form10q.htm

10-Q 1 form10q.htm NORTHERN STATES POWER COMPANY MINNESOTA 10-Q 3-31-2013 form10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2013

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 May 6, 2013
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	32

PART II —	OTHER INFORMATION

Item 1 —	Legal Proceedings	32
Item 1A —	Risk Factors	32
Item 4 —	Mine Safety Disclosures	32
Item 5 —	Other Information	32
Item 6 —	Exhibits	33

SIGNATURES		34

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 (PSCo); and Southwestern Public Service Company (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 March 31
	2013			2012
Operating revenues
Electric, non-affiliates	$	841,176		$	765,433
Electric, affiliates		110,138			108,951
Natural gas		235,286			196,514
Other		6,635			5,875
Total operating revenues		1,193,235			1,076,773

Operating expenses
Electric fuel and purchased power		388,901			365,328
Cost of natural gas sold and transported		158,770			134,190
Cost of sales — other		3,575			3,117
Operating and maintenance expenses		273,280			261,030
Conservation program expenses		24,879			27,684
Depreciation and amortization		109,085			98,980
Taxes (other than income taxes)		59,455			53,768
Total operating expenses		1,017,945			944,097

Operating income		175,290			132,676

Other income, net		2,153			2,405
Allowance for funds used during construction — equity		10,262			8,035

Interest charges and financing costs
Interest charges — includes other financing costs of $1,486 and $1,477, respectively		45,114			52,120
Allowance for funds used during construction — debt		(4,589	)		(4,278	)
Total interest charges and financing costs		40,525			47,842

Income before income taxes		147,180			95,274
Income taxes		45,215			18,288
Net income	$	101,965		$	76,986

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 March 31
	2013			2012

Net income	