to majority bank group approval.

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, 2012 and Dec. 31, 2011, there were $8.7 million and $7.7 million of letters of credit outstanding under the credit facility, respectively.  An additional $1.1 million of letters of credit not issued under the credit facility were outstanding at June 30, 2012 and Dec. 31, 2011, respectively.  The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

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.  The following table presents money pool borrowings for NSP-Minnesota:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2012			Twelve Months Ended Dec. 31, 2011
Borrowing limit	$	250		$	250
Amount outstandingat period end		145			65
Average amount outstanding		50			17
Maximum amount outstanding		145			80
Weighted average interest rate, computed on a daily basis		0.34	%		0.34	%
Weighted average interest rate at period end		0.34			0.35

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8.  Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosuresprovides 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 discounted cash flow or option pricing 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.  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; 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 ability to redeem private equity and real estate investments, 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, except for asset-backed and mortgage-backed securities, for which the third party service may also consider additional, more subjective inputs.  Since the impact of the use of these less observable inputs can be significant to the valuation of asset-backed and mortgage-backed securities, fair value measurements for these instruments have been assigned a Level 3.  Inputs that may be considered in the valuation of asset-backed and mortgage-backed securities in conjunction with pricing of similar securities in active markets include the use of risk-based discounting and estimated prepayments in a discounted cash flow model.  When these additional inputs and models are utilized, increases in the risk-adjusted discount rates and decreases in the assumed principal prepayment rates each have the impact of reducing reported fair values for these instruments.

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.

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Electric commodity derivatives held by NSP-Minnesota include financial transmission rights (FTRs) purchased from Midwest Independent Transmission System Operator, Inc. (MISO).  FTRs purchased from MISO are financial instruments that entitle the holder to one year of 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 that energy congestion, which is caused by overall transmission load and other transmission constraints. 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.  Monthly FTR settlements are included in the fuel clause adjustment,  and therefore changes in the fair value of the yet to be settled portions of 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.

NSP-Minnesota continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts 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 commodity derivative liabilities, the impact of considering credit risk was immaterial to the fair value of commodity derivative assets and liabilities presented in the consolidated balance sheets.

Non-Derivative Instruments Fair Value Measurements

The Nuclear Regulatory Commission (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 nuclear generating plants.  The fund contains cash equivalents, debt securities, equity securities, and other investments — all classified as available-for-sale securities under the applicable accounting guidance.  NSP-Minnesota plans to reinvest proceeds from matured securities until decommissioning begins.

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 $109.8 million and $79.8 million at June 30, 2012 and Dec. 31, 2011, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $76.6 million and $87.5 million at June 30, 2012 and Dec. 31, 2011, respectively.

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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 investments at June 30, 2012 and Dec. 31, 2011:

	June 30, 2012
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	24,913	$	15,082	$	9,831	$	-	$	24,913
Commingled funds		375,222		-		372,487		-		372,487
International equity funds		65,712		-		62,469		-		62,469
Private equity investments		22,593		-		-		23,303		23,303
Real estate		28,536		-		-		32,721		32,721
Debt securities:
Government securities		118,378		-		119,376		-		119,376
U.S. corporate bonds		151,444		-		159,834		-		159,834
International corporate bonds		22,782		-		23,709		-		23,709
Municipal bonds		66,769		-		70,608		-		70,608
Asset-backed securities		7,057		-		-		7,068		7,068
Mortgage-backed securities		63,526		-		-		66,321		66,321
Equity securities:
Common stock		407,384		424,703		-		-		424,703
Total	$	1,354,316	$	439,785	$	818,314	$	129,413	$	1,387,512

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $22.4 million of miscellaneous investments.

	Dec. 31, 2011
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	26,123	$	7,103	$	19,020	$	-	$	26,123
Commingled funds		320,798		-		311,105		-		311,105
International equity funds		63,781		-		58,508		-		58,508
Private equity investments		9,203		-		-		9,203		9,203
Real estate		24,768		-		-		26,395		26,395
Debt securities:
Government securities		116,490		-		117,256		-		117,256
U.S. corporate bonds		187,083		-		193,516		-		193,516
International corporate bonds		35,198		-		35,804		-		35,804
Municipal bonds		60,469		-		64,731		-		64,731
Asset-backed securities		16,516		-		-		16,501		16,501
Mortgage-backed securities		75,627		-		-		78,664		78,664
Equity securities:
Common stock		408,122		398,625		-		-		398,625
Total	$	1,344,178	$	405,728	$	799,940	$	130,763	$	1,336,431

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $21.1 million of miscellaneous investments.

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The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three and six months ended June 30, 2012 and 2011:

(Thousands of Dollars)	April 1, 2012		Purchases		Settlements			Gains (Losses) Recognized as Regulatory Assets and Liabilities			June 30, 2012
Private equity investments	$	20,068	$	3,235	$	-		$	-		$	23,303
Real estate		27,905		2,271		-			2,545			32,721
Asset-backed securities		16,547		-		(9,458	)		(21	)		7,068
Mortgage-backed securities		68,671		7,414		(9,690	)		(74	)		66,321
Total	$	133,191	$	12,920	$	(19,148	)	$	2,450		$	129,413

(Thousands of Dollars)	April 1, 2011		Purchases		Settlements			Gains (Losses) Recognized as Regulatory Assets and Liabilities			June 30, 2011
Asset-backed securities	$	26,020	$	-	$	(5,206	)	$	190		$	21,004
Mortgage-backed securities		98,367		52,952		(88,584	)		(464	)		62,271
Total	$	124,387	$	52,952	$	(93,790	)	$	(274	)	$	83,275

(Thousands of Dollars)	Jan. 1, 2012		Purchases		Settlements			Gains (Losses) Recognized as Regulatory Assets and Liabilities			June 30, 2012
Private equity investments	$	9,203	$	13,390	$	-		$	710		$	23,303
Real estate		26,395		3,907		(1,766	)		4,185			32,721
Asset-backed securities		16,501		-		(9,459	)		26			7,068
Mortgage-backed securities		78,664		14,318		(26,418	)		(243	)		66,321
Total	$	130,763	$	31,615	$	(37,643	)	$	4,678		$	129,413

(Thousands of Dollars)	Jan. 1, 2011		Purchases		Settlements			Gains (Losses) Recognized as Regulatory Assets and Liabilities			June 30, 2011
Asset-backed securities	$	33,174	$	756	$	(13,116	)	$	190		$	21,004
Mortgage-backed securities		72,589		99,065		(108,457	)		(926	)		62,271
Total	$	105,763	$	99,821	$	(121,573	)	$	(736	)	$	83,275

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class at June 30, 2012:

	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	$	104,694	$	79	$	3,648	$	10,955	$	119,376
U.S. corporate bonds		-		40,032		103,834		15,968		159,834
International corporate bonds		-		6,481		17,228		-		23,709
Municipal bonds		-		-		27,692		42,916		70,608
Asset-backed securities		-		4,983		2,085		-		7,068
Mortgage-backed securities		-		-		877		65,444		66,321
Debt securities	$	104,694	$	51,575	$	155,364	$	135,283	$	446,916

18

Derivative Instruments Fair Value Measurements

NSP-Minnesota enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to reduce risk in connection with changes in interest rates, utility commodity prices, vehicle fuel prices, as well as variances in forecasted weather.

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, 2012, accumulated OCI related to interest rate derivatives included $0.1 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

At June 30, 2012, NSP-Minnesota had unsettled interest rate swaps outstanding with a total notional amount of $225 million.  These interest rate swaps were designated as hedges, and as such, changes in fair value are recorded to OCI.

Short-Term Wholesale and Commodity Trading Risk — NSP-Minnesota conducts various short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related products.  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 the 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, and vehicle fuel.

At June 30, 2012, NSP-Minnesota had vehicle fuel contracts designated as cash flow hedges extending through December 2014.  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 OCI 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, 2012 and 2011.

At June 30, 2012, accumulated OCI related to commodity derivative cash flow hedges included immaterial amounts of net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

Additionally, NSP-Minnesota enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers.  Changes in the fair value of these commodity derivatives are recorded in electric operating revenue, net of amounts credited to customers under margin-sharing mechanisms.

The following table details the gross notional amounts of commodity forwards, options, and FTRs at June 30, 2012 and Dec. 31, 2011:

(Amounts in Thousands) (a)(b)	June 30, 2012		Dec. 31, 2011
Megawatt hours (MWh) of electricity		60,527		37,522
MMBtu of natural gas		1,828		7,290
Gallons of vehicle fuel		275		330

(a) Amounts are not reflective of net positions in the underlying commodities.

(b) Notional amounts for options are also included on a gross basis, but are weighted for the probability of exercise.

19

The following tables detail the impact of derivative activity during the three and six months ended June 30, 2012 and 2011, on OCI, regulatory assets and liabilities, and income:

	Three Months Ended June 30, 2012
	Fair Value Gains (Losses)						Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:						into Income During the Period from:
	Accumulated						Accumulated						Pre-Tax Gains
	Other			Regulatory			Other			Regulatory			Recognized
	Comprehensive			(Assets) and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Loss			Liabilities			Loss			(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate	$	(28,532	)	$	-		$	(27	) (a)	$	-		$	-
Vehicle fuel and other commodity		(118	)		-			(30	) (e)		-			-
Total	$	(28,650	)	$	-		$	(57	)	$	-		$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-		$	-		$	1,588	(b)
Electric commodity		-			38,174			-			(9,714	) (c)		-
Natural gas commodity		-			96			-			-			-
Total	$	-		$	38,270		$	-		$	(9,714	)	$	1,588
	Six Months Ended June 30, 2012
	Fair Value Gains (Losses)						Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:						into Income During the Period from:
	Accumulated						Accumulated						Pre-Tax Gains
	Other			Regulatory			Other			Regulatory			Recognized
	Comprehensive			(Assets) and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Loss			Liabilities			Loss			(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate	$	(7,745	)	$	-		$	(54	) (a)	$	-		$	-
Vehicle fuel and other commodity		(15	)		-			(58	) (e)		-			-
Total	$	(7,760	)	$	-		$	(112	)	$	-		$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-		$	-		$	3,311	(b)
Electric commodity		-			39,756			-			(17,685	) (c)		-
Natural gas commodity		-			(2,564	)		-			16,158	(d)		-
Total	$	-		$	37,192		$	-		$	(1,527	)	$	3,311

20

	Three Months Ended June 30, 2011
	Fair Value Gains (Losses)						Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:						into Income During the Period from:
	Accumulated						Accumulated						Pre-Tax Gains
	Other			Regulatory			Other			Regulatory			Recognized
	Comprehensive			(Assets) and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Income			Liabilities			Income			(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate	$	-		$	-		$	(27	) (a)	$	-		$	-
Vehicle fuel and other commodity		(36	)		-			(33	) (e)		-			-
Total	$	(36	)	$	-		$	(60	)	$	-		$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-		$	-		$	1,320	(b)
Electric commodity		-			10,299			-			(8,666	) (c)		-
Natural gas commodity		-			(1,534	)		-			-			-
Total	$	-		$	8,765		$	-		$	(8,666	)	$	1,320
	Six Months Ended June 30, 2011
	Fair Value Gains (Losses)						Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:						into Income During the Period from:
	Accumulated						Accumulated						Pre-Tax Gains
	Other			Regulatory			Other			Regulatory			Recognized
	Comprehensive			(Assets) and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Income			Liabilities			Income			(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate	$	-		$	-		$	(54	) (a)	$	-		$	-
Vehicle fuel and other commodity		177			-			(55	) (e)		-			-
Total	$	177		$	-		$	(109	)	$	-		$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-		$	-		$	6,675	(b)
Electric commodity		-			19,145			-			(17,555	) (c)		-
Natural gas commodity		-			(3,553	)		-			10,928	(d)		-
Total	$	-		$	15,592		$	-		$	(6,627	)	$	6,675

(a) Recorded to interest charges.

(b) Recorded to electric operating revenues.  Portions of these gains and losses are shared with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

(c) 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.

(d) 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.

(e) Recorded to operating and maintenance (O&M) expenses.

21

NSP-Minnesota had no derivative instruments designated as fair value hedges during the three and six months ended June 30, 2012 and 2011.  Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Credit Related Contingent Features — Contract provisions of the derivative instruments that NSP-Minnesota enters into 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, 2012, contracts underlying $21.2 million of derivative instruments in a gross liability position would require NSP-Minnesota to post collateral or settle applicable contracts if the credit ratings of NSP-Minnesota are downgraded below investment grade, however, at June 30, 2012, these derivative liabilities were offset by derivative assets with the applicable counterparties, and therefore such a downgrade would not result in payments to these counterparties.  If the credit ratings of NSP-Minnesota were downgraded below investment grade, contracts underlying $1.4 million of derivative instruments in a gross liability position at Dec. 31, 2011 would have required NSP-Minnesota to post collateral or settle applicable contracts, which would have resulted in payments to counterparties of $0.1 million.  At June 30, 2012 and Dec. 31, 2011, there was no collateral posted on these specific contracts.

Certain of NSP-Minnesota’s 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, 2012 and Dec. 31, 2011.

Recurring Fair Value Measurements—The following table presents, for each of the hierarchy levels, NSP-Minnesota’s derivative assets and liabilities that are measured at fair value on a recurring basis at June 30, 2012:

	June 30, 2012
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	49	$	-	$	49	$	-		$	49
Other derivative instruments:
Trading commodity		79		25,408		-		25,487		(7,622	)		17,865
Electric commodity		-		-		35,664		35,664		(1,875	)		33,789
Natural gas commodity		-		98		-		98		(19	)		79
Total current derivative assets	$	79	$	25,555	$	35,664	$	61,298	$	(9,516	)		51,782
Purchased power agreements (a)													23,109
Current derivative instruments												$	74,891
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	32	$	-	$	32	$	(32	)	$	-
Other derivative instruments:
Trading commodity		-		31,482		-		31,482		(2,729	)		28,753
Total noncurrent derivative assets	$	-	$	31,514	$	-	$	31,514	$	(2,761	)		28,753
Purchased power agreements (a)													43,061
Noncurrent derivative instruments												$	71,814

22

	June 30, 2012
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate	$	-	$	35,864	$	-	$	35,864	$	-		$	35,864
Other derivative instruments:
Trading commodity		112		19,868		-		19,980		(9,036	)		10,944
Electric commodity		-		-		1,875		1,875		(1,875	)		-
Natural gas commodity		-		2		-		2		(2	)		-
Total current derivative liabilities	$	112	$	55,734	$	1,875	$	57,721	$	(10,913	)		46,808
Purchased power agreements (a)													13,851
Current derivative instruments												$	60,659
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	16,683	$	-	$	16,683	$	(2,761	)	$	13,922
Total noncurrent derivative liabilities	$	-	$	16,683	$	-	$	16,683	$	(2,761	)		13,922
Purchased power agreements (a)													166,094
Noncurrent derivative instruments												$	180,016

(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 purchased power agreements 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) The accounting guidance for derivatives and hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between NSP-Minnesota and a counterparty.  A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

The following tables present, for each of the hierarchy levels, NSP-Minnesota’s derivative assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2011:

	Dec. 31, 2011
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	93	$	-	$	93	$	-		$	93
Other derivative instruments:
Trading commodity		-		26,133		-		26,133		(9,679	)		16,454
Electric commodity		-		-		13,333		13,333		(1,471	)		11,862
Total current derivative assets	$	-	$	26,226	$	13,333	$	39,559	$	(11,150	)		28,409
Purchased power agreements (a)													23,108
Current derivative instruments												$	51,517
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	59	$	-	$	59	$	(59	)	$	-
Other derivative instruments:
Trading commodity		-		28,307		-		28,307		(2,234	)		26,073
Total noncurrent derivative assets	$	-	$	28,366	$	-	$	28,366	$	(2,293	)		26,073
Purchased power agreements (a)													54,616
Noncurrent derivative instruments												$	80,689

23

	Dec. 31, 2011
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate	$	-	$	28,119	$	-	$	28,119	$	-		$	28,119
Other derivative instruments:
Trading commodity		-		21,816		-		21,816		(11,647	)		10,169
Electric commodity		-		698		916		1,614		(1,471	)		143
Natural gas commodity		-		13,499		-		13,499		-			13,499
Total current derivative liabilities	$	-	$	64,132	$	916	$	65,048	$	(13,118	)		51,930
Purchased power agreements (a)													13,851
Current derivative instruments												$	65,781
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	13,464	$	-	$	13,464	$	(2,293	)	$	11,171
Total noncurrent derivative liabilities	$	-	$	13,464	$	-	$	13,464	$	(2,293	)		11,171
Purchased power agreements (a)													173,019
Noncurrent derivative instruments												$	184,190

(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 purchased power agreements 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) The accounting guidance for derivatives and hedgingpermits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between NSP-Minnesota and a counterparty.  A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

The following table presents the changes in Level 3 commodity derivatives for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30
(Thousands of Dollars)	2012			2011
Balance at April 1	$	5,324		$	2,332
Purchases		37,296			33,609
Settlements		(12,675	)		(8,211	)
Net transactions recorded during the period:
Gains recognized in earnings (a)		-			4
Gains (losses) recorded as regulatory assets and liabilities		3,844			(23,738	)
Balance at June 30	$	33,789		$	3,996
	Six Months Ended June 30
(Thousands of Dollars)	2012			2011
Balance at Jan. 1	$	12,417		$	2,392
Purchases		37,297			33,609
Settlements		(21,560	)		(16,001	)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a)		(9	)		72
Gains (losses) recorded as regulatory assets and liabilities		5,644			(16,076	)
Balance at June 30	$	33,789		$	3,996

(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 the three and six months ended June 30, 2012 and 2011.

24

Fair Value of Long-Term Debt

As of June 30, 2012 and Dec. 31, 2011, other financial instruments for which the carrying amount did not equal fair value were as follows:

	June 30, 2012				Dec. 31, 2011
	Carrying				Carrying
(Thousands of Dollars)	Amount		Fair Value		Amount		Fair Value
Long-term debt, including current portion	$	3,339,401	$	4,046,627	$	3,338,897	$	4,066,367

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, 2012 and Dec. 31, 2011, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.  These fair value estimates have not been comprehensively revalued for purposes of these consolidated financial statements since those dates and current estimates of fair values may differ significantly.

9.  Other Income (Expense), Net

Other income (expense), net consisted of the following:

	Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2012			2011			2012			2011
Interest (expense) income	$	(83	)	$	(126	)	$	3,756		$	2,953
Other nonoperating income		168			138			472			332
Insurance policy expense		(967	)		(1,217	)		(2,705	)		(1,606	)
Other (expense) income, net	$	(882	)	$	(1,205	)	$	1,523		$	1,679

10.  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 reportable segment.

NSP-Minnesota has the following reportable segments: regulated electric, regulated natural gas and all other.

· NSP-Minnesota’s regulated electric utility segment generates electricity which is transmitted and distributed in 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 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 continuing 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.

25

	Regulated		Regulated			All		Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas			Other		Eliminations			Total
Three Months Ended June 30, 2012
Operating revenues from external customers	$	908,050	$	59,069		$	5,417	$	-		$	972,536
Intersegment revenues		144		139			-		(283	)		-
Total revenues	$	908,194	$	59,208		$	5,417	$	(283	)	$	972,536
Net income (loss)	$	64,921	$	(2,811	)	$	2,202	$	-		$	64,312
Three Months Ended June 30, 2011
Operating revenues from external customers	$	908,070	$	96,922		$	5,534	$	-		$	1,010,526
Intersegment revenues		171		148			-		(319	)		-
Total revenues	$	908,241	$	97,070		$	5,534	$	(319	)	$	1,010,526
Net income	$	61,870	$	74		$	3,279	$	-		$	65,223
Six Months Ended June 30, 2012
Operating revenues from external customers	$	1,782,434	$	255,583		$	11,292	$	-		$	2,049,309
Intersegment revenues		267		380			-		(647	)		-
Total revenues	$	1,782,701	$	255,963		$	11,292	$	(647	)	$	2,049,309
Net income	$	124,202	$	11,486		$	5,610	$	-		$	141,298
Six Months Ended June 30, 2011
Operating revenues from external customers	$	1,812,207	$	380,648		$	10,563	$	-		$	2,203,418
Intersegment revenues		296		339			-		(635	)		-
Total revenues	$	1,812,503	$	380,987		$	10,563	$	(635	)	$	2,203,418
Net income	$	130,174	$	21,149		$	6,075	$	-		$	157,398

11.  Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three Months Ended June 30
	2012			2011			2012			2011
							Postretirement Health
(Thousands of Dollars)	Pension Benefits						Care Benefits
Service cost	$	7,336		$	8,015		$	24		$	23
Interest cost		12,301			13,043			1,814			1,911
Expected return on plan assets		(16,836	)		(18,528	)		(109	)		(144	)
Amortization of transition obligation		-			-			336			336
Amortization of prior service cost (credit)		2,955			3,293			(30	)		(30	)
Amortization of net loss		10,196			7,707			853			607
Net periodic benefit cost		15,952			13,530			2,888			2,703
Cost not recognized due to the effects of regulation		(9,083	)		(10,140	)		-			-
Net benefit cost recognized for financial reporting	$	6,869		$	3,390		$	2,888		$	2,703

26

	Six Months Ended June 30
	2012			2011			2012			2011
							Postretirement Health
(Thousands of Dollars)	Pension Benefits						Care Benefits
Service cost	$	14,706		$	14,008		$	48		$	44
Interest cost		24,610			25,973			3,565			3,686
Expected return on plan assets		(33,658	)		(37,121	)		(219	)		(288	)
Amortization of transition obligation		-			-			673			673
Amortization of prior service cost (credit)		5,910			6,585			(59	)		(59	)
Amortization of net loss		20,065			14,368			1,602			1,174
Net periodic benefit cost		31,633			23,813			5,610			5,230
Cost not recognized due to the effects of regulation		(17,141	)		(17,450	)		-			-
Net benefit cost recognized for financial reporting	$	14,492		$	6,363		$	5,610		$	5,230

In January 2012, contributions of $190.5 million were made across four of Xcel Energy’s pension plans, of which $79.3 million was attributable to NSP-Minnesota.  Xcel Energy does not expect additional pension contributions during 2012.

In June 2012, to manage volatility in equity pricing within the pension master trust, Xcel Energy entered into equity collar contracts with a net-zero cost at initiation on a portion of the equity securities.  The equity collar strategy is designed to reduce potential equity losses while limiting gains, resulting in lower equity volatility for the pension plans.  At June 30, 2012, the mark-to-market value of these arrangements was not material to the value of the pension trust assets.  These arrangements will expire in December 2012.

Item 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Discussion of financial condition and liquidity for NSP-Minnesota is omitted per conditions set forth in general instructions H (1) (a) and (b) of Form 10-Q for wholly owned subsidiaries.  It is replaced with management’s narrative analysis of the results of operations set forth in general instructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).

Financial Review

The following discussion and analysis by management focuses on those factors that had a material effect on NSP-Minnesota’s financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future.  It should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes to the consolidated financial statements.  Due to the seasonality of NSP-Minnesota’s electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results.

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Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions.  Actual results may vary materially.  Forward-looking statements speak only as of the date they are made and we do not undertake any obligation to update them to reflect changes that occur after that date.  Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of NSP-Minnesota and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where NSP-Minnesota has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by NSP-Minnesota and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions by regulatory bodies impacting NSP-Minnesota’s nuclear operations, including those affecting costs, operations or the approval of requests pending before the NRC; financial or regulatory accounting policies imposed by  regulatory bodies; availability or cost of capital; employee workforce factors; the items described under Factors Affecting Results of Operations; and the other risk factors listed from time to time by NSP-Minnesota in reports filed with the SEC, including “Risk Factors” in Item 1A of NSP-Minnesota’s Form 10-K for the year ended Dec. 31, 2011, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended June 30, 2012.

Results of Operations

NSP-Minnesota’s net income was approximately $141.3 million for the six months ended June 30, 2012, compared with approximately $157.4 million for the same period in 2011.The decrease is primarily due to the unfavorable impact of warmer than normal winter weather, higher property taxes, higher O&M expenses and sluggish electric sales, which were partially offset by the positive impact of summer weather and a lower effective tax rate.

Electric Revenues and Margins

Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuation in the price of natural gas, coal and uranium used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses, these price fluctuations have little impact on electric margin.  The following table details the electric revenues and margin:

	Six Months Ended June 30
(Millions of Dollars)	2012			2011
Electric revenues	$	1,782		$	1,812
Electric fuel and purchased power		(727	)		(753	)
Electric margin	$	1,055		$	1,059

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The following summarizes the components of the changes in electric revenues and margin for the six months ended June 30:

Electric Revenues

(Millions of Dollars)	2012 vs. 2011
Fuel and purchased power cost recovery	$	(16	)
Differences in Minnesota retail rates (2011 interim compared to 2012 settlement) (a)		(8	)
Conservation revenue (offset by expenses)		(7	)
Estimated impact of weather		(7	)
Trading		(6	)
Retail sales decrease (excluding weather impact)		(5	)
Transmission revenue		10
Retail rate increases (North Dakota and South Dakota)		5
Interchange agreement billing with NSP-Wisconsin		4
Total decrease in electric revenues	$	(30	)

(a) NSP-Minnesota reduced depreciation expense and revenues by approximately $16 million in the first half of 2012 to reflect the settlement in the Minnesota electric rate case.

Electric Margin

(Millions of Dollars)	2012 vs. 2011
Differences in Minnesota retail rates (2011 interim compared to 2012 settlement) (a)	$	(8	)
Conservation revenue (offset by expenses)		(7	)
Estimated impact of weather		(7	)
Retail sales decrease (excluding weather impact)		(5	)
Transmission revenue, net of costs		6
Interchange agreement billing with NSP-Wisconsin		6
Retail rate increases (North Dakota and South Dakota)		5
Other, net		6
Total decrease in electric margin	$	(4	)

(a) NSP-Minnesota reduced depreciation expense and revenues by approximately $16 million in the first half of 2012 to reflect the settlement in the Minnesota electric rate case.

Natural Gas Revenues and Margins

The cost of natural gas tends to vary with changing sales requirements and unit cost of natural gas purchases.  However, due to purchased natural gas cost recovery mechanisms for retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin.  The following table details natural gas revenues and margin:

	Six Months Ended June 30
(Millions of Dollars)	2012			2011
Natural gas revenues	$	256		$	381
Cost of natural gas sold and transported		(160	)		(258	)
Natural gas margin	$	96		$	123

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The following summarizes the components of the changes in natural gas revenues and margin for the six months ended June 30:

Natural Gas Revenues

(Millions of Dollars)	2012 vs. 2011
Purchased natural gas adjustment clause recovery	$	(98	)
Estimated impact of weather		(15	)
Conservation revenue (offset by expenses)		(11	)
Other, net		(1	)
Total decrease in natural gas revenues	$	(125	)

Natural Gas Margin

(Millions of Dollars)	2012 vs. 2011
Estimated impact of weather	$	(15	)
Conservation revenue (offset by expenses)		(11	)
Other, net		(1	)
Total decrease in natural gas margin	$	(27	)

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $15.8 million, or 3.1 percent, for the six months ended June 30, 2012, compared with the same period in 2011.  The following summarizes the components of the changes for the six months ended June 30:

(Millions of Dollars)	2012 vs. 2011
Higher employee benefit costs	$	8
Higher plant generation costs		6
Other, net (including management cost savings initiatives)		2
Total increase in O&M expenses	$	16

· Higher employee benefit costs are primarily due to higher pension expense.

· Higher plant generation costs related to increased labor costs for outages and overhauls in 2012.

Conservation Program Expenses — Conservation program expenses decreased $18.2 million, or 26.7 percent, for the six months ended June 30, 2012, compared with the same period in 2011.  The decrease is primarily attributable to a lower gas rider rate, as well as the timing of recovery of electric conservation improvement program expenses.  Conservation program expenses are generally recovered in major jurisdictions concurrently through riders and base rates.

Depreciation and Amortization — Depreciation and amortization expense decreased $5.9 million, or 2.9 percent, for the six months ended June 30, 2012, compared with the same period in 2011.  This decrease is primarily due to a change in depreciation lives for certain assets to reflect the settlement in the Minnesota and South Dakota electric rate cases, resulting in a reduction in depreciation expense of $16 million, partially offset by normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $16.2 million, or 18.8 percent, for the six months ended June 30, 2012, compared with the same period in 2011.  The increases are due to an increase in property taxes primarily in Minnesota.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC decreased $4.6 million, or 14.8 percent, for the six months ended June 30, 2012, compared with the same period in 2011.  The decrease is primarily due to construction projects related to the Monticello extended power uprate that went into service in 2011.

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Income Taxes —Income tax expense decreased $27.6 million for the first six months of 2012, compared with the same period in 2011.  The decrease in income tax expense was primarily due to lower pretax earnings and a tax benefit associated with a carryback.  The effective tax rate was 27.8 percent for the first six months of 2012, compared with 34.3 percent for the same period in 2011.  The lower effective tax rate for the first six months of 2012 was primarily due to the completion of an analysis in the first quarter of 2012 on the eligibility of certain expenses that qualified for an extended carryback beyond the typical two-year carryback period.  As a result, NSP-Minnesota recognized a discrete tax benefit of approximately $15 million.  Without this tax benefit, the effective tax rate for the first six months of 2012 would have been 35.5 percent.

Public Utility Regulation

NSP System Resource Plans — In December 2011, NSP-Minnesota filed an update to the 2011 through 2025 resource plan with the MPUC.  To account for slower projected economic growth and the loss of NSP-Wisconsin’s wholesale customers, NSP-Minnesota modified the current plan to include a recommendation to withdraw the Black Dog repowering project certificate of need (CON) and to reassess the wind procurement plan and resource contingency plan in detail.  In May 2012, an ALJ granted NSP-Minnesota’s request to withdraw the CON application; the ALJ decision is pending MPUC action.

The resource plan update also notified the MPUC that there have been changes in the size, timing, and cost estimates for the extended power uprate project at the Prairie Island nuclear generating plant.  In March 2012, NSP-Minnesota made a change of circumstances (COC) filing providing a new economic and project design analysis and seeking MPUC guidance before proceeding with the extended power uprate project.  The COC filing indicated the costs of the Prairie Island uprate project have increased, and the cost savings relative to other resource options have declined and may even be negative under certain assumptions.  The COC filing is pending MPUC action.  Some elements of the resource plan remain unchanged such as the extension of certain contracts, the Monticello nuclear generating plant extended power uprate project and the commitment to specific conservation improvement program annual achievements.

CapX2020 CON — In 2009, the MPUC granted CONs to construct one 230 kilovolt (KV) electric transmission line and three 345 KV electric transmission lines as part of the CapX2020 project.  The estimated cost of the four major transmission projects is $1.9 billion.  NSP-Minnesota and NSP-Wisconsin are responsible for approximately $1.1 billion of the total cost.  The remainder of the costs will be borne by other utilities in the upper Midwest.  These cost estimates will be revised after the regulatory process is completed.

The MPUC has issued route permits for the Minnesota portion of the Fargo, N.D. to St. Cloud, Minn. project, the Brookings, S.D. project, the Bemidji, Minn. to Grand Rapids, Minn. project and for the portions of the new transmission lines between Hampton, Minn. and La Crosse, Wis. to be constructed in Minnesota.  In June 2011, the SDPUC approved a facility permit for a portion of the Brookings, S.D. project.  The North Dakota Public Service Commission granted a CPCN in January 2011.  It is expected the NDPSC will approve the remaining required Certificate of Corridor Compatibility and Route Permit activities in North Dakota in August 2012.

In December 2011, the Monticello, Minn. to St. Cloud, Minn. 345 KV project was placed in service and MISO granted the final approval of the Brookings, S.D. project as a multi-value project.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of NSP-Minnesota, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards.  State and local agencies have jurisdiction over many of NSP-Minnesota’s activities, including regulation of retail rates and environmental matters.  See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2011.  In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) —In July 2011, the FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation, and development.  On April 18, 2012, the Minnesota Governor signed legislation that preserves the rights of incumbent utilities to construct and own transmission interconnected to their systems.  This legislation is similar to the legislation previously passed in North Dakota and South Dakota.  Therefore, Order 1000 is expected to have limited impacts on future transmission development and ownership in the NSP System in Minnesota, North Dakota, and South Dakota.  The NSP System is the integrated electric production and transmission system of NSP-Minnesota and NSP-Wisconsin, which is managed by NSP-Minnesota. Compliance filings to address these new requirements are due October 2012, and are effective prospectively.

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In May 2012, the FERC issued Order 1000-A, its order on rehearing of Order 1000.  Order 1000-A declined all motions for rehearing and offered limited clarification of aspects of the final rule.  Several parties filed requests for clarification of Order 1000-A.  Several appeals of Order 1000 have also been filed and these appeals have been consolidated into the D.C. Circuit.  These appeals are expected to be heard over the next 12 months with a ruling expected sometime in mid-2013.

Nuclear Power Operations and Waste Disposal

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant.  See Note 12 of NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2011 for further discussion regarding the nuclear generating plants.  Nuclear power plant operation produces gaseous, liquid and solid radioactive wastes.  The discharge and handling of such wastes are controlled by federal regulation.  High-level radioactive wastes primarily include used nuclear fuel.  Low-level radioactive waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in the plant.

NRC Regulation — The NRC regulates the nuclear operations of NSP-Minnesota.  Decisions by the NRC can significantly impact the operations of the nuclear generating plants.  The event at the nuclear generating plant in Fukushima, Japan in 2011 could impact the NRC’s deliberations on NSP-Minnesota’s power uprates and could also result in additional regulation, which could require additional capital expenditures or operating expenses.  The NRC has created an internal task force that has developed recommendations on whether it should require immediate emergency preparedness and mitigating enhancements at U.S. reactors and any changes to NRC regulations, inspection procedures, and licensing processes.  In July 2011, the task force released its recommendations in a written report which recommends actions to enhance U.S. nuclear generating plant readiness to safely manage severe events.

In March 2012, the NRC issued three orders and a request for additional information to all licensees.  The orders included requirements for mitigation strategies for beyond-design-basis external events, requirements with regard to reliable spent fuel instrumentation, and requirements with regard to reliable hardened containment vents, which are applicable to boiling water reactor containments at the Monticello plant.  The request for additional information included requirements to perform walkdowns of seismic and flood protection, to evaluate seismic and flood hazards, and to assess the emergency preparedness staffing and communications capabilities at each plant.  NSP-Minnesota expects that complying with these requirements will cost approximately $20 to $50 million at the Monticello and Prairie Island plants.  Based on current refueling outage plans specific to each nuclear facility, the dates of the required compliance begin in the second quarter of 2015 with all units being fully compliant by December 2016.  NSP-Minnesota believes the costs associated with compliance would be recoverable from customers through regulatory mechanisms and does not expect a material impact on its results of operations, financial position, or cash flows.

NRC Waste Confidence Decision (WCD) — In June 2012, the D.C. Circuit issued a ruling to vacate and remand the NRC’s WCD.  The WCD assesses how long temporary on-site storage can remain safe and when facilities for the disposal of nuclear waste will become available.  The D.C. Circuit remanded the WCD to the NRC and directed them to prepare an environmental impact statement if there are significant impacts or an environmental assessment to support a finding of no significant impact.  NSP-Minnesota is reviewing the decision and believes that there will not be an immediate impact for operations at the Prairie Island or Monticello nuclear generating plants.

Nuclear Plant Power Uprates

Prairie Island Nuclear Extended Power Uprate — In 2009, the MPUC approved a CON for an extended power uprate of approximately 164 MW for Prairie Island Units 1 and 2.  Recent analysis of the extended power uprate submittals to the NRC concluded that significant additional design work beyond NSP-Minnesota’s estimated schedule and cost plan would be required for a successful application submittal.  The analysis demonstrates the magnitude of the benefits is substantially lower than originally anticipated.  As a result, NSP-Minnesota completed an economic and new project design analysis and submitted a COC filing with the MPUC in March 2012.  As part of the analysis, potential prospective risks were identified that could further reduce the anticipated economic benefits of the project.  NSP-Minnesota asked the MPUC to confirm that the extended power uprate project is in the best interest of customers prior to NSP-Minnesota making the significant investments necessary to complete an application and undertake the NRC licensing process.  Public comments have been received both in support of and challenging the continuation of the project.  NSP-Minnesota is working to facilitate interaction between parties to ensure a common understanding of the benefits and challenges to the project before the MPUC renders a decision.  The COC filing is pending MPUC action.

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Monticello Nuclear Plant Extended Power Uprate—  In 2008, NSP-Minnesota filed for both state and federal approvals of an extended power uprate of approximately 71 MW for NSP-Minnesota’s Monticello nuclear generating plant.  The MPUC approved the CON for the extended power uprate in 2008.  The filing was placed on hold by the NRC staff to address concerns raised by the Advisory Committee on Reactor Safeguards related to containment pressure associated with pump performance.  NSP-Minnesota has been working with the industry and regulatory agencies to address this issue and expects to submit an update to the application for approval to the NRC in the fourth quarter of 2012, which could result in approval of the extended power uprate project by the NRC in the second quarter of 2013.  NSP-Minnesota is planning to implement the equipment changes needed to support the Monticello life extension and power uprate projects in the planned spring 2013 refueling outage.

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure.  As of June 30, 2012, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No change in NSP-Minnesota’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, NSP-Minnesota’s internal control over financial reporting.

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

In the normal course of business, various lawsuits and claims have arisen against NSP-Minnesota.  NSP-Minnesota has recorded an estimate of the probable cost of settlement or other disposition for such matters.

Additional Information

See Note 6 to the consolidated financial statements for further discussion of legal claims and environmental proceedings.  See Note 5 to the consolidated financial statements for discussion of proceedings involving utility rates and other regulatory matters.

Item 1A — RISK FACTORS

NSP-Minnesota’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2011, which is incorporated herein by reference.

Item 4 — MINE SAFETY DISCLOSURES

None.

Item 5 — OTHER INFORMATION

None.

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Item 6 — EXHIBITS

*Indicates incorporation by reference

† Furnished, herewith, not filed.  Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

3.01*	Articles of Incorporation and Amendments of Northern Power Corp. (renamed Northern States Power Co. (a Minnesota corporation) on Aug. 21, 2000) (Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
3.02*	By-Laws of Northern Power Corp. as Amended on Aug. 1, 2000 and June 3, 2008 (Exhibit 3.02 to Form 8-K (file no. 001-31387) dated June 3, 2008).
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101†	The following materials from NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 are formatted in XBRL (eXtensible Business Reporting Language):  (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) Notes to Condensed Consolidated Financial Statements, and (vi) document and entity information.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		Northern States Power Company (a Minnesota corporation)
Aug. 3, 2012
	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Vice President and Controller
		/s/ TERESA S. MADDEN
		Teresa S. Madden
		Senior Vice President, Chief Financial Officer and Director

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EX-31.01

Exhibit 31.01

CERTIFICATION

I, Judy M. Poferl, certify that:

1. I have reviewed this report on Form 10-Q of Northern States Power Company (a Minnesota corporation);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   Aug. 3, 2012

/s/ JUDY M. POFERL

Judy M. Poferl

President, Chief Executive Officer and Director

1

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Teresa S. Madden, certify that:

1. I have reviewed this report on Form 10-Q of Northern States Power Company (a Minnesota corporation);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  Aug. 3, 2012

/s/ TERESA S. MADDEN

Teresa S. Madden

Senior Vice President, Chief Financial Officer and Director

2

EX-32.01

Exhibit 32.01

OFFICER CERTIFICATION

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Northern States Power Company, a Minnesota Corporation (NSP-Minnesota) on Form 10-Q for the quarter ended June 30, 2012, as filed with the SEC on the date hereof (Form 10-Q), each of the undersigned officers of NSP-Minnesota certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of NSP-Minnesota as of the dates and for the periods expressed in the Form 10-Q.

Date:  Aug. 3, 2012

/s/ JUDY M. POFERL

Judy M. Poferl

President, Chief Executive Officer and Director

/s/ TERESA S. MADDEN

Teresa S. Madden

Senior Vice President, Chief Financial Officer and Director

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to NSP-Minnesota and will be retained by NSP-Minnesota and furnished to the SEC or its staff upon request.

1

EX-99.01

Exhibit 99.01

NSP-Minnesota Cautionary Factors

The Private Securities Litigation Reform Act provides a “safe harbor” for forward-looking statements to encourage such disclosures without the threat of litigation, providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement.  Forward-looking statements are made in written documents and oral presentations of NSP-Minnesota, Xcel Energy Inc. or any of its other subsidiaries.  These statements are based on management’s beliefs as well as assumptions and information currently available to management.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions.  In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause NSP-Minnesota’s actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

· Economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures;

· The risk of a significant slowdown in growth or decline in the U.S. economy, the risk of delay in growth recovery in the U.S. economy or the risk of increased cost for insurance premiums, security and other items as a consequence of past or future terrorist attacks;

· Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where NSP-Minnesota has a financial interest;

· Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services;

· Financial or regulatory accounting principles or policies imposed by the FASB, the SEC, the FERC and similar entities with regulatory oversight;

· Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, NSP-Minnesota, Xcel Energy Inc. or any of its other subsidiaries; or security ratings;

· Factors affecting utility and nonutility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel, nuclear fuel or natural gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; nuclear or environmental incidents; cyber incidents; or electric transmission or natural gas pipeline constraints;

· Employee workforce factors, including loss or retirement of key executives, collective bargaining agreements with union employees, or work stoppages;

· Increased competition in the utility industry or additional competition in the markets served by NSP-Minnesota, Xcel Energy Inc. and its other subsidiaries;

· State, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and natural gas markets; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

· Environmental laws and regulations, including legislation and regulations relating to climate change, and the associated cost of compliance;

· Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;

· Nuclear regulatory policies and procedures, including operating regulations and spent nuclear fuel storage;

· Social attitudes regarding the utility and power industries;

· Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;

· Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;

· Risks associated with implementations of new technologies; and

· Other business or investment considerations that may be disclosed from time to time in SEC filings, including “Risk Factors” in Item 1A of NSP-Minnesota’s form 10-K for the year ended Dec. 31, 2011, or in other publicly disseminated written documents.

NSP-Minnesota undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.  The foregoing review of factors should not be construed as exhaustive.

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Commitments and Contingencies, Legal Contingencies (Details) (USD $)	Jun. 30, 2012 Native Village of Kivalina vs. Xcel Energy Inc. et al. [Member]	Feb. 29, 2008 Native Village of Kivalina vs. Xcel Energy Inc. et al. [Member]	Jun. 30, 2012 Comer vs. Xcel Energy Inc. et al. [Member]	May 31, 2011 Comer vs. Xcel Energy Inc. et al. [Member]	Jun. 30, 2012 Merricourt Wind Project Litigation [Member]	May 31, 2011 Merricourt Wind Project Litigation [Member]	Apr. 30, 2011 Merricourt Wind Project Litigation [Member] MW	Mar. 31, 2011 Merricourt Wind Project Litigation [Member]
Legal Contingencies [Abstract]
Number of other entities against which the native village of Kivalina has filed a lawsuit		23
Estimated cost of relocating the village of Kivalina, low end of range	$ 95,000,000
Estimated cost of relocating the village of Kivalina, high end of range	400,000,000
Accrual for legal contingency	0		0		0
Minimum number of utility, oil, chemical and coal companies against which a lawsuit was filed in U.S. District Court in Mississippi				85
Generating capacity (in MW)							150
Merricourt deposit								101,000,000
Minimum amount of damages claimed by plaintiff						$ 240,000,000

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Other Income (Expense), Net (Tables)

6 Months Ended

Jun. 30, 2012

Other Income (Expense), Net [Abstract]

Other Income (Expense), Net

Other income (expense), net consisted of the following:

	Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2012			2011			2012			2011
Interest (expense) income	$	(83	)	$	(126	)	$	3,756		$	2,953
Other nonoperating income		168			138			472			332
Insurance policy expense		(967	)		(1,217	)		(2,705	)		(1,606	)
Other (expense) income, net	$	(882	)	$	(1,205	)	$	1,523		$	1,679

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Segment Reporting Information [Line Items]
Operating revenues from external customers	$ 972,536	$ 1,010,526	$ 2,049,309	$ 2,203,418
Intersegment revenues	0	0	0	0
Total operating revenues	972,536	1,010,526	2,049,309	2,203,418
Net income (loss)	64,312	65,223	141,298	157,398
Regulated Electric [Member]
Segment Reporting Information [Line Items]
Operating revenues from external customers	908,050	908,070	1,782,434	1,812,207
Intersegment revenues	144	171	267	296
Total operating revenues	908,194	908,241	1,782,701	1,812,503
Net income (loss)	64,921	61,870	124,202	130,174
Regulated Natural Gas [Member]
Segment Reporting Information [Line Items]
Operating revenues from external customers	59,069	96,922	255,583	380,648
Intersegment revenues	139	148	380	339
Total operating revenues	59,208	97,070	255,963	380,987
Net income (loss)	(2,811)	74	11,486	21,149
All Other [Member]
Segment Reporting Information [Line Items]
Operating revenues from external customers	5,417	5,534	11,292	10,563
Intersegment revenues	0	0	0	0
Total operating revenues	5,417	5,534	11,292	10,563
Net income (loss)	2,202	3,279	5,610	6,075
Reconciling Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues from external customers	0	0	0	0
Intersegment revenues	(283)	(319)	(647)	(635)
Total operating revenues	(283)	(319)	(647)	(635)
Net income (loss)	$ 0	$ 0	$ 0	$ 0

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Management's Opinion

6 Months Ended

Jun. 30, 2012

Management's Opinion [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, 2012 and Dec. 31, 2011; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 2012 and 2011; and its cash flows for the six months ended June 30, 2012 and 2011.  All adjustments are of a normal, recurring nature, except as otherwise disclosed.  Management has also evaluated the impact of events occurring after June 30, 2012 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, 2011 balance sheet information has been derived from the audited 2011 consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2011.  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, 2011, filed with the SEC on Feb. 27, 2012.  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.

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			6 Months Ended
	Mar. 31, 2012	Jun. 30, 2012	Dec. 31, 2011	Jun. 30, 2012 State Jurisdiction [Member]	Jun. 30, 2012 Xcel Energy Inc. [Member] Internal Revenue Service (IRS) [Member]
Income Tax Examination [Line Items]
Year(s) no longer subject to audit as statute of limitations has expired					2007
Earliest year subject to examination				2008	2008
Year(s) under examination				None	None
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit - Permanent tax positions		$ 3.3	$ 3.3
Unrecognized tax benefit - Temporary tax positions		12.6	13.4
Unrecognized tax benefit balance		15.9	16.7
NOL and tax credit carryforwards		(17.2)	(18.1)
Amounts accrued for penalties related to unrecognized tax benefits		0	0
Federal Tax Loss Carryback Claims [Abstract]
Tax loss carryback period (in years)	2Y
Discrete tax benefit	$ (15)

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Selected Balance Sheet Data (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Accounts receivable, net [Abstract]
Accounts receivable	$ 309,043	$ 337,581
Less allowance for bad debts	(19,751)	(23,004)
Accounts receivable, net	289,292	314,577
Inventories [Abstract]
Inventories	244,037	301,848
Property, plant and equipment, net [Abstract]
Property, plant and equipment	14,377,742	14,118,589
Accumulated depreciation and amortization	(5,462,566)	(5,433,106)
Property, plant and equipment, net	9,311,126	8,982,834
Electric Plant [Member]
Property, plant and equipment, net [Abstract]
Property, plant and equipment	12,026,539	11,948,041
Natural Gas Plant [Member]
Property, plant and equipment, net [Abstract]
Property, plant and equipment	1,010,389	1,006,163
Common and Other Property [Member]
Property, plant and equipment, net [Abstract]
Property, plant and equipment	465,887	525,139
Construction Work in Progress [Member]
Property, plant and equipment, net [Abstract]
Property, plant and equipment	874,927	639,246
Nuclear Fuel [Member]
Property, plant and equipment, net [Abstract]
Property, plant and equipment	2,087,663	1,939,299
Accumulated depreciation and amortization	(1,691,713)	(1,641,948)
Materials and Supplies [Member]
Inventories [Abstract]
Inventories	130,458	124,961
Fuel [Member]
Inventories [Abstract]
Inventories	89,030	113,711
Natural Gas [Member]
Inventories [Abstract]
Inventories	$ 24,549	$ 63,176

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Rate Matters (Details) (USD $)	Jun. 30, 2012	Dec. 31, 2011	Jun. 30, 2012 Electric Rate Case [Member] Minnesota Public Utilities Commission (MPUC) [Member]	May 31, 2012 Electric Rate Case [Member] Minnesota Public Utilities Commission (MPUC) [Member]	Feb. 29, 2012 Electric Rate Case [Member] Minnesota Public Utilities Commission (MPUC) [Member]	Dec. 31, 2011 Electric Rate Case [Member] Minnesota Public Utilities Commission (MPUC) [Member]	Aug. 31, 2011 Electric Rate Case [Member] Minnesota Public Utilities Commission (MPUC) [Member]	Jan. 02, 2011 Electric Rate Case [Member] Minnesota Public Utilities Commission (MPUC) [Member]	Nov. 30, 2010 Electric Rate Case [Member] Minnesota Public Utilities Commission (MPUC) [Member]	May 31, 2012 Electric Rate Case [Member] North Dakota Public Service Commission (NDPSC) [Member]	Feb. 29, 2012 Electric Rate Case [Member] North Dakota Public Service Commission (NDPSC) [Member]	May 31, 2011 Electric Rate Case [Member] North Dakota Public Service Commission (NDPSC) [Member]	Feb. 18, 2011 Electric Rate Case [Member] North Dakota Public Service Commission (NDPSC) [Member]	Dec. 31, 2010 Electric Rate Case [Member] North Dakota Public Service Commission (NDPSC) [Member]	Jun. 30, 2012 Electric Rate Case [Member] South Dakota Public Utilities Commission (SDPUC) [Member]	Jun. 29, 2012 Electric Rate Case [Member] South Dakota Public Utilities Commission (SDPUC) [Member]	Jan. 02, 2012 Electric Rate Case [Member] South Dakota Public Utilities Commission (SDPUC) [Member]	Jun. 30, 2011 Electric Rate Case [Member] South Dakota Public Utilities Commission (SDPUC) [Member]
Rate Matters [Abstract]
Entity's original requested rate increase (decrease) for 2011									$ 150,000,000					$ 19,800,000
Percentage increase in entity's original requested rate increase for 2011 (in hundredths)									5.62%					12.00%
Entity's additional requested rate increase (decrease) for 2012									48,300,000					4,200,000
Percentage increase in entity's additional requested rate increase for 2012 (in hundredths)									1.81%					2.60%
Entity's original requested percent return on equity (in hundredths)									11.25%					11.25%		10.65%		11.00%
Entity's rate base in original requested rate increase (decrease)									5,600,000,000					328,000,000		367,500,000		323,400,000
Entity's original requested equity ratio percent (in hundredths)									52.56%					52.56%		52.89%		52.48%
Entity's interim rate increase implemented								123,000,000					17,400,000				12,700,000
Entity's revised requested rate increase (decrease) for 2011							122,000,000					18,000,000
Entity's revised requested rate increase (decrease) for 2012							29,000,000					2,400,000
Entity's revised interim rate increase implemented					72,800,000
Entity's rate increase (decrease) implemented for 2011				58,000,000						13,700,000
Entity's rate increase (decrease) approved for implementation in 2012				14,800,000											8,000,000
Entity's approved percent return on equity (in hundredths)				10.37%							10.40%				9.25%
Entity's approved equity ratio percent (in hundredths)				52.56%											53.00%
Entity's adjustment related to depreciation				(30,000,000)
Entity's recorded provision for revenue subject to refund	82,419,000	69,746,000	80,000,000			67,000,000
Entity's adjustment related to property taxes			24,000,000
Property taxes deferred as regulatory asset			0
Percentage increase in entity's revised requested rate increase for 2011 (in hundredths)												11.00%
Percentage increase in entity's revised requested rate increase for 2012 (in hundredths)												1.40%
Entity's rate increase (decrease) implemented for 2012										2,000,000
Entity's original requested rate increase (decrease) for 2012																		14,600,000
Amounts currently recovered in automatic recovery mechanisms included in requested rate increase (decrease) for 2012																		700,000
Entity's original requested rate increase (decrease)																$ 19,400,000

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Commitments and Contingencies, Purchased Power Agreements and Guarantees and Indemnifications (Details) (USD $)	Jun. 30, 2012 MW	Dec. 31, 2011
Indemnification Agreement [Member] | Obligations Under Acquisition of Nobles Wind Project [Member]
Guarantees and Indemnifications [Abstract]
Generating capacity (in MW)	201
Guarantee amount	$ 20,000,000	$ 20,000,000
Current exposure	0	0
Assets held as collateral	$ 0	$ 0
Independent Power Producing Entities [Member]
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	1,064	1,064

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) (USD $)	Jun. 30, 2012	Dec. 31, 2011
Capitalization
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

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Commitments and Contingencies, Environmental Contingencies (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended
	Apr. 30, 2012 Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule [Member] MW	May 31, 2012 Regional Haze Rules [Member]	Jun. 30, 2012 Capital Commitments [Member] Cross-State Air Pollution Rule (CSAPR) [Member]	Jun. 30, 2012 Capital Commitments [Member] Regional Haze Rules [Member]
Environmental Requirements [Abstract]
Liability for estimated cost to comply with regulation			$ 10	$ 50
Generating capacity (in MW)	25
Number of years before affected facilities must demonstrate compliance, low end of range (in years)	3Y
Number of years before affected facilities must demonstrate compliance, high end of range (in years)	4Y
Estimated amount spent on projects to reduce NOx emissions on Sherco Units 1 and 2				$ 20
Number of days provided in the notice of intent to sue (in days)		180D

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CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Operating revenues
Electric	$ 908,050	$ 908,070	$ 1,782,434	$ 1,812,207
Natural gas	59,069	96,922	255,583	380,648
Other	5,417	5,534	11,292	10,563
Total operating revenues	972,536	1,010,526	2,049,309	2,203,418
Operating expenses
Electric fuel and purchased power	362,146	378,597	727,474	752,674
Cost of natural gas sold and transported	25,545	56,970	159,735	258,212
Cost of sales - other	2,972	2,865	6,089	5,791
Operating and maintenance expenses	271,611	261,626	532,641	516,840
Conservation program expenses	22,487	29,926	50,171	68,412
Depreciation and amortization	99,923	104,355	198,903	204,828
Taxes (other than income taxes)	48,374	40,334	102,142	85,987
Total operating expenses	833,058	874,673	1,777,155	1,892,744
Operating income	139,478	135,853	272,154	310,674
Other (expense) income, net	(882)	(1,205)	1,523	1,679
Allowance for funds used during construction - equity	9,179	10,146	17,214	19,739
Interest charges and financing costs
Interest charges - includes other financing costs of $1,476, $1,616, $2,953 and $3,042, respectively	52,282	52,313	104,402	103,928
Allowance for funds used during construction - debt	(4,937)	(5,961)	(9,215)	(11,284)
Total interest charges and financing costs	47,345	46,352	95,187	92,644
Income before income taxes	100,430	98,442	195,704	239,448
Income taxes	36,118	33,219	54,406	82,050
Net income	$ 64,312	$ 65,223	$ 141,298	$ 157,398

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CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
Operating activities
Net income	$ 141,298	$ 157,398
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	201,290	207,493
Nuclear fuel amortization	49,765	43,732
Deferred income taxes	91,672	85,421
Amortization of investment tax credits	(1,351)	(1,347)
Allowance for equity funds used during construction	(17,214)	(19,739)
Net derivative gains	(626)	(4,401)
Changes in operating assets and liabilities:
Accounts receivable	(83,951)	24,654
Accrued unbilled revenues	39,555	57,260
Inventories	57,811	47,168
Other current assets	(25,456)	(538)
Accounts payable	(62,066)	46,431
Net regulatory assets and liabilities	(7,165)	(8,480)
Other current liabilities	(29,202)	(10,792)
Pension and other employee benefit obligations	(73,610)	(43,484)
Change in other noncurrent assets	(23,952)	(2,586)
Change in other noncurrent liabilities	(5,607)	(26,893)
Net cash provided by operating activities	251,191	551,297
Investing activities
Utility capital/construction expenditures	(469,026)	(622,360)
Proceeds from insurance recoveries	24,000	0
Merricourt refund	0	101,261
Merricourt deposit	0	(90,833)
Allowance for equity funds used during construction	17,214	19,739
Purchases of investments in external decommissioning fund	(371,361)	(1,226,490)
Proceeds from the sale of investments in external decommissioning fund	371,361	1,226,504
Investments in utility money pool arrangement	0	(432,000)
Repayments from utility money pool arrangement	0	432,000
Advances to affiliate	0	(111,300)
Advances from affiliate	0	148,300
Change in restricted cash	94,959	0
Other, net	(1,333)	(3,691)
Net cash used in investing activities	(334,186)	(558,870)
Financing activities
(Repayments of) proceeds from short-term borrowings, net	(26,000)	5,000
Borrowings under utility money pool arrangement	555,000	300
Repayments under utility money pool arrangement	(475,000)	(300)
Repayments of long-term debt, including reacquisition premiums	0	(30)
Capital contributions from parent	145,621	125,000
Dividends paid to parent	(116,081)	(116,007)
Net cash provided by financing activities	83,540	13,963
Net change in cash and cash equivalents	545	6,390
Cash and cash equivalents at beginning of period	26,005	38,408
Cash and cash equivalents at end of period	26,550	44,798
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(96,391)	(89,977)
Cash paid for income taxes, net	(21,957)	(4,211)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 170,877	$ 23,513

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Fair Value of Financial Assets and Liabilities (Details) (USD $)	3 Months Ended				6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011		Dec. 31, 2011
Fair Value of Financial Assets and Liabilities [Abstract]
Number of years of monthly revenues or charges holder of FTRs purchased from MISO is entitled (in years)					1Y
Non-Derivative Instruments Fair Value Measurements [Abstract]
Nuclear decommissioning fund available-for-sale securities, unrealized gains	$ 109,800,000				$ 109,800,000				$ 79,800,000
Nuclear decommissioning fund available-for-sale securities, unrealized losses	76,600,000				76,600,000				87,500,000
Nuclear decommissioning fund [Abstract]
Cost	1,354,316,000	[1]			1,354,316,000	[1]			1,344,178,000	[2]
Other derivative instruments [Abstract]
Current derivative instruments	74,891,000				74,891,000				51,517,000
Other derivative instruments [Abstract]
Noncurrent derivative instruments	71,814,000				71,814,000				80,689,000
Other derivative instruments [Abstract]
Current derivative instruments	60,659,000				60,659,000				65,781,000
Other derivative instruments [Abstract]
Noncurrent derivative instruments	180,016,000				180,016,000				184,190,000
Investments [Abstract]
Miscellaneous investments	22,400,000				22,400,000				21,100,000
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward]
Balance	133,191,000		124,387,000		130,763,000		105,763,000
Purchases	12,920,000		52,952,000		31,615,000		99,821,000
Settlements	(19,148,000)		(93,790,000)		(37,643,000)		(121,573,000)
Gains (losses) recognized as regulatory assets and liabilities	2,450,000		(274,000)		4,678,000		(736,000)
Balance	129,413,000		83,275,000		129,413,000		83,275,000
Financial Impact of Qualifying Fair Value Hedges [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
Credit Related Contingent Features [Abstract]
Derivative instruments in a gross liability position	21,200,000				21,200,000				1,400,000
Payments required if credit ratings were downgraded below investment grade	0				0				100,000
Collateral posted on derivative instruments in a gross liability position	0				0				0
Collateral posted related to adequate assurance clauses in derivative contracts	0				0				0
Carrying Amount [Member]
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	3,339,401,000				3,339,401,000				3,338,897,000
Fair Value [Member]
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	4,046,627,000				4,046,627,000				4,066,367,000
Commodity Derivatives, Net [Member]
Changes in Level 3 Commodity Derivatives [Roll Forward]
Balance	5,324,000		2,332,000		12,417,000		2,392,000
Purchases	37,296,000		33,609,000		37,297,000		33,609,000
Settlements	(12,675,000)		(8,211,000)		(21,560,000)		(16,001,000)
Net transactions recorded during the period [Abstract]
(Losses) gains recognized in earnings	0	[3]	4,000	[3]	(9,000)	[3]	72,000	[3]
Gains (losses) recorded as regulatory assets and liabilities	3,844,000		(23,738,000)		5,644,000		(16,076,000)
Balance	33,789,000		3,996,000		33,789,000		3,996,000
Transfers into Level 3	0		0		0		0
Transfers out of Level 3	0		0		0		0
Cash Flow Hedges [Member]
Impact of Derivative Activity on OCI, Regulatory Assets and Liabilities, and Income [Abstract]
Fair value gains (losses) recognized during the period in accumulated other comprehensive income (loss)	(28,650,000)		(36,000)		(7,760,000)		177,000
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 income (loss)	(57,000)		(60,000)		(112,000)		(109,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		0		0
Pre-tax gains recognized during the period in income	0		0		0		0
Cash Flow Hedges [Member] | Interest Rate [Member]
Impact of Derivative Activity on OCI, Regulatory Assets and Liabilities, and Income [Abstract]
Fair value gains (losses) recognized during the period in accumulated other comprehensive income (loss)	(28,532,000)		0		(7,745,000)		0
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 income (loss)	(27,000)	[4]	(27,000)	[4]	(54,000)	[4]	(54,000)	[4]
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		0		0
Pre-tax gains recognized during the period in income	0		0		0		0
Cash Flow Hedges [Member] | Vehicle Fuel And Other Commodity [Member]
Impact of Derivative Activity on OCI, Regulatory Assets and Liabilities, and Income [Abstract]
Fair value gains (losses) recognized during the period in accumulated other comprehensive income (loss)	(118,000)		(36,000)		(15,000)		177,000
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 income (loss)	(30,000)	[5]	(33,000)	[5]	(58,000)	[5]	(55,000)	[5]
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		0		0
Pre-tax gains recognized during the period in income	0		0		0		0
Other Derivative Instruments [Member]
Impact of Derivative Activity on OCI, Regulatory Assets and Liabilities, and Income [Abstract]
Fair value gains (losses) recognized during the period in accumulated other comprehensive income (loss)	0		0		0		0
Fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	38,270,000		8,765,000		37,192,000		15,592,000
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive income (loss)	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	(9,714,000)		(8,666,000)		(1,527,000)		(6,627,000)
Pre-tax gains recognized during the period in income	1,588,000		1,320,000		3,311,000		6,675,000
Other Derivative Instruments [Member] | Trading Commodity [Member]
Impact of Derivative Activity on OCI, Regulatory Assets and Liabilities, and Income [Abstract]
Fair value gains (losses) recognized during the period in accumulated other comprehensive income (loss)	0		0		0		0
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 income (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 recognized during the period in income	1,588,000	[6]	1,320,000	[6]	3,311,000	[6]	6,675,000	[6]
Other Derivative Instruments [Member] | Electric Commodity [Member]
Impact of Derivative Activity on OCI, Regulatory Assets and Liabilities, and Income [Abstract]
Fair value gains (losses) recognized during the period in accumulated other comprehensive income (loss)	0		0		0		0
Fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	38,174,000		10,299,000		39,756,000		19,145,000
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive income (loss)	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	(9,714,000)	[7]	(8,666,000)	[8]	(17,685,000)	[8]	(17,555,000)	[8]
Pre-tax gains recognized during the period in income	0		0		0		0
Other Derivative Instruments [Member] | Natural Gas Commodity [Member]
Impact of Derivative Activity on OCI, Regulatory Assets and Liabilities, and Income [Abstract]
Fair value gains (losses) recognized during the period in accumulated other comprehensive income (loss)	0		0		0		0
Fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	96,000		(1,534,000)		(2,564,000)		(3,553,000)
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive income (loss)	0		0		0		0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	0		0		16,158,000	[7]	10,928,000	[7]
Pre-tax gains recognized during the period in income	0		0		0		0
Electric Commodity [Member]
Gross notional amounts of commodity forwards, options and FTRs [Abstract]
Notional amount	60,527,000	[10],[9]			60,527,000	[10],[9]			37,522,000	[10],[9]
Natural Gas Commodity [Member]
Gross notional amounts of commodity forwards, options and FTRs [Abstract]
Notional amount	1,828,000	[10],[9]			1,828,000	[10],[9]			7,290,000	[10],[9]
Vehicle Fuel Commodity [Member]
Gross notional amounts of commodity forwards, options and FTRs [Abstract]
Notional amount	275,000	[10],[9]			275,000	[10],[9]			330,000	[10],[9]
Interest Rate Swap [Member]
Interest Rate Derivatives [Abstract]
Amount of accumulated other comprehensive gains related to interest rate derivatives expected to be reclassified into earnings within the next twelve months	100,000				100,000
Notional amount outstanding	225,000,000				225,000,000
Asset-backed Securities [Member]
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward]
Balance	16,547,000		26,020,000		16,501,000		33,174,000
Purchases	0		0		0		756,000
Settlements	(9,458,000)		(5,206,000)		(9,459,000)		(13,116,000)
Gains (losses) recognized as regulatory assets and liabilities	(21,000)		190,000		26,000		190,000
Balance	7,068,000		21,004,000		7,068,000		21,004,000
Mortgage-backed Securities [Member]
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward]
Balance	68,671,000		98,367,000		78,664,000		72,589,000
Purchases	7,414,000		52,952,000		14,318,000		99,065,000
Settlements	(9,690,000)		(88,584,000)		(26,418,000)		(108,457,000)
Gains (losses) recognized as regulatory assets and liabilities	(74,000)		(464,000)		(243,000)		(926,000)
Balance	66,321,000		62,271,000		66,321,000		62,271,000
Real Estate [Member]
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward]
Balance	27,905,000				26,395,000
Purchases	2,271,000				3,907,000
Settlements	0				(1,766,000)
Gains (losses) recognized as regulatory assets and liabilities	2,545,000				4,185,000
Balance	32,721,000				32,721,000
Private Equity Investments [Member]
Changes in Level 3 Nuclear Decommissioning Fund Assets [Roll Forward]
Balance	20,068,000				9,203,000
Purchases	3,235,000				13,390,000
Settlements	0				0
Gains (losses) recognized as regulatory assets and liabilities	0				710,000
Balance	23,303,000				23,303,000
Fair Value Measured on a Recurring Basis [Member]
Nuclear decommissioning fund [Abstract]
Cash equivalents	24,913,000	[1]			24,913,000	[1]			26,123,000	[2]
Commingled funds	372,487,000	[1]			372,487,000	[1]			311,105,000	[2]
International equity funds	62,469,000	[1]			62,469,000	[1]			58,508,000	[2]
Private equity investments	23,303,000	[1]			23,303,000	[1]			9,203,000	[2]
Real estate	32,721,000	[1]			32,721,000	[1]			26,395,000	[2]
Debt securities [Abstract]
Government securities	119,376,000	[1]			119,376,000	[1]			117,256,000	[2]
U.S. corporate bonds	159,834,000	[1]			159,834,000	[1]			193,516,000	[2]
International corporate bonds	23,709,000	[1]			23,709,000	[1]			35,804,000	[2]
Municipal bonds	70,608,000	[1]			70,608,000	[1]			64,731,000	[2]
Asset-backed securities	7,068,000	[1]			7,068,000	[1]			16,501,000	[2]
Mortgage-backed securities	66,321,000	[1]			66,321,000	[1]			78,664,000	[2]
Equity securities [Abstract]
Common stock	424,703,000	[1]			424,703,000	[1]			398,625,000	[2]
Total	1,387,512,000	[1]			1,387,512,000	[1]			1,336,431,000	[2]
Derivatives designated as cash flow hedges [Abstract]
Vehicle fuel and other commodity	49,000				49,000				93,000
Other derivative instruments [Abstract]
Trading commodity	17,865,000				17,865,000				16,454,000
Electric commodity	33,789,000				33,789,000				11,862,000
Natural gas commodity	79,000				79,000
Total current derivative assets	51,782,000				51,782,000				28,409,000
Purchased power agreements	23,109,000	[11]			23,109,000	[11]			23,108,000	[11]
Current derivative instruments	74,891,000				74,891,000				51,517,000
Derivatives designated as cash flow hedges [Abstract]
Vehicle fuel and other commodity	0				0				0
Other derivative instruments [Abstract]
Trading commodity	28,753,000				28,753,000				26,073,000
Total noncurrent derivative assets	28,753,000				28,753,000				26,073,000
Purchased power agreements	43,061,000	[11]			43,061,000	[11]			54,616,000	[11]
Noncurrent derivative instruments	71,814,000				71,814,000				80,689,000
Derivatives designated as cash flow hedges [Abstract]
Interest rate	35,864,000				35,864,000				28,119,000
Other derivative instruments [Abstract]
Trading commodity	10,944,000				10,944,000				10,169,000
Electric commodity	0				0				143,000
Natural gas commodity	0				0				13,499,000
Total current derivative liabilities	46,808,000				46,808,000				51,930,000
Purchased power agreements	13,851,000	[11]			13,851,000	[11]			13,851,000	[11]
Current derivative instruments	60,659,000				60,659,000				65,781,000
Other derivative instruments [Abstract]
Trading commodity	13,922,000				13,922,000				11,171,000
Total noncurrent derivative liabilities	13,922,000				13,922,000				11,171,000
Purchased power agreements	166,094,000	[11]			166,094,000	[11]			173,019,000	[11]
Noncurrent derivative instruments	180,016,000				180,016,000				184,190,000
Fair Value Measured on a Recurring Basis [Member] | Level 1 [Member]
Nuclear decommissioning fund [Abstract]
Cash equivalents	15,082,000	[1]			15,082,000	[1]			7,103,000	[2]
Commingled funds	0	[1]			0	[1]			0	[2]
International equity funds	0	[1]			0	[1]			0	[2]
Private equity investments	0	[1]			0	[1]			0	[2]
Real estate	0	[1]			0	[1]			0	[2]
Debt securities [Abstract]
Government securities	0	[1]			0	[1]			0	[2]
U.S. corporate bonds	0	[1]			0	[1]			0	[2]
International corporate bonds	0	[1]			0	[1]			0	[2]
Municipal bonds	0	[1]			0	[1]			0	[2]
Asset-backed securities	0	[1]			0	[1]			0	[2]
Mortgage-backed securities	0	[1]			0	[1]			0	[2]
Equity securities [Abstract]
Common stock	424,703,000	[1]			424,703,000	[1]			398,625,000	[2]
Total	439,785,000	[1]			439,785,000	[1]			405,728,000	[2]
Derivatives designated as cash flow hedges [Abstract]
Vehicle fuel and other commodity	0				0				0
Other derivative instruments [Abstract]
Trading commodity	79,000				79,000				0
Electric commodity	0				0				0
Natural gas commodity	0				0
Total current derivative assets	79,000				79,000				0
Derivatives designated as cash flow hedges [Abstract]
Vehicle fuel and other commodity	0				0				0
Other derivative instruments [Abstract]
Trading commodity	0				0				0
Total noncurrent derivative assets	0				0				0
Derivatives designated as cash flow hedges [Abstract]
Interest rate	0				0				0
Other derivative instruments [Abstract]
Trading commodity	112,000				112,000				0
Electric commodity	0				0				0
Natural gas commodity	0				0				0
Total current derivative liabilities	112,000				112,000				0
Other derivative instruments [Abstract]
Trading commodity	0				0				0
Total noncurrent derivative liabilities	0				0				0
Fair Value Measured on a Recurring Basis [Member] | Level 2 [Member]
Nuclear decommissioning fund [Abstract]
Cash equivalents	9,831,000	[1]			9,831,000	[1]			19,020,000	[2]
Commingled funds	372,487,000	[1]			372,487,000	[1]			311,105,000	[2]
International equity funds	62,469,000	[1]			62,469,000	[1]			58,508,000	[2]
Private equity investments	0	[1]			0	[1]			0	[2]
Real estate	0	[1]			0	[1]			0	[2]
Debt securities [Abstract]
Government securities	119,376,000	[1]			119,376,000	[1]			117,256,000	[2]
U.S. corporate bonds	159,834,000	[1]			159,834,000	[1]			193,516,000	[2]
International corporate bonds	23,709,000	[1]			23,709,000	[1]			35,804,000	[2]
Municipal bonds	70,608,000	[1]			70,608,000	[1]			64,731,000	[2]
Asset-backed securities	0	[1]			0	[1]			0	[2]
Mortgage-backed securities	0	[1]			0	[1]			0	[2]
Equity securities [Abstract]
Common stock	0	[1]			0	[1]			0	[2]
Total	818,314,000	[1]			818,314,000	[1]			799,940,000	[2]
Derivatives designated as cash flow hedges [Abstract]
Vehicle fuel and other commodity	49,000				49,000				93,000
Other derivative instruments [Abstract]
Trading commodity	25,408,000				25,408,000				26,133,000
Electric commodity	0				0				0
Natural gas commodity	98,000				98,000
Total current derivative assets	25,555,000				25,555,000				26,226,000
Derivatives designated as cash flow hedges [Abstract]
Vehicle fuel and other commodity	32,000				32,000				59,000
Other derivative instruments [Abstract]
Trading commodity	31,482,000				31,482,000				28,307,000
Total noncurrent derivative assets	31,514,000				31,514,000				28,366,000
Derivatives designated as cash flow hedges [Abstract]
Interest rate	35,864,000				35,864,000				28,119,000
Other derivative instruments [Abstract]
Trading commodity	19,868,000				19,868,000				21,816,000
Electric commodity	0				0				698,000
Natural gas commodity	2,000				2,000				13,499,000
Total current derivative liabilities	55,734,000				55,734,000				64,132,000
Other derivative instruments [Abstract]
Trading commodity	16,683,000				16,683,000				13,464,000
Total noncurrent derivative liabilities	16,683,000				16,683,000				13,464,000
Fair Value Measured on a Recurring Basis [Member] | Level 3 [Member]
Nuclear decommissioning fund [Abstract]
Cash equivalents	0	[1]			0	[1]			0	[2]
Commingled funds	0	[1]			0	[1]			0	[2]
International equity funds	0	[1]			0	[1]			0	[2]
Private equity investments	23,303,000	[1]			23,303,000	[1]			9,203,000	[2]
Real estate	32,721,000	[1]			32,721,000	[1]			26,395,000	[2]
Debt securities [Abstract]
Government securities	0	[1]			0	[1]			0	[2]
U.S. corporate bonds	0	[1]			0	[1]			0	[2]
International corporate bonds	0	[1]			0	[1]			0	[2]
Municipal bonds	0	[1]			0	[1]			0	[2]
Asset-backed securities	7,068,000	[1]			7,068,000	[1]			16,501,000	[2]
Mortgage-backed securities	66,321,000	[1]			66,321,000	[1]			78,664,000	[2]
Equity securities [Abstract]
Common stock	0	[1]			0	[1]			0	[2]
Total	129,413,000	[1]			129,413,000	[1]			130,763,000	[2]
Derivatives designated as cash flow hedges [Abstract]
Vehicle fuel and other commodity	0				0				0
Other derivative instruments [Abstract]
Trading commodity	0				0				0
Electric commodity	35,664,000				35,664,000				13,333,000
Natural gas commodity	0				0
Total current derivative assets	35,664,000				35,664,000				13,333,000
Derivatives designated as cash flow hedges [Abstract]
Vehicle fuel and other commodity	0				0				0
Other derivative instruments [Abstract]
Trading commodity	0				0				0
Total noncurrent derivative assets	0				0				0
Derivatives designated as cash flow hedges [Abstract]
Interest rate	0				0				0
Other derivative instruments [Abstract]
Trading commodity	0				0				0
Electric commodity	1,875,000				1,875,000				916,000
Natural gas commodity	0				0				0
Total current derivative liabilities	1,875,000				1,875,000				916,000
Other derivative instruments [Abstract]
Trading commodity	0				0				0
Total noncurrent derivative liabilities	0				0				0
Fair Value Measured on a Recurring Basis [Member] | Fair Value Total [Member]
Derivatives designated as cash flow hedges [Abstract]
Vehicle fuel and other commodity	49,000				49,000				93,000
Other derivative instruments [Abstract]
Trading commodity	25,487,000				25,487,000				26,133,000
Electric commodity	35,664,000				35,664,000				13,333,000
Natural gas commodity	98,000				98,000
Total current derivative assets	61,298,000				61,298,000				39,559,000
Derivatives designated as cash flow hedges [Abstract]
Vehicle fuel and other commodity	32,000				32,000				59,000
Other derivative instruments [Abstract]
Trading commodity	31,482,000				31,482,000				28,307,000
Total noncurrent derivative assets	31,514,000				31,514,000				28,366,000
Derivatives designated as cash flow hedges [Abstract]
Interest rate	35,864,000				35,864,000				28,119,000
Other derivative instruments [Abstract]
Trading commodity	19,980,000				19,980,000				21,816,000
Electric commodity	1,875,000				1,875,000				1,614,000
Natural gas commodity	2,000				2,000				13,499,000
Total current derivative liabilities	57,721,000				57,721,000				65,048,000
Other derivative instruments [Abstract]
Trading commodity	16,683,000				16,683,000				13,464,000
Total noncurrent derivative liabilities	16,683,000				16,683,000				13,464,000
Fair Value Measured on a Recurring Basis [Member] | Counterparty Netting [Member]
Derivatives designated as cash flow hedges [Abstract]
Vehicle fuel and other commodity	0	[12]			0	[12]			0	[12]
Other derivative instruments [Abstract]
Trading commodity	(7,622,000)	[12]			(7,622,000)	[12]			(9,679,000)	[12]
Electric commodity	(1,875,000)	[12]			(1,875,000)	[12]			(1,471,000)	[12]
Natural gas commodity	(19,000)	[12]			(19,000)	[12]
Total current derivative assets	(9,516,000)	[12]			(9,516,000)	[12]			(11,150,000)	[12]
Derivatives designated as cash flow hedges [Abstract]
Vehicle fuel and other commodity	(32,000)	[12]			(32,000)	[12]			(59,000)	[12]
Other derivative instruments [Abstract]
Trading commodity	(2,729,000)	[12]			(2,729,000)	[12]			(2,234,000)	[12]
Total noncurrent derivative assets	(2,761,000)	[12]			(2,761,000)	[12]			(2,293,000)	[12]
Derivatives designated as cash flow hedges [Abstract]
Interest rate	0	[12]			0	[12]			0	[12]
Other derivative instruments [Abstract]
Trading commodity	(9,036,000)	[12]			(9,036,000)	[12]			(11,647,000)	[12]
Electric commodity	(1,875,000)	[12]			(1,875,000)	[12]			(1,471,000)	[12]
Natural gas commodity	(2,000)	[12]			(2,000)	[12]			0	[12]
Total current derivative liabilities	(10,913,000)	[12]			(10,913,000)	[12]			(13,118,000)	[12]
Other derivative instruments [Abstract]
Trading commodity	(2,761,000)	[12]			(2,761,000)	[12]			(2,293,000)	[12]
Total noncurrent derivative liabilities	(2,761,000)	[12]			(2,761,000)	[12]			(2,293,000)	[12]
Cash Equivalents [Member]
Nuclear decommissioning fund [Abstract]
Cost	24,913,000	[1]			24,913,000	[1]			26,123,000	[2]
Commingled Funds [Member]
Nuclear decommissioning fund [Abstract]
Cost	375,222,000	[1]			375,222,000	[1]			320,798,000	[2]
International Equity Funds [Member]
Nuclear decommissioning fund [Abstract]
Cost	65,712,000	[1]			65,712,000	[1]			63,781,000	[2]
Private Equity Investments [Member]
Nuclear decommissioning fund [Abstract]
Cost	22,593,000	[1]			22,593,000	[1]			9,203,000	[2]
Real Estate [Member]
Nuclear decommissioning fund [Abstract]
Cost	28,536,000	[1]			28,536,000	[1]			24,768,000	[2]
Debt Securities [Member]
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	104,694,000				104,694,000
Due in 1 to 5 Years	51,575,000				51,575,000
Due in 5 to 10 Years	155,364,000				155,364,000
Due after 10 Years	135,283,000				135,283,000
Total	446,916,000				446,916,000
Government Securities [Member]
Nuclear decommissioning fund [Abstract]
Cost	118,378,000	[1]			118,378,000	[1]			116,490,000	[2]
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	104,694,000				104,694,000
Due in 1 to 5 Years	79,000				79,000
Due in 5 to 10 Years	3,648,000				3,648,000
Due after 10 Years	10,955,000				10,955,000
Total	119,376,000				119,376,000
U.S. Corporate Bonds [Member]
Nuclear decommissioning fund [Abstract]
Cost	151,444,000	[1]			151,444,000	[1]			187,083,000	[2]
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	0				0
Due in 1 to 5 Years	40,032,000				40,032,000
Due in 5 to 10 Years	103,834,000				103,834,000
Due after 10 Years	15,968,000				15,968,000
Total	159,834,000				159,834,000
International Corporate Bonds [Member]
Nuclear decommissioning fund [Abstract]
Cost	22,782,000	[1]			22,782,000	[1]			35,198,000	[2]
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	0				0
Due in 1 to 5 Years	6,481,000				6,481,000
Due in 5 to 10 Years	17,228,000				17,228,000
Due after 10 Years	0				0
Total	23,709,000				23,709,000
Municipal Bonds [Member]
Nuclear decommissioning fund [Abstract]
Cost	66,769,000	[1]			66,769,000	[1]			60,469,000	[2]
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	0				0
Due in 1 to 5 Years	0				0
Due in 5 to 10 Years	27,692,000				27,692,000
Due after 10 Years	42,916,000				42,916,000
Total	70,608,000				70,608,000
Asset-backed Securities [Member]
Nuclear decommissioning fund [Abstract]
Cost	7,057,000	[1]			7,057,000	[1]			16,516,000	[2]
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	0				0
Due in 1 to 5 Years	4,983,000				4,983,000
Due in 5 to 10 Years	2,085,000				2,085,000
Due after 10 Years	0				0
Total	7,068,000				7,068,000
Mortgage-backed Securities [Member]
Nuclear decommissioning fund [Abstract]
Cost	63,526,000	[1]			63,526,000	[1]			75,627,000	[2]
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	0				0
Due in 1 to 5 Years	0				0
Due in 5 to 10 Years	877,000				877,000
Due after 10 Years	65,444,000				65,444,000
Total	66,321,000				66,321,000
Common Stock [Member]
Nuclear decommissioning fund [Abstract]
Cost	$ 407,384,000	[1]			$ 407,384,000	[1]			$ 408,122,000	[2]

[1] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $22.4 million of miscellaneous investments.

[2] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $21.1 million of miscellaneous investments.

[3] These amounts relate to commodity derivatives held at the end of the period.

[4] Recorded to interest charges.

[5] Recorded to operating and maintenance (O&M) expenses.

[6] Recorded to electric operating revenues. Portions of these gains and losses are shared with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

[7] 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.

[8] 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.

[9] Amounts are not reflective of net positions in the underlying commodities.

[10] Notional amounts for options are also included on a gross basis, but are weighted for the probability of exercise.

[11] In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term purchased power agreements 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.

[12] The accounting guidance for derivatives and hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between NSP-Minnesota and a counterparty. A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

XML

Income Taxes (Tables)

6 Months Ended

Jun. 30, 2012

Income Taxes [Abstract]

Reconciliation of Unrecognized Tax Benefit

A reconciliation of the amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	June 30, 2012		Dec. 31, 2011
Unrecognized tax benefit - Permanent tax positions	$	3.3	$	3.3
Unrecognized tax benefit - Temporary tax positions		12.6		13.4
Unrecognized tax benefit balance	$	15.9	$	16.7

Tax Benefits Associated With 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, 2012			Dec. 31, 2011
NOL and tax credit carryforwards	$	(17.2	)	$	(18.1	)

XML

Other Income (Expense), Net (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Other Income (Expense), Net [Abstract]
Other (expense) income, net	$ (882)	$ (1,205)	$ 1,523	$ 1,679
Interest (Expense) Income [Member]
Other Income (Expense), Net [Abstract]
Other (expense) income, net	(83)	(126)	3,756	2,953
Other Nonoperating Income [Member]
Other Income (Expense), Net [Abstract]
Other (expense) income, net	168	138	472	332
Insurance Policy Expense [Member]
Other Income (Expense), Net [Abstract]
Other (expense) income, net	$ (967)	$ (1,217)	$ (2,705)	$ (1,606)

XML

Fair Value of Financial Assets and Liabilities (Tables)

6 Months Ended

Jun. 30, 2012

Fair Value of Financial Assets and Liabilities [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 investments at June 30, 2012 and Dec. 31, 2011:

	June 30, 2012
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	24,913	$	15,082	$	9,831	$	-	$	24,913
Commingled funds		375,222		-		372,487		-		372,487
International equity funds		65,712		-		62,469		-		62,469
Private equity investments		22,593		-		-		23,303		23,303
Real estate		28,536		-		-		32,721		32,721
Debt securities:
Government securities		118,378		-		119,376		-		119,376
U.S. corporate bonds		151,444		-		159,834		-		159,834
International corporate bonds		22,782		-		23,709		-		23,709
Municipal bonds		66,769		-		70,608		-		70,608
Asset-backed securities		7,057		-		-		7,068		7,068
Mortgage-backed securities		63,526		-		-		66,321		66,321
Equity securities:
Common stock		407,384		424,703		-		-		424,703
Total	$	1,354,316	$	439,785	$	818,314	$	129,413	$	1,387,512

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $22.4 million of miscellaneous investments.

	Dec. 31, 2011
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	26,123	$	7,103	$	19,020	$	-	$	26,123
Commingled funds		320,798		-		311,105		-		311,105
International equity funds		63,781		-		58,508		-		58,508
Private equity investments		9,203		-		-		9,203		9,203
Real estate		24,768		-		-		26,395		26,395
Debt securities:
Government securities		116,490		-		117,256		-		117,256
U.S. corporate bonds		187,083		-		193,516		-		193,516
International corporate bonds		35,198		-		35,804		-		35,804
Municipal bonds		60,469		-		64,731		-		64,731
Asset-backed securities		16,516		-		-		16,501		16,501
Mortgage-backed securities		75,627		-		-		78,664		78,664
Equity securities:
Common stock		408,122		398,625		-		-		398,625
Total	$	1,344,178	$	405,728	$	799,940	$	130,763	$	1,336,431

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $21.1 million of miscellaneous investments.

Changes in Level 3 Nuclear Decommissioning Fund Assets

The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three and six months ended June 30, 2012 and 2011:

(Thousands of Dollars)	April 1, 2012		Purchases		Settlements			Gains (Losses) Recognized as Regulatory Assets and Liabilities			June 30, 2012
Private equity investments	$	20,068	$	3,235	$	-		$	-		$	23,303
Real estate		27,905		2,271		-			2,545			32,721
Asset-backed securities		16,547		-		(9,458	)		(21	)		7,068
Mortgage-backed securities		68,671		7,414		(9,690	)		(74	)		66,321
Total	$	133,191	$	12,920	$	(19,148	)	$	2,450		$	129,413

(Thousands of Dollars)	April 1, 2011		Purchases		Settlements			Gains (Losses) Recognized as Regulatory Assets and Liabilities			June 30, 2011
Asset-backed securities	$	26,020	$	-	$	(5,206	)	$	190		$	21,004
Mortgage-backed securities		98,367		52,952		(88,584	)		(464	)		62,271
Total	$	124,387	$	52,952	$	(93,790	)	$	(274	)	$	83,275

(Thousands of Dollars)	Jan. 1, 2012		Purchases		Settlements			Gains (Losses) Recognized as Regulatory Assets and Liabilities			June 30, 2012
Private equity investments	$	9,203	$	13,390	$	-		$	710		$	23,303
Real estate		26,395		3,907		(1,766	)		4,185			32,721
Asset-backed securities		16,501		-		(9,459	)		26			7,068
Mortgage-backed securities		78,664		14,318		(26,418	)		(243	)		66,321
Total	$	130,763	$	31,615	$	(37,643	)	$	4,678		$	129,413

(Thousands of Dollars)	Jan. 1, 2011		Purchases		Settlements			Gains (Losses) Recognized as Regulatory Assets and Liabilities			June 30, 2011
Asset-backed securities	$	33,174	$	756	$	(13,116	)	$	190		$	21,004
Mortgage-backed securities		72,589		99,065		(108,457	)		(926	)		62,271
Total	$	105,763	$	99,821	$	(121,573	)	$	(736	)	$	83,275

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, 2012:

	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	$	104,694	$	79	$	3,648	$	10,955	$	119,376
U.S. corporate bonds		-		40,032		103,834		15,968		159,834
International corporate bonds		-		6,481		17,228		-		23,709
Municipal bonds		-		-		27,692		42,916		70,608
Asset-backed securities		-		4,983		2,085		-		7,068
Mortgage-backed securities		-		-		877		65,444		66,321
Debt securities	$	104,694	$	51,575	$	155,364	$	135,283	$	446,916

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, 2012 and Dec. 31, 2011:

(Amounts in Thousands) (a)(b)	June 30, 2012		Dec. 31, 2011
Megawatt hours (MWh) of electricity		60,527		37,522
MMBtu of natural gas		1,828		7,290
Gallons of vehicle fuel		275		330

(a) Amounts are not reflective of net positions in the underlying commodities.

(b) Notional amounts for options are also included on a gross basis, but are weighted for the probability of exercise.

Impact of Derivative Activity on OCI, Regulatory Assets and Liabilities, and Income

The following tables detail the impact of derivative activity during the three and six months ended June 30, 2012 and 2011, on OCI, regulatory assets and liabilities, and income:

	Three Months Ended June 30, 2012
	Fair Value Gains (Losses)						Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:						into Income During the Period from:
	Accumulated						Accumulated						Pre-Tax Gains
	Other			Regulatory			Other			Regulatory			Recognized
	Comprehensive			(Assets) and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Loss			Liabilities			Loss			(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate	$	(28,532	)	$	-		$	(27	) (a)	$	-		$	-
Vehicle fuel and other commodity		(118	)		-			(30	) (e)		-			-
Total	$	(28,650	)	$	-		$	(57	)	$	-		$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-		$	-		$	1,588	(b)
Electric commodity		-			38,174			-			(9,714	) (c)		-
Natural gas commodity		-			96			-			-			-
Total	$	-		$	38,270		$	-		$	(9,714	)	$	1,588
	Six Months Ended June 30, 2012
	Fair Value Gains (Losses)						Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:						into Income During the Period from:
	Accumulated						Accumulated						Pre-Tax Gains
	Other			Regulatory			Other			Regulatory			Recognized
	Comprehensive			(Assets) and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Loss			Liabilities			Loss			(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate	$	(7,745	)	$	-		$	(54	) (a)	$	-		$	-
Vehicle fuel and other commodity		(15	)		-			(58	) (e)		-			-
Total	$	(7,760	)	$	-		$	(112	)	$	-		$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-		$	-		$	3,311	(b)
Electric commodity		-			39,756			-			(17,685	) (c)		-
Natural gas commodity		-			(2,564	)		-			16,158	(d)		-
Total	$	-		$	37,192		$	-		$	(1,527	)	$	3,311

	Three Months Ended June 30, 2011
	Fair Value Gains (Losses)						Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:						into Income During the Period from:
	Accumulated						Accumulated						Pre-Tax Gains
	Other			Regulatory			Other			Regulatory			Recognized
	Comprehensive			(Assets) and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Income			Liabilities			Income			(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate	$	-		$	-		$	(27	) (a)	$	-		$	-
Vehicle fuel and other commodity		(36	)		-			(33	) (e)		-			-
Total	$	(36	)	$	-		$	(60	)	$	-		$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-		$	-		$	1,320	(b)
Electric commodity		-			10,299			-			(8,666	) (c)		-
Natural gas commodity		-			(1,534	)		-			-			-
Total	$	-		$	8,765		$	-		$	(8,666	)	$	1,320
	Six Months Ended June 30, 2011
	Fair Value Gains (Losses)						Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:						into Income During the Period from:
	Accumulated						Accumulated						Pre-Tax Gains
	Other			Regulatory			Other			Regulatory			Recognized
	Comprehensive			(Assets) and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Income			Liabilities			Income			(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate	$	-		$	-		$	(54	) (a)	$	-		$	-
Vehicle fuel and other commodity		177			-			(55	) (e)		-			-
Total	$	177		$	-		$	(109	)	$	-		$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-		$	-		$	6,675	(b)
Electric commodity		-			19,145			-			(17,555	) (c)		-
Natural gas commodity		-			(3,553	)		-			10,928	(d)		-
Total	$	-		$	15,592		$	-		$	(6,627	)	$	6,675

(a) Recorded to interest charges.

(b) Recorded to electric operating revenues.  Portions of these gains and losses are shared with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

(c) 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.

(d) 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.

(e) Recorded to operating and maintenance (O&M) expenses.

Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level

The following table presents, for each of the hierarchy levels, NSP-Minnesota's derivative assets and liabilities that are measured at fair value on a recurring basis at June 30, 2012:

	June 30, 2012
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	49	$	-	$	49	$	-		$	49
Other derivative instruments:
Trading commodity		79		25,408		-		25,487		(7,622	)		17,865
Electric commodity		-		-		35,664		35,664		(1,875	)		33,789
Natural gas commodity		-		98		-		98		(19	)		79
Total current derivative assets	$	79	$	25,555	$	35,664	$	61,298	$	(9,516	)		51,782
Purchased power agreements (a)													23,109
Current derivative instruments												$	74,891
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	32	$	-	$	32	$	(32	)	$	-
Other derivative instruments:
Trading commodity		-		31,482		-		31,482		(2,729	)		28,753
Total noncurrent derivative assets	$	-	$	31,514	$	-	$	31,514	$	(2,761	)		28,753
Purchased power agreements (a)													43,061
Noncurrent derivative instruments												$	71,814

	June 30, 2012
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate	$	-	$	35,864	$	-	$	35,864	$	-		$	35,864
Other derivative instruments:
Trading commodity		112		19,868		-		19,980		(9,036	)		10,944
Electric commodity		-		-		1,875		1,875		(1,875	)		-
Natural gas commodity		-		2		-		2		(2	)		-
Total current derivative liabilities	$	112	$	55,734	$	1,875	$	57,721	$	(10,913	)		46,808
Purchased power agreements (a)													13,851
Current derivative instruments												$	60,659
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	16,683	$	-	$	16,683	$	(2,761	)	$	13,922
Total noncurrent derivative liabilities	$	-	$	16,683	$	-	$	16,683	$	(2,761	)		13,922
Purchased power agreements (a)													166,094
Noncurrent derivative instruments												$	180,016

(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 purchased power agreements 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) The accounting guidance for derivatives and hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between NSP-Minnesota and a counterparty.  A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

The following tables present, for each of the hierarchy levels, NSP-Minnesota's derivative assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2011:

	Dec. 31, 2011
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	93	$	-	$	93	$	-		$	93
Other derivative instruments:
Trading commodity		-		26,133		-		26,133		(9,679	)		16,454
Electric commodity		-		-		13,333		13,333		(1,471	)		11,862
Total current derivative assets	$	-	$	26,226	$	13,333	$	39,559	$	(11,150	)		28,409
Purchased power agreements (a)													23,108
Current derivative instruments												$	51,517
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	59	$	-	$	59	$	(59	)	$	-
Other derivative instruments:
Trading commodity		-		28,307		-		28,307		(2,234	)		26,073
Total noncurrent derivative assets	$	-	$	28,366	$	-	$	28,366	$	(2,293	)		26,073
Purchased power agreements (a)													54,616
Noncurrent derivative instruments												$	80,689

	Dec. 31, 2011
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate	$	-	$	28,119	$	-	$	28,119	$	-		$	28,119
Other derivative instruments:
Trading commodity		-		21,816		-		21,816		(11,647	)		10,169
Electric commodity		-		698		916		1,614		(1,471	)		143
Natural gas commodity		-		13,499		-		13,499		-			13,499
Total current derivative liabilities	$	-	$	64,132	$	916	$	65,048	$	(13,118	)		51,930
Purchased power agreements (a)													13,851
Current derivative instruments												$	65,781
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	13,464	$	-	$	13,464	$	(2,293	)	$	11,171
Total noncurrent derivative liabilities	$	-	$	13,464	$	-	$	13,464	$	(2,293	)		11,171
Purchased power agreements (a)													173,019
Noncurrent derivative instruments												$	184,190

(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 purchased power agreements 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) The accounting guidance for derivatives and hedgingpermits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between NSP-Minnesota and a counterparty.  A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

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, 2012 and 2011:

	Three Months Ended June 30
(Thousands of Dollars)	2012			2011
Balance at April 1	$	5,324		$	2,332
Purchases		37,296			33,609
Settlements		(12,675	)		(8,211	)
Net transactions recorded during the period:
Gains recognized in earnings (a)		-			4
Gains (losses) recorded as regulatory assets and liabilities		3,844			(23,738	)
Balance at June 30	$	33,789		$	3,996
	Six Months Ended June 30
(Thousands of Dollars)	2012			2011
Balance at Jan. 1	$	12,417		$	2,392
Purchases		37,297			33,609
Settlements		(21,560	)		(16,001	)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a)		(9	)		72
Gains (losses) recorded as regulatory assets and liabilities		5,644			(16,076	)
Balance at June 30	$	33,789		$	3,996

(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, 2012 and Dec. 31, 2011, other financial instruments for which the carrying amount did not equal fair value were as follows:

	June 30, 2012				Dec. 31, 2011
	Carrying				Carrying
(Thousands of Dollars)	Amount		Fair Value		Amount		Fair Value
Long-term debt, including current portion	$	3,339,401	$	4,046,627	$	3,338,897	$	4,066,367

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Current assets
Cash and cash equivalents	$ 26,550	$ 26,005
Restricted cash	328	95,287
Accounts receivable, net	289,292	314,577
Accounts receivable from affiliates	30,751	18,033
Accrued unbilled revenues	191,748	231,303
Inventories	244,037	301,848
Regulatory assets	173,028	141,709
Derivative instruments	74,891	51,517
Prepayments and other	81,956	45,219
Total current assets	1,112,581	1,225,498
Property, plant and equipment, net	9,311,126	8,982,834
Other assets
Nuclear decommissioning fund and other investments	1,409,952	1,357,538
Regulatory assets	873,819	872,014
Derivative instruments	71,814	80,689
Other	59,576	36,638
Total other assets	2,415,161	2,346,879
Total assets	12,838,868	12,555,211
Current liabilities
Current portion of long-term debt	450,005	450,000
Short-term debt	0	26,000
Borrowings under utility money pool arrangement	145,000	65,000
Accounts payable	405,233	322,979
Accounts payable to affiliates	48,435	47,651
Regulatory liabilities	68,754	132,574
Taxes accrued	123,864	158,319
Accrued interest	66,565	68,362
Dividends payable to parent	59,022	58,054
Derivative instruments	60,659	65,781
Provision for rate refund	82,419	69,746
Other	76,761	94,990
Total current liabilities	1,586,717	1,559,456
Deferred credits and other liabilities
Deferred income taxes	1,784,589	1,666,005
Deferred investment tax credits	31,048	31,743
Regulatory liabilities	430,764	439,029
Asset retirement obligations	1,623,642	1,581,896
Derivative instruments	180,016	184,190
Pension and employee benefit obligations	339,861	413,755
Other	82,598	65,464
Total deferred credits and other liabilities	4,472,518	4,382,082
Commitments and contingencies
Capitalization
Long-term debt	2,889,396	2,888,897
Common stock - authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares outstanding at June 30, 2012 and Dec. 31, 2011, respectively	10	10
Additional paid in capital	2,512,012	2,366,391
Retained earnings	1,396,976	1,372,727
Accumulated other comprehensive loss	(18,761)	(14,352)
Total common stockholder's equity	3,890,237	3,724,776
Total liabilities and equity	$ 12,838,868	$ 12,555,211

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CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Interest charges and financing costs
Other financing costs	$ 1,476	$ 1,616	$ 2,953	$ 3,042

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Fair Value of Financial Assets and Liabilities

6 Months Ended

Jun. 30, 2012

Fair Value of Financial Assets and Liabilities [Abstract]

Fair Value of Financial Assets and Liabilities

8.    Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosuresprovides 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 discounted cash flow or option pricing 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.  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; 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 ability to redeem private equity and real estate investments, 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, except for asset-backed and mortgage-backed securities, for which the third party service may also consider additional, more subjective inputs.  Since the impact of the use of these less observable inputs can be significant to the valuation of asset-backed and mortgage-backed securities, fair value measurements for these instruments have been assigned a Level 3.  Inputs that may be considered in the valuation of asset-backed and mortgage-backed securities in conjunction with pricing of similar securities in active markets include the use of risk-based discounting and estimated prepayments in a discounted cash flow model.  When these additional inputs and models are utilized, increases in the risk-adjusted discount rates and decreases in the assumed principal prepayment rates each have the impact of reducing reported fair values for these instruments.

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 financial transmission rights (FTRs) purchased from Midwest Independent Transmission System Operator, Inc. (MISO).  FTRs purchased from MISO are financial instruments that entitle the holder to one year of 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 that energy congestion, which is caused by overall transmission load and other transmission constraints. 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.  Monthly FTR settlements are included in the fuel clause adjustment,  and therefore changes in the fair value of the yet to be settled portions of 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.

NSP-Minnesota continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts 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 commodity derivative liabilities, the impact of considering credit risk was immaterial to the fair value of commodity derivative assets and liabilities presented in the consolidated balance sheets.

Non-Derivative Instruments Fair Value Measurements

The Nuclear Regulatory Commission (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 nuclear generating plants.  The fund contains cash equivalents, debt securities, equity securities, and other investments - all classified as available-for-sale securities under the applicable accounting guidance.  NSP-Minnesota plans to reinvest proceeds from matured securities until decommissioning begins.

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 $109.8 million and $79.8 million at June 30, 2012 and Dec. 31, 2011, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $76.6 million and $87.5 million at June 30, 2012 and Dec. 31, 2011, 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 investments at June 30, 2012 and Dec. 31, 2011:

	June 30, 2012
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	24,913	$	15,082	$	9,831	$	-	$	24,913
Commingled funds		375,222		-		372,487		-		372,487
International equity funds		65,712		-		62,469		-		62,469
Private equity investments		22,593		-		-		23,303		23,303
Real estate		28,536		-		-		32,721		32,721
Debt securities:
Government securities		118,378		-		119,376		-		119,376
U.S. corporate bonds		151,444		-		159,834		-		159,834
International corporate bonds		22,782		-		23,709		-		23,709
Municipal bonds		66,769		-		70,608		-		70,608
Asset-backed securities		7,057		-		-		7,068		7,068
Mortgage-backed securities		63,526		-		-		66,321		66,321
Equity securities:
Common stock		407,384		424,703		-		-		424,703
Total	$	1,354,316	$	439,785	$	818,314	$	129,413	$	1,387,512

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $22.4 million of miscellaneous investments.

	Dec. 31, 2011
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	26,123	$	7,103	$	19,020	$	-	$	26,123
Commingled funds		320,798		-		311,105		-		311,105
International equity funds		63,781		-		58,508		-		58,508
Private equity investments		9,203		-		-		9,203		9,203
Real estate		24,768		-		-		26,395		26,395
Debt securities:
Government securities		116,490		-		117,256		-		117,256
U.S. corporate bonds		187,083		-		193,516		-		193,516
International corporate bonds		35,198		-		35,804		-		35,804
Municipal bonds		60,469		-		64,731		-		64,731
Asset-backed securities		16,516		-		-		16,501		16,501
Mortgage-backed securities		75,627		-		-		78,664		78,664
Equity securities:
Common stock		408,122		398,625		-		-		398,625
Total	$	1,344,178	$	405,728	$	799,940	$	130,763	$	1,336,431

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $21.1 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, 2012 and 2011:

(Thousands of Dollars)	April 1, 2012		Purchases		Settlements			Gains (Losses) Recognized as Regulatory Assets and Liabilities			June 30, 2012
Private equity investments	$	20,068	$	3,235	$	-		$	-		$	23,303
Real estate		27,905		2,271		-			2,545			32,721
Asset-backed securities		16,547		-		(9,458	)		(21	)		7,068
Mortgage-backed securities		68,671		7,414		(9,690	)		(74	)		66,321
Total	$	133,191	$	12,920	$	(19,148	)	$	2,450		$	129,413

(Thousands of Dollars)	April 1, 2011		Purchases		Settlements			Gains (Losses) Recognized as Regulatory Assets and Liabilities			June 30, 2011
Asset-backed securities	$	26,020	$	-	$	(5,206	)	$	190		$	21,004
Mortgage-backed securities		98,367		52,952		(88,584	)		(464	)		62,271
Total	$	124,387	$	52,952	$	(93,790	)	$	(274	)	$	83,275

(Thousands of Dollars)	Jan. 1, 2012		Purchases		Settlements			Gains (Losses) Recognized as Regulatory Assets and Liabilities			June 30, 2012
Private equity investments	$	9,203	$	13,390	$	-		$	710		$	23,303
Real estate		26,395		3,907		(1,766	)		4,185			32,721
Asset-backed securities		16,501		-		(9,459	)		26			7,068
Mortgage-backed securities		78,664		14,318		(26,418	)		(243	)		66,321
Total	$	130,763	$	31,615	$	(37,643	)	$	4,678		$	129,413

(Thousands of Dollars)	Jan. 1, 2011		Purchases		Settlements			Gains (Losses) Recognized as Regulatory Assets and Liabilities			June 30, 2011
Asset-backed securities	$	33,174	$	756	$	(13,116	)	$	190		$	21,004
Mortgage-backed securities		72,589		99,065		(108,457	)		(926	)		62,271
Total	$	105,763	$	99,821	$	(121,573	)	$	(736	)	$	83,275

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class at June 30, 2012:

	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	$	104,694	$	79	$	3,648	$	10,955	$	119,376
U.S. corporate bonds		-		40,032		103,834		15,968		159,834
International corporate bonds		-		6,481		17,228		-		23,709
Municipal bonds		-		-		27,692		42,916		70,608
Asset-backed securities		-		4,983		2,085		-		7,068
Mortgage-backed securities		-		-		877		65,444		66,321
Debt securities	$	104,694	$	51,575	$	155,364	$	135,283	$	446,916

Derivative Instruments Fair Value Measurements

NSP-Minnesota enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to reduce risk in connection with changes in interest rates, utility commodity prices, vehicle fuel prices, as well as variances in forecasted weather.

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, 2012, accumulated OCI related to interest rate derivatives included $0.1 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

At June 30, 2012, NSP-Minnesota had unsettled interest rate swaps outstanding with a total notional amount of $225 million.  These interest rate swaps were designated as hedges, and as such, changes in fair value are recorded to OCI.

Short-Term Wholesale and Commodity Trading Risk - NSP-Minnesota conducts various short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related products.  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 the 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, and vehicle fuel.

At June 30, 2012, NSP-Minnesota had vehicle fuel contracts designated as cash flow hedges extending through December 2014.  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 OCI 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, 2012 and 2011.

At June 30, 2012, accumulated OCI related to commodity derivative cash flow hedges included immaterial amounts of net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

Additionally, NSP-Minnesota enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers.  Changes in the fair value of these commodity derivatives are recorded in electric operating revenue, net of amounts credited to customers under margin-sharing mechanisms.

The following table details the gross notional amounts of commodity forwards, options, and FTRs at June 30, 2012 and Dec. 31, 2011:

(Amounts in Thousands) (a)(b)	June 30, 2012		Dec. 31, 2011
Megawatt hours (MWh) of electricity		60,527		37,522
MMBtu of natural gas		1,828		7,290
Gallons of vehicle fuel		275		330

(a) Amounts are not reflective of net positions in the underlying commodities.

(b) Notional amounts for options are also 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, 2012 and 2011, on OCI, regulatory assets and liabilities, and income:

	Three Months Ended June 30, 2012
	Fair Value Gains (Losses)						Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:						into Income During the Period from:
	Accumulated						Accumulated						Pre-Tax Gains
	Other			Regulatory			Other			Regulatory			Recognized
	Comprehensive			(Assets) and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Loss			Liabilities			Loss			(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate	$	(28,532	)	$	-		$	(27	) (a)	$	-		$	-
Vehicle fuel and other commodity		(118	)		-			(30	) (e)		-			-
Total	$	(28,650	)	$	-		$	(57	)	$	-		$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-		$	-		$	1,588	(b)
Electric commodity		-			38,174			-			(9,714	) (c)		-
Natural gas commodity		-			96			-			-			-
Total	$	-		$	38,270		$	-		$	(9,714	)	$	1,588
	Six Months Ended June 30, 2012
	Fair Value Gains (Losses)						Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:						into Income During the Period from:
	Accumulated						Accumulated						Pre-Tax Gains
	Other			Regulatory			Other			Regulatory			Recognized
	Comprehensive			(Assets) and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Loss			Liabilities			Loss			(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate	$	(7,745	)	$	-		$	(54	) (a)	$	-		$	-
Vehicle fuel and other commodity		(15	)		-			(58	) (e)		-			-
Total	$	(7,760	)	$	-		$	(112	)	$	-		$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-		$	-		$	3,311	(b)
Electric commodity		-			39,756			-			(17,685	) (c)		-
Natural gas commodity		-			(2,564	)		-			16,158	(d)		-
Total	$	-		$	37,192		$	-		$	(1,527	)	$	3,311

	Three Months Ended June 30, 2011
	Fair Value Gains (Losses)						Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:						into Income During the Period from:
	Accumulated						Accumulated						Pre-Tax Gains
	Other			Regulatory			Other			Regulatory			Recognized
	Comprehensive			(Assets) and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Income			Liabilities			Income			(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate	$	-		$	-		$	(27	) (a)	$	-		$	-
Vehicle fuel and other commodity		(36	)		-			(33	) (e)		-			-
Total	$	(36	)	$	-		$	(60	)	$	-		$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-		$	-		$	1,320	(b)
Electric commodity		-			10,299			-			(8,666	) (c)		-
Natural gas commodity		-			(1,534	)		-			-			-
Total	$	-		$	8,765		$	-		$	(8,666	)	$	1,320
	Six Months Ended June 30, 2011
	Fair Value Gains (Losses)						Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:						into Income During the Period from:
	Accumulated						Accumulated						Pre-Tax Gains
	Other			Regulatory			Other			Regulatory			Recognized
	Comprehensive			(Assets) and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Income			Liabilities			Income			(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate	$	-		$	-		$	(54	) (a)	$	-		$	-
Vehicle fuel and other commodity		177			-			(55	) (e)		-			-
Total	$	177		$	-		$	(109	)	$	-		$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-		$	-		$	6,675	(b)
Electric commodity		-			19,145			-			(17,555	) (c)		-
Natural gas commodity		-			(3,553	)		-			10,928	(d)		-
Total	$	-		$	15,592		$	-		$	(6,627	)	$	6,675

(a) Recorded to interest charges.

(b) Recorded to electric operating revenues.  Portions of these gains and losses are shared with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

(c) 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.

(d) 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.

(e) Recorded to operating and maintenance (O&M) expenses.

NSP-Minnesota had no derivative instruments designated as fair value hedges during the three and six months ended June 30, 2012 and 2011.  Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Credit Related Contingent Features- Contract provisions of the derivative instruments that NSP-Minnesota enters into 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, 2012, contracts underlying $21.2 million of derivative instruments in a gross liability position would require NSP-Minnesota to post collateral or settle applicable contracts if the credit ratings of NSP-Minnesota are downgraded below investment grade, however, at June 30, 2012, these derivative liabilities were offset by derivative assets with the applicable counterparties, and therefore such a downgrade would not result in payments to these counterparties.  If the credit ratings of NSP-Minnesota were downgraded below investment grade, contracts underlying $1.4 million of derivative instruments in a gross liability position at Dec. 31, 2011 would have required NSP-Minnesota to post collateral or settle applicable contracts, which would have resulted in payments to counterparties of $0.1 million.  At June 30, 2012 and Dec. 31, 2011, there was no collateral posted on these specific contracts.

Certain of NSP-Minnesota's 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, 2012 and Dec. 31, 2011.

Recurring Fair Value Measurements-The following table presents, for each of the hierarchy levels, NSP-Minnesota's derivative assets and liabilities that are measured at fair value on a recurring basis at June 30, 2012:

	June 30, 2012
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	49	$	-	$	49	$	-		$	49
Other derivative instruments:
Trading commodity		79		25,408		-		25,487		(7,622	)		17,865
Electric commodity		-		-		35,664		35,664		(1,875	)		33,789
Natural gas commodity		-		98		-		98		(19	)		79
Total current derivative assets	$	79	$	25,555	$	35,664	$	61,298	$	(9,516	)		51,782
Purchased power agreements (a)													23,109
Current derivative instruments												$	74,891
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	32	$	-	$	32	$	(32	)	$	-
Other derivative instruments:
Trading commodity		-		31,482		-		31,482		(2,729	)		28,753
Total noncurrent derivative assets	$	-	$	31,514	$	-	$	31,514	$	(2,761	)		28,753
Purchased power agreements (a)													43,061
Noncurrent derivative instruments												$	71,814

	June 30, 2012
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate	$	-	$	35,864	$	-	$	35,864	$	-		$	35,864
Other derivative instruments:
Trading commodity		112		19,868		-		19,980		(9,036	)		10,944
Electric commodity		-		-		1,875		1,875		(1,875	)		-
Natural gas commodity		-		2		-		2		(2	)		-
Total current derivative liabilities	$	112	$	55,734	$	1,875	$	57,721	$	(10,913	)		46,808
Purchased power agreements (a)													13,851
Current derivative instruments												$	60,659
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	16,683	$	-	$	16,683	$	(2,761	)	$	13,922
Total noncurrent derivative liabilities	$	-	$	16,683	$	-	$	16,683	$	(2,761	)		13,922
Purchased power agreements (a)													166,094
Noncurrent derivative instruments												$	180,016

(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 purchased power agreements 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) The accounting guidance for derivatives and hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between NSP-Minnesota and a counterparty.  A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

The following tables present, for each of the hierarchy levels, NSP-Minnesota's derivative assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2011:

	Dec. 31, 2011
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	93	$	-	$	93	$	-		$	93
Other derivative instruments:
Trading commodity		-		26,133		-		26,133		(9,679	)		16,454
Electric commodity		-		-		13,333		13,333		(1,471	)		11,862
Total current derivative assets	$	-	$	26,226	$	13,333	$	39,559	$	(11,150	)		28,409
Purchased power agreements (a)													23,108
Current derivative instruments												$	51,517
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	59	$	-	$	59	$	(59	)	$	-
Other derivative instruments:
Trading commodity		-		28,307		-		28,307		(2,234	)		26,073
Total noncurrent derivative assets	$	-	$	28,366	$	-	$	28,366	$	(2,293	)		26,073
Purchased power agreements (a)													54,616
Noncurrent derivative instruments												$	80,689

	Dec. 31, 2011
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate	$	-	$	28,119	$	-	$	28,119	$	-		$	28,119
Other derivative instruments:
Trading commodity		-		21,816		-		21,816		(11,647	)		10,169
Electric commodity		-		698		916		1,614		(1,471	)		143
Natural gas commodity		-		13,499		-		13,499		-			13,499
Total current derivative liabilities	$	-	$	64,132	$	916	$	65,048	$	(13,118	)		51,930
Purchased power agreements (a)													13,851
Current derivative instruments												$	65,781
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	13,464	$	-	$	13,464	$	(2,293	)	$	11,171
Total noncurrent derivative liabilities	$	-	$	13,464	$	-	$	13,464	$	(2,293	)		11,171
Purchased power agreements (a)													173,019
Noncurrent derivative instruments												$	184,190

(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 purchased power agreements 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) The accounting guidance for derivatives and hedgingpermits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between NSP-Minnesota and a counterparty.  A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

The following table presents the changes in Level 3 commodity derivatives for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30
(Thousands of Dollars)	2012			2011
Balance at April 1	$	5,324		$	2,332
Purchases		37,296			33,609
Settlements		(12,675	)		(8,211	)
Net transactions recorded during the period:
Gains recognized in earnings (a)		-			4
Gains (losses) recorded as regulatory assets and liabilities		3,844			(23,738	)
Balance at June 30	$	33,789		$	3,996
	Six Months Ended June 30
(Thousands of Dollars)	2012			2011
Balance at Jan. 1	$	12,417		$	2,392
Purchases		37,297			33,609
Settlements		(21,560	)		(16,001	)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a)		(9	)		72
Gains (losses) recorded as regulatory assets and liabilities		5,644			(16,076	)
Balance at June 30	$	33,789		$	3,996

(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 the three and six months ended June 30, 2012 and 2011.

Fair Value of Long-Term Debt

As of June 30, 2012 and Dec. 31, 2011, other financial instruments for which the carrying amount did not equal fair value were as follows:

	June 30, 2012				Dec. 31, 2011
	Carrying				Carrying
(Thousands of Dollars)	Amount		Fair Value		Amount		Fair Value
Long-term debt, including current portion	$	3,339,401	$	4,046,627	$	3,338,897	$	4,066,367

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, 2012 and Dec. 31, 2011, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.  These fair value estimates have not been comprehensively revalued for purposes of these consolidated financial statements since those dates and current estimates of fair values may differ significantly.

XML

Document and Entity Information	6 Months Ended
	Jun. 30, 2012	Aug. 03, 2012
Document and Entity Information [Abstract]
Entity Registrant Name	NORTHERN STATES POWER CO
Entity Central Index Key	0001123852
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
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	2012
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2012

XML

Other Income (Expense), Net

6 Months Ended

Jun. 30, 2012

Other Income (Expense), Net [Abstract]

Other Income (Expense), Net

9.  Other Income (Expense), Net

 

Other income (expense), net consisted of the following:

	Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2012			2011			2012			2011
Interest (expense) income	$	(83	)	$	(126	)	$	3,756		$	2,953
Other nonoperating income		168			138			472			332
Insurance policy expense		(967	)		(1,217	)		(2,705	)		(1,606	)
Other (expense) income, net	$	(882	)	$	(1,205	)	$	1,523		$	1,679

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Comprehensive income:
Net income	$ 64,312	$ 65,223	$ 141,298	$ 157,398
Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $30, $24, $56 and $48, respectively	44	34	81	68
Derivative instruments:
Net fair value (decrease) increase, net of tax of $(11,680), $(6), $(3,163) and $72, respectively	(16,970)	(8)	(4,597)	105
Reclassification of gains to net income, net of tax of $(23), $(32), $(45) and $(44), respectively	(34)	(46)	(67)	(61)
Total derivative instruments, net of tax	(17,004)	(54)	(4,664)	44
Marketable securities:
Net fair value increase, net of tax of $84, $0, $120 and $34, respectively	122	0	174	50
Other comprehensive (loss) income	(16,838)	(20)	(4,409)	162
Comprehensive income	$ 47,474	$ 65,203	$ 136,889	$ 157,560

XML

Selected Balance Sheet Data

6 Months Ended

Jun. 30, 2012

Selected Balance Sheet Data [Abstract]

Selected Balance Sheet Data

3.  Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2012			Dec. 31, 2011
Accounts receivable, net
Accounts receivable	$	309,043		$	337,581
Less allowance for bad debts		(19,751	)		(23,004	)
	$	289,292		$	314,577
Inventories
Materials and supplies	$	130,458		$	124,961
Fuel		89,030			113,711
Natural gas		24,549			63,176
	$	244,037		$	301,848
Property, plant and equipment, net
Electric plant	$	12,026,539		$	11,948,041
Natural gas plant		1,010,389			1,006,163
Common and other property		465,887			525,139
Construction work in progress		874,927			639,246
Total property, plant and equipment		14,377,742			14,118,589
Less accumulated depreciation		(5,462,566	)		(5,433,106	)
Nuclear fuel		2,087,663			1,939,299
Less accumulated amortization		(1,691,713	)		(1,641,948	)
	$	9,311,126		$	8,982,834

XML

Accounting Pronouncements

6 Months Ended

Jun. 30, 2012

Accounting Pronouncements [Abstract]

Accounting Pronouncements

2. Accounting Pronouncements

Recently Adopted

Fair Value Measurement - In May 2011, the Financial Accounting Standards Board (FASB) issued Fair Value Measurement (Topic 820) - Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (Accounting Standards Update (ASU) No. 2011-04), which provides clarifications regarding existing fair value measurement principles and disclosure requirements, and also specific new guidance for items such as measurement of instruments classified within stockholders' equity.  These requirements were effective for interim and annual periods beginning after Dec. 15, 2011.  NSP-Minnesota implemented the accounting and disclosure guidance effective Jan. 1, 2012, and the implementation did not have a material impact on its consolidated financial statements.  For required fair value measurement disclosures, see Note 8.

Comprehensive Income - In June 2011, the FASB issued Comprehensive Income (Topic 220) - Presentation of Comprehensive Income (ASU No. 2011-05), which requires the presentation of the components of net income, the components of other comprehensive income (OCI) and total comprehensive income in either a single continuous financial statement of comprehensive income or in two separate, but consecutive financial statements of net income and comprehensive income.  These updates do not affect the items reported in OCI or the guidance for reclassifying such items to net income.  These requirements were effective for interim and annual periods beginning after Dec. 15, 2011.  NSP-Minnesota implemented the financial statement presentation guidance effective Jan. 1, 2012.

Recently Issued

Balance Sheet Offsetting - In December 2011, the FASB issued Balance Sheet (Topic 210) - Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity's financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements.  These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets, and are effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods.  NSP-Minnesota does not expect the implementation of this disclosure guidance to have a material impact on its consolidated financial statements.

XML

Borrowings and Other Financing Instruments (Tables)

6 Months Ended

Jun. 30, 2012

Borrowings and Other Financing Instruments [Abstract]

Commercial Paper

The following table presents commercial paper outstanding for NSP-Minnesota:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2012			Twelve Months Ended Dec. 31, 2011
Borrowing limit	$	500		$	500
Amount outstandingat period end		-			26
Average amount outstanding		52			7
Maximum amount outstanding		89			80
Weighted average interest rate, computed on a daily basis		0.41	%		0.34	%
Weighted average interest rate at period end		N/A			0.45

Committed Credit Facilities Available

At June 30, 2012, NSP-Minnesota had the following committed credit facility available (in millions of dollars):

Credit Facility		Drawn (a)		Available
$	500.0	$	8.7	$	491.3

(a) Includes outstanding letters of credit.

Money Pool

The following table presents money pool borrowings for NSP-Minnesota:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2012			Twelve Months Ended Dec. 31, 2011
Borrowing limit	$	250		$	250
Amount outstandingat period end		145			65
Average amount outstanding		50			17
Maximum amount outstanding		145			80
Weighted average interest rate, computed on a daily basis		0.34	%		0.34	%
Weighted average interest rate at period end		0.34			0.35

XML

Segment Information

6 Months Ended

Jun. 30, 2012

Segment Information [Abstract]

Segment Information

10.  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 reportable segment.

NSP-Minnesota has the following reportable segments: regulated electric, regulated natural gas and all other.

· NSP-Minnesota's regulated electric utility segment generates electricity which is transmitted and distributed in 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 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 continuing 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.

	Regulated		Regulated			All		Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas			Other		Eliminations			Total
Three Months Ended June 30, 2012
Operating revenues from external customers	$	908,050	$	59,069		$	5,417	$	-		$	972,536
Intersegment revenues		144		139			-		(283	)		-
Total revenues	$	908,194	$	59,208		$	5,417	$	(283	)	$	972,536
Net income (loss)	$	64,921	$	(2,811	)	$	2,202	$	-		$	64,312
Three Months Ended June 30, 2011
Operating revenues from external customers	$	908,070	$	96,922		$	5,534	$	-		$	1,010,526
Intersegment revenues		171		148			-		(319	)		-
Total revenues	$	908,241	$	97,070		$	5,534	$	(319	)	$	1,010,526
Net income	$	61,870	$	74		$	3,279	$	-		$	65,223
Six Months Ended June 30, 2012
Operating revenues from external customers	$	1,782,434	$	255,583		$	11,292	$	-		$	2,049,309
Intersegment revenues		267		380			-		(647	)		-
Total revenues	$	1,782,701	$	255,963		$	11,292	$	(647	)	$	2,049,309
Net income	$	124,202	$	11,486		$	5,610	$	-		$	141,298
Six Months Ended June 30, 2011
Operating revenues from external customers	$	1,812,207	$	380,648		$	10,563	$	-		$	2,203,418
Intersegment revenues		296		339			-		(635	)		-
Total revenues	$	1,812,503	$	380,987		$	10,563	$	(635	)	$	2,203,418
Net income	$	130,174	$	21,149		$	6,075	$	-		$	157,398

XML

Commitments and Contingencies

6 Months Ended

Jun. 30, 2012

Commitments and Contingencies [Abstract]

Commitments and Contingencies

6.   Commitments and Contingencies

Except as noted below and in Note 5 to the consolidated financial statements in this Quarterly Report on Form 10-Q, the circumstances set forth in Notes 10, 11 and 12 to the consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2011 appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to NSP-Minnesota's financial position.

Purchased Power Agreements

Under certain purchased power agreements, NSP-Minnesota purchases power from independent power producing entities that own natural gas or biomass fueled power plants 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 purchased power agreements create a variable interest in the associated independent power producing entity.

NSP-Minnesota had approximately 1,064 megawatts (MW) of capacity under long-term purchased power agreements as of June 30, 2012 and Dec. 31, 2011 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 the year 2028.

Guarantees and Indemnifications

In connection with the acquisition of the 201 MW Nobles wind project in 2011, NSP-Minnesota agreed to indemnify the seller for losses arising out of a breach of certain representations and warranties.  NSP-Minnesota's indemnification obligation is capped at $20 million, in the aggregate, at June 30, 2012 and Dec. 31, 2011.  The indemnification obligation expires in March 2013.  NSP-Minnesota has not recorded a liability related to this indemnity, and it had no assets held as collateral related to this agreement at June 30, 2012 or Dec. 31, 2011.

Environmental Contingencies

Environmental Requirements

Greenhouse Gas (GHG) New Source Performance Standard Proposal (NSPS) and Emission Guideline for Existing Sources - In April 2012, the U.S. Environmental Protection Agency (EPA) proposed a GHG NSPS for newly constructed power plants.  The proposal requires that carbon dioxide (CO2) emission rates be equal to those achieved by a natural gas combined-cycle plant, even if the plant is coal-fired.  The EPA also proposed that NSPS not apply to modified or reconstructed existing power plants and noted that, pursuant to its general NSPS regulations, installation of control equipment on existing plants would not constitute a "modification" to those plants under the NSPS program.  Xcel Energy submitted comments on the proposed GHG NSPS in June 2012.  It is not possible to evaluate the impact of this regulation until its final requirements are known.

The EPA also plans to propose GHG regulations applicable to emissions from existing power plants under the Clean Air Act (CAA).  It is not known when the EPA will propose new standards for existing sources.

Cross-State Air Pollution Rule (CSAPR) - In July 2011, the EPA issued its CSAPR to address long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO2) and nitrogen oxide (NOx) from utilities located in the eastern half of the United States, including Minnesota.  The CSAPR sets more stringent requirements than the proposed Clean Air Transport Rule.  The rule also creates an emissions trading program.

On Dec. 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a stay of the CSAPR, pending completion of judicial review.  Oral arguments in the case were held in April 2012 and it is anticipated the D.C. Circuit will rule on the challenges to the CSAPR during the summer of 2012.  It is not known at this time whether the CSAPR will be upheld, reversed or will require modifications pursuant to a future D.C. Circuit decision.

If the CSAPR is upheld and unmodified, NSP-Minnesota would likely utilize a combination of emissions reductions through upgrades to its existing SO2 control technology at Sherco Units 1 and 2, which is estimated to cost a total of $10 million through 2014, and system operating changes to Black Dog and Sherco Units 1 and 2.  Costs for the Sherco Units 1 and 2 SO2 control technology are discussed below in the regional haze rules as SO2 reductions are part of the compliance plan for both the CSAPR and the regional haze rules.  If available, NSP-Minnesota would also consider allowance purchases.  In addition, NSP-Minnesota has filed a petition for reconsideration with the EPA and a petition for review of the CSAPR with the D.C. Circuit seeking the allocation of additional emission allowances to NSP-Minnesota.  NSP-Minnesota contends that the EPA's method of allocating allowances arbitrarily resulted in fewer allowances for its Riverside and High Bridge plants than should have been awarded to reflect their operations during the baseline period, which included coal-fired operations prior to their conversion to natural gas.  In April 2012, NSP-Minnesota appealed to the D.C. Circuit on a final rule that the EPA issued that made changes to certain allowance allocations under the CSAPR, seeking to secure additional allocations for its Riverside and High Bridge plants.  If successful, additional allowances would reduce NSP-Minnesota's costs to comply with the CSAPR.  The D.C. Circuit held this appeal in abeyance until it issues its decision.

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule - The final EGU MATS rule became effective 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.  NSP-Minnesota believes these costs will be recoverable through regulatory mechanisms and does not expect a material impact on results of operations, financial position or cash flows.

Regional Haze Rules - In 2005, the EPA finalized amendments to its regional haze rules regarding provisions that require the installation and operation of emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the United States.  NSP-Minnesota generating facilities are subject to BART requirements.  Individual states were required to identify the facilities located in their states that will have to reduce SO2, NOx and PM emissions under BART and then set emissions limits for those facilities.

In December 2009, the Minnesota Pollution Control Agency (MPCA) approved the regional haze state implementation plan (SIP), which has been submitted to the EPA for approval.  The MPCA selected the BART controls for Sherco Units 1 and 2 to improve visibility in the national parks.  The MPCA concluded Selective Catalytic Reduction (SCR) should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs.  The MPCA's BART controls for Sherco Units 1 and 2 consist of combustion controls for NOx and scrubber upgrades for SO2.  The combustion controls have been installed on Sherco Units 1 and 2, and the scrubber upgrades are scheduled to be installed by 2015.  At this time, the estimated cost for meeting the BART, regional haze and other CAA requirements is approximately $50 million, of which $20 million has already been spent on projects to reduce NOx emissions on Sherco Units 1 and 2.  NSP-Minnesota anticipates that all costs associated with BART compliance will be fully recoverable through regulatory recovery mechanisms.

In June 2011, the EPA provided comments to the MPCA on the SIP, stating that the EPA's preliminary review indicates that SCR controls should be added to Sherco Units 1 and 2.  The MPCA has since proposed that the CSAPR should be considered BART for EGUs and the EPA proposed that states be allowed to find that CSAPR compliance meets BART requirements for EGUs, and specifically that Minnesota's proposal to find the CSAPR to meet BART requirements should be approved, if finalized by the state.

In April 2012, the MPCA approved a supplement to the 2009 regional haze SIP finding that the CSAPR meets BART for EGUs in Minnesota.  The supplement also made a source-specific BART determination for Sherco Units 1 and 2 that requires installation of the combustion controls for NOx and scrubber upgrades for SO2 by January 2015.  In May 2012, the EPA adopted a final rule that allows states to determine whether CSAPR compliance meets BART requirements.  In June 2012, the EPA issued its final approval of the Minnesota SIP for EGUs.

In addition to the regional haze rules identified in the EPA's visibility program, and addressed in the MPCA's SIP discussed above, there are other visibility rules related to a program called the Reasonably Attributable Visibility Impairment (RAVI) program.  In October 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 make its own determination as to whether Sherco Units 1 and 2 cause or contribute to RAVI and, if so, whether the level of controls required by the MPCA is appropriate.  The EPA plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the RAVI program.  It is not yet known when the EPA will publish a proposal under RAVI, or what that proposal will entail.  In May 2012, a notice of intent to sue was filed with the EPA by the following organizations: National Parks Conservation Association, Minnesota Center for Environmental Advocacy, Friends of the Boundary Waters Wilderness, Voyagers National Park Association, Fresh Energy and Sierra Club.  The notice advised the EPA of the parties' intent to sue the EPA in 180 days to attempt to require the EPA to determine BART for the Sherco Units 1 and 2 under the RAVI program.  It is not yet known how the EPA intends to respond to this notice.

Revisions to National Ambient Air Quality Standards (NAAQS) for PM - In June 2012, the EPA proposed to lower the primary (health-based) NAAQS for annual average fine PM and to retain the current daily standard for fine PM.  In areas in which NSP-Minnesota operates power plants, current monitored air concentrations are below the range of the proposed annual primary standard.  The EPA also proposed to add a secondary (welfare-based) NAAQS to improve visibility, primarily in urban areas.  NSP-Minnesota expects the proposed visibility standard would likely be met where NSP-Minnesota operates power plants based on currently available information.  A final rule is expected in December 2012 and the EPA is expected to designate non-compliant locations by December 2014.  If such areas are identified, states would then study the sources of the nonattainment and make emission reduction plans to attain the standards.  It is not possible to evaluate the impact of this regulation further until its final requirements are known.

Legal Contingencies

Lawsuits and claims arise in the normal course of business.  Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition.  The ultimate outcome of these matters cannot presently be determined.  Accordingly, the ultimate resolution of these matters could have a material effect on NSP-Minnesota's consolidated financial position, results of operations, and cash flows.

Environmental Litigation

Native Village of Kivalina vs. Xcel Energy Inc. et al. - In February 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U.S. District Court for the Northern District of California against Xcel Energy Inc., the parent company of NSP-Minnesota, and 23 other utility, oil, gas and coal companies.  Plaintiffs claim that defendants' emission of CO2 and other GHGs contribute to global warming, which is harming their village.  Xcel Energy Inc. believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss in June 2008.  In October 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds.  In November 2009, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).  In November 2011, oral arguments were presented.  It is unknown when the Ninth Circuit will render a final opinion.  The amount of damages claimed by plaintiffs is unknown, but likely includes the cost of relocating the village of Kivalina.  Plaintiffs' alleged relocation is estimated to cost between $95 million to $400 million.  While Xcel Energy Inc. believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it could potentially have a material impact on NSP-Minnesota's consolidated results of operations, cash flows or financial position.  No accrual has been recorded for this matter.

Comer vs. Xcel Energy Inc. et al. - In May 2011, less than a year after their initial lawsuit was dismissed, plaintiffs in this purported class action lawsuit filed a second lawsuit against more than 85 utility, oil, chemical and coal companies in U.S. District Court in Mississippi.  The complaint alleges defendants' CO2 emissions intensified the strength of Hurricane Katrina and increased the damage plaintiffs purportedly sustained to their property.  Plaintiffs base their claims on public and private nuisance, trespass and negligence.  Among the defendants named in the complaint are Xcel Energy Inc. and NSP-Minnesota.  The amount of damages claimed by plaintiffs is unknown.  The defendants, including Xcel Energy Inc., believe this lawsuit is without merit and filed a motion to dismiss the lawsuit.  In March 2012, the U.S. District Court granted this motion for dismissal.  In April 2012, plaintiffs appealed this decision to the U.S. Court of Appeals for the Fifth Circuit.While Xcel Energy Inc. believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it could potentially have a material impact on NSP-Minnesota's consolidated results of operations, cash flows or financial position.  No accrual has been recorded for this matter.

Employment, Tort and Commercial Litigation

Merricourt Wind Project Litigation - In April 2011, NSP-Minnesota terminated its agreements with enXco Development Corporation (enXco) for the development of a 150 MW wind project in southeastern North Dakota.  NSP-Minnesota's decision to terminate the agreements was based in large part on the adverse impact this project could have on endangered or threatened species protected by federal law and the uncertainty in cost and timing in mitigating this impact.  NSP-Minnesota also terminated the agreements due to enXco's nonperformance of certain other conditions, including failure to obtain a Certificate of Site Compatibility and the failure to close on the contracts by an agreed upon date of March 31, 2011.  NSP-Minnesota recorded a $101 million deposit in the first quarter of 2011, which was collected in April 2011.  In May 2011, NSP-Minnesota filed a declaratory judgment action in U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreements and enXco also filed a separate lawsuit in the same court seeking, among other things, in excess of $240 million for an alleged breach of contract.  NSP-Minnesota believes enXco's lawsuit is without merit and filed a motion to dismiss.  In September 2011, the U.S. District Court denied the motion to dismiss.  The trial is set to begin in late 2012 or early 2013.  While NSP-Minnesota believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it could potentially have a material impact on NSP-Minnesota's consolidated results of operations, cash flows or financial position.  No accrual has been recorded for this matter.

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Income Taxes

6 Months Ended

Jun. 30, 2012

Income Taxes [Abstract]

Income Taxes

4.  Income Taxes

Except to the extent noted below, the circumstances set forth in Note 6 to the consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2011 appropriately represent, 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 2007 federal income tax return expired in September 2011.  The statute of limitations applicable to Xcel Energy's 2008 federal income tax return expires in September 2012.As of June 30, 2012, there was no federal income tax audit in progress.

State Audits - NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns.  As of June 30, 2012, NSP-Minnesota's earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2008.  As of June 30, 2012, there were 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, 2012		Dec. 31, 2011
Unrecognized tax benefit - Permanent tax positions	$	3.3	$	3.3
Unrecognized tax benefit - Temporary tax positions		12.6		13.4
Unrecognized tax benefit balance	$	15.9	$	16.7

The unrecognized tax benefit balance was 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, 2012			Dec. 31, 2011
NOL and tax credit carryforwards	$	(17.2	)	$	(18.1	)

It is reasonably possible that NSP-Minnesota's amount of unrecognized tax benefits could significantly change in the next 12 months as the Internal Revenue Service and state audits resume.  At this time, due to the uncertain nature of the audit process, an overall range of possible change cannot be reasonably estimated.

The payable for interest related to unrecognized tax benefits is offset by the interest benefit associated with NOL and tax credit carryforwards.  The receivable and payable for interest related to unrecognized tax benefits at June 30, 2012 and Dec. 31, 2011, respectively, were not material.  No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2012 or Dec. 31, 2011.

Federal Tax Loss Carryback Claims - NSP-Minnesota completed an analysis in the first quarter of 2012 on the eligibility of certain expenses that qualified for an extended carryback beyond the typical two-year carryback period.  As a result of a higher tax rate in prior years, NSP-Minnesota recognized a discrete tax benefit of approximately $15 million in the first quarter of 2012.

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Rate Matters

6 Months Ended

Jun. 30, 2012

Rate Matters [Abstract]

Rate Matters

5.   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, 2011 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Recently Concluded Regulatory Proceedings - Minnesota Public Utilities Commission (MPUC)

Minnesota Electric Rate Case- In November 2010, NSP-Minnesota filed a request with the MPUC to increase electric rates in Minnesota for 2011 by approximately $150 million, or an increase of 5.62 percent, and an additional increase of $48.3 million, or 1.81 percent, in 2012.  The rate filing was based on a 2011 forecast test year, a requested return on equity (ROE) of 11.25 percent, an electric rate base of $5.6 billion and an equity ratio of 52.56 percent.  The MPUC approved an interim rate increase of $123 million, subject to refund, effective Jan. 2, 2011.  In August 2011, NSP-Minnesota submitted supplemental testimony, revising its requested rate increase to approximately $122 million for 2011 and an additional increase of approximately $29 million in 2012.

In November 2011, NSP-Minnesota reached a settlement agreement with certain customer intervenors.  In February 2012, NSP-Minnesota filed to reduce the interim rate request to $72.8 million to align with the settlement agreement.  In March 2012, the MPUC approved the settlement.  In May 2012, the MPUC issued an order approving the following:

· A rate increase of approximately $58 million in 2011 and an incremental rate increase of $14.8 million in 2012 based on an ROE of 10.37 percent and an equity ratio of 52.56 percent.

· A reduction to depreciation expense and NSP-Minnesota's rate request by $30 million.

As of June 30, 2012 and Dec. 31, 2011, NSP-Minnesota recorded a provision for revenue subject to refund of approximately $80 million and $67 million, respectively.

Minnesota Property Tax Deferral Request - In December 2011, NSP-Minnesota filed a request to defer incremental 2012 property taxes that would not be recovered in base rates, estimated to be approximately $24 million, or alternatively that a property tax rider be approved.  In June 2012, the MPUC denied NSP-Minnesota's request for deferred accounting for incremental property taxes and also denied the request for a property tax rider.   There were no incremental 2012 property taxes deferred as a regulatory asset.

Recently Concluded Regulatory Proceedings - North Dakota Public Service Commission (NDPSC)

North Dakota Electric Rate Case - In December 2010, NSP-Minnesota filed a request with the NDPSC to increase 2011 electric rates in North Dakota by approximately $19.8 million, or an increase of 12 percent, and a step increase of $4.2 million, or 2.6 percent, in 2012.  The rate filing was based on a 2011 forecast test year and included a requested ROE of 11.25 percent, an electric rate base of approximately $328 million and an equity ratio of 52.56 percent.  The NDPSC approved an interim rate increase of approximately $17.4 million, subject to refund, effective Feb. 18, 2011.

In May 2011, NSP-Minnesota revised its rate request to approximately $18.0 million, or an increase of 11 percent, for 2011 and $2.4 million, or 1.4 percent, for the additional step increase in 2012.  In February 2012, the NDPSC approved the settlement agreement, which provided for a rate increase of $13.7 million in 2011 and an additional step increase of $2.0 million in 2012, based on a 10.4 percent ROE and black box settlement for all other issues.  To address 2012 sales coming in below forecast revenue projections, the settlement includes a true-up to 2012 non-fuel revenues plus the settlement rate increase.  NSP-Minnesota implemented final rates in May 2012 and issued refunds in June 2012.

Pending and Recently Concluded Regulatory Proceedings - South Dakota Public Utilities Commission (SDPUC)

South Dakota 2011 Electric Rate Case - In June 2011, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $14.6 million annually, effective in 2012.  The proposed increase included $0.7 million in revenues currently recovered through automatic recovery mechanisms.  The request was based on a 2010 historic test year adjusted for known and measurable changes, a requested ROE of 11 percent, a rate base of $323.4 million and an equity ratio of 52.48 percent.  On Jan. 2, 2012, interim rates of $12.7 million were implemented.  In June 2012, the SDPUC authorized a rate increase of approximately $8.0 million, based on an ROE of 9.25 percent, and an equity ratio of 53 percent.  On July 17, 2012, the SDPUC approved implementation of final rates on Aug. 1, 2012, with refunds to be issued in September 2012.

South Dakota 2012 Electric Rate Case-On June 29, 2012, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $19.4 million annually.  The request was based on a 2011 historic test year adjusted for certain known and measurable changes for 2012 and 2013, a requested ROE of 10.65 percent, an average rate base of $367.5 million, and an equity ratio of 52.89 percent.  A SDPUC decision is expected in late 2012 or early 2013.

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Borrowings and Other Financing Instruments

6 Months Ended

Jun. 30, 2012

Borrowings and Other Financing Instruments [Abstract]

Borrowings and Other Financing Instruments

7.   Borrowings and Other Financing Instruments

Commercial Paper - NSP-Minnesota meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility.  The following table presents commercial paper outstanding for NSP-Minnesota:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2012			Twelve Months Ended Dec. 31, 2011
Borrowing limit	$	500		$	500
Amount outstandingat period end		-			26
Average amount outstanding		52			7
Maximum amount outstanding		89			80
Weighted average interest rate, computed on a daily basis		0.41	%		0.34	%
Weighted average interest rate at period end		N/A			0.45

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 amount exceeding available capacity under the credit agreement.  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, 2012, NSP-Minnesota had the following committed credit facility available (in millions of dollars):

Credit Facility		Drawn (a)		Available
$	500.0	$	8.7	$	491.3

(a) Includes outstanding letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility.  NSP-Minnesota had no direct advances on the credit facility outstanding at June 30, 2012 and Dec. 31, 2011.

Amended Credit Agreement -In July 2012, NSP-Minnesota entered into an amended five-year credit agreement with a syndicate of banks, replacing the previous four-year credit agreement. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with an improvement in pricing and an extension of maturity from March 2015 to July 2017. The Eurodollar borrowing margin on the line of credit was reduced from a range of 100 to 200 basis points per year, to a range of 87.5 to 175 basis points per year based on applicable long-term credit ratings. The commitment fees, calculated on the unused portion of the line of credit, were reduced from a range of 10 to 35 basis points per year, to a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.

NSP-Minnesota has the right to request an extension of the revolving termination date for two additional one-year periods, subject to majority bank group approval.

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, 2012 and Dec. 31, 2011, there were $8.7 million and $7.7 million of letters of credit outstanding under the credit facility, respectively.  An additional $1.1 million of letters of credit not issued under the credit facility were outstanding at June 30, 2012 and Dec. 31, 2011, respectively.  The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

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.  The following table presents money pool borrowings for NSP-Minnesota:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2012			Twelve Months Ended Dec. 31, 2011
Borrowing limit	$	250		$	250
Amount outstandingat period end		145			65
Average amount outstanding		50			17
Maximum amount outstanding		145			80
Weighted average interest rate, computed on a daily basis		0.34	%		0.34	%
Weighted average interest rate at period end		0.34			0.35

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Borrowings and Other Financing Instruments (Details) (USD $)	1 Months Ended	6 Months Ended			3 Months Ended		12 Months Ended	3 Months Ended	12 Months Ended
	Jul. 31, 2012	Jun. 30, 2012		Dec. 31, 2011	Jun. 30, 2012 Commercial Paper [Member]		Dec. 31, 2011 Commercial Paper [Member]	Jun. 30, 2012 Money Pool [Member]	Dec. 31, 2011 Money Pool [Member]
Short-term Debt [Line Items]
Borrowing limit					$ 500,000,000		$ 500,000,000	$ 250,000,000	$ 250,000,000
Amount outstanding at period end		0		26,000,000	0		26,000,000
Amount outstanding at period end		145,000,000		65,000,000				145,000,000	65,000,000
Average amount outstanding					52,000,000		7,000,000	50,000,000	17,000,000
Maximum amount outstanding					89,000,000		80,000,000	145,000,000	80,000,000
Weighted average interest rate, computed on a daily basis (in hundredths)					0.41%		0.34%	0.34%	0.34%
Weighted average interest rate at period end (in hundredths)						[1]	0.45%	0.34%	0.35%
Committed Credit Facilities [Abstract]
Credit facility		500,000,000
Drawn		8,700,000	[2]
Available		491,300,000
Credit facility bank borrowings outstanding		0		0
Amended Credit Agreement [Abstract]
Amended term (in years)	5Y
Original term (in years)		4Y
Minimum borrowing margin based on long-term credit ratings (in hundredths)	0.875%	1.00%
Maximum borrowing margin based on long-term credit ratings (in hundredths)	1.75%	2.00%
Minimum commitment fees calculated on unused portion of lines of credit (in hundredths)	0.075%	0.10%
Maximum commitment fees calculated on unused portion of lines of credit (in hundredths)	0.275%	0.35%
Number of additional periods the revolving termination date can be extended, subject to majority bank group approval	2
Term of each additional period the revolving termination date can be extended, subject to majority bank group approval (in years)	1Y
Letters of Credit [Abstract]
Terms of letters of credit (in years)		1Y
Letters of credit outstanding under credit facilities		8,700,000		7,700,000
Letters of credit outstanding not issued under credit facilities		$ 1,100,000		$ 1,100,000

[1] N/A

[2] Includes outstanding letters of credit.

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Selected Balance Sheet Data (Tables)

6 Months Ended

Jun. 30, 2012

Selected Balance Sheet Data [Abstract]

Accounts Receivable

(Thousands of Dollars)	June 30, 2012			Dec. 31, 2011
Accounts receivable, net
Accounts receivable	$	309,043		$	337,581
Less allowance for bad debts		(19,751	)		(23,004	)
	$	289,292		$	314,577

Inventories

(Thousands of Dollars)		June 30, 2012		Dec. 31, 2011
Inventories
Materials and supplies	$	130,458	$	124,961
Fuel		89,030		113,711
Natural gas		24,549		63,176
	$	244,037	$	301,848

Property, Plant and Equipment

(Thousands of Dollars)		June 30, 2012			Dec. 31, 2011
Property, plant and equipment, net
Electric plant	$	12,026,539		$	11,948,041
Natural gas plant		1,010,389			1,006,163
Common and other property		465,887			525,139
Construction work in progress		874,927			639,246
Total property, plant and equipment		14,377,742			14,118,589
Less accumulated depreciation		(5,462,566	)		(5,433,106	)
Nuclear fuel		2,087,663			1,939,299
Less accumulated amortization		(1,691,713	)		(1,641,948	)
	$	9,311,126		$	8,982,834

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2012

Segment Information [Abstract]

Results from Continuing Operations by Reportable Segment

	Regulated		Regulated			All		Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas			Other		Eliminations			Total
Three Months Ended June 30, 2012
Operating revenues from external customers	$	908,050	$	59,069		$	5,417	$	-		$	972,536
Intersegment revenues		144		139			-		(283	)		-
Total revenues	$	908,194	$	59,208		$	5,417	$	(283	)	$	972,536
Net income (loss)	$	64,921	$	(2,811	)	$	2,202	$	-		$	64,312
Three Months Ended June 30, 2011
Operating revenues from external customers	$	908,070	$	96,922		$	5,534	$	-		$	1,010,526
Intersegment revenues		171		148			-		(319	)		-
Total revenues	$	908,241	$	97,070		$	5,534	$	(319	)	$	1,010,526
Net income	$	61,870	$	74		$	3,279	$	-		$	65,223
Six Months Ended June 30, 2012
Operating revenues from external customers	$	1,782,434	$	255,583		$	11,292	$	-		$	2,049,309
Intersegment revenues		267		380			-		(647	)		-
Total revenues	$	1,782,701	$	255,963		$	11,292	$	(647	)	$	2,049,309
Net income	$	124,202	$	11,486		$	5,610	$	-		$	141,298
Six Months Ended June 30, 2011
Operating revenues from external customers	$	1,812,207	$	380,648		$	10,563	$	-		$	2,203,418
Intersegment revenues		296		339			-		(635	)		-
Total revenues	$	1,812,503	$	380,987		$	10,563	$	(635	)	$	2,203,418
Net income	$	130,174	$	21,149		$	6,075	$	-		$	157,398

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, tax	$ 30	$ 24	$ 56	$ 48
Derivative instruments:
Net fair value (decrease) increase, tax	(11,680)	(6)	(3,163)	72
Reclassification of gains to net income, tax	(23)	(32)	(45)	(44)
Marketable securities:
Net fair value increase, tax	$ 84	$ 0	$ 120	$ 34

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2012

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

1. 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, 2011, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

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Benefit Plans and Other Postretirement Benefits (Tables)

6 Months Ended

Jun. 30, 2012

Benefit Plans and Other Postretirement Benefits [Abstract]

Components of Net Periodic Benefit Cost

Components of Net Periodic Benefit Cost

	Three Months Ended June 30
	2012			2011			2012			2011
							Postretirement Health
(Thousands of Dollars)	Pension Benefits						Care Benefits
Service cost	$	7,336		$	8,015		$	24		$	23
Interest cost		12,301			13,043			1,814			1,911
Expected return on plan assets		(16,836	)		(18,528	)		(109	)		(144	)
Amortization of transition obligation		-			-			336			336
Amortization of prior service cost (credit)		2,955			3,293			(30	)		(30	)
Amortization of net loss		10,196			7,707			853			607
Net periodic benefit cost		15,952			13,530			2,888			2,703
Cost not recognized due to the effects of regulation		(9,083	)		(10,140	)		-			-
Net benefit cost recognized for financial reporting	$	6,869		$	3,390		$	2,888		$	2,703

	Six Months Ended June 30
	2012			2011			2012			2011
							Postretirement Health
(Thousands of Dollars)	Pension Benefits						Care Benefits
Service cost	$	14,706		$	14,008		$	48		$	44
Interest cost		24,610			25,973			3,565			3,686
Expected return on plan assets		(33,658	)		(37,121	)		(219	)		(288	)
Amortization of transition obligation		-			-			673			673
Amortization of prior service cost (credit)		5,910			6,585			(59	)		(59	)
Amortization of net loss		20,065			14,368			1,602			1,174
Net periodic benefit cost		31,633			23,813			5,610			5,230
Cost not recognized due to the effects of regulation		(17,141	)		(17,450	)		-			-
Net benefit cost recognized for financial reporting	$	14,492		$	6,363		$	5,610		$	5,230

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Benefit Plans and Other Postretirement Benefits (Details) (USD $)	1 Months Ended	3 Months Ended		6 Months Ended
	Jan. 31, 2012	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Pension Benefits [Member]
Components of Net Periodic Benefit Cost [Abstract]
Service cost		$ 7,336,000	$ 8,015,000	$ 14,706,000	$ 14,008,000
Interest cost		12,301,000	13,043,000	24,610,000	25,973,000
Expected return on plan assets		(16,836,000)	(18,528,000)	(33,658,000)	(37,121,000)
Amortization of prior service cost (credit)		2,955,000	3,293,000	5,910,000	6,585,000
Amortization of net loss		10,196,000	7,707,000	20,065,000	14,368,000
Net periodic benefit cost		15,952,000	13,530,000	31,633,000	23,813,000
Cost not recognized due to the effects of regulation		(9,083,000)	(10,140,000)	(17,141,000)	(17,450,000)
Net benefit cost recognized for financial reporting		6,869,000	3,390,000	14,492,000	6,363,000
Pension contributions attributable to NSP-Minnesota	79,300,000
Postretirement Health Care Benefits [Member]
Components of Net Periodic Benefit Cost [Abstract]
Service cost		24,000	23,000	48,000	44,000
Interest cost		1,814,000	1,911,000	3,565,000	3,686,000
Expected return on plan assets		(109,000)	(144,000)	(219,000)	(288,000)
Amortization of transition obligation		336,000	336,000	673,000	673,000
Amortization of prior service cost (credit)		(30,000)	(30,000)	(59,000)	(59,000)
Amortization of net loss		853,000	607,000	1,602,000	1,174,000
Net periodic benefit cost		2,888,000	2,703,000	5,610,000	5,230,000
Net benefit cost recognized for financial reporting		2,888,000	2,703,000	5,610,000	5,230,000
Xcel Energy Inc. [Member] | Pension Benefits [Member]
Components of Net Periodic Benefit Cost [Abstract]
Total contributions to Xcel Energy's pension plans during the period	$ 190,500,000
Number of Xcel Energy's pension plans to which contributions were made	4

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Benefit Plans and Other Postretirement Benefits

6 Months Ended

Jun. 30, 2012

Benefit Plans and Other Postretirement Benefits [Abstract]

Benefit Plans and Other Postretirement Benefits

11.  Benefit Plans and Other Postretirement Benefits

  

Components of Net Periodic Benefit Cost

	Three Months Ended June 30
	2012			2011			2012			2011
							Postretirement Health
(Thousands of Dollars)	Pension Benefits						Care Benefits
Service cost	$	7,336		$	8,015		$	24		$	23
Interest cost		12,301			13,043			1,814			1,911
Expected return on plan assets		(16,836	)		(18,528	)		(109	)		(144	)
Amortization of transition obligation		-			-			336			336
Amortization of prior service cost (credit)		2,955			3,293			(30	)		(30	)
Amortization of net loss		10,196			7,707			853			607
Net periodic benefit cost		15,952			13,530			2,888			2,703
Cost not recognized due to the effects of regulation		(9,083	)		(10,140	)		-			-
Net benefit cost recognized for financial reporting	$	6,869		$	3,390		$	2,888		$	2,703

	Six Months Ended June 30
	2012			2011			2012			2011
							Postretirement Health
(Thousands of Dollars)	Pension Benefits						Care Benefits
Service cost	$	14,706		$	14,008		$	48		$	44
Interest cost		24,610			25,973			3,565			3,686
Expected return on plan assets		(33,658	)		(37,121	)		(219	)		(288	)
Amortization of transition obligation		-			-			673			673
Amortization of prior service cost (credit)		5,910			6,585			(59	)		(59	)
Amortization of net loss		20,065			14,368			1,602			1,174
Net periodic benefit cost		31,633			23,813			5,610			5,230
Cost not recognized due to the effects of regulation		(17,141	)		(17,450	)		-			-
Net benefit cost recognized for financial reporting	$	14,492		$	6,363		$	5,610		$	5,230

In January 2012, contributions of $190.5 million were made across four of Xcel Energy's pension plans, of which $79.3 million was attributable to NSP-Minnesota.  Xcel Energy does not expect additional pension contributions during 2012.

In June 2012, to manage volatility in equity pricing within the pension master trust, Xcel Energy entered into equity collar contracts with a net-zero cost at initiation on a portion of the equity securities.  The equity collar strategy is designed to reduce potential equity losses while limiting gains, resulting in lower equity volatility for the pension plans.  At June 30, 2012, the mark-to-market value of these arrangements was not material to the value of the pension trust assets.  These arrangements will expire in December 2012.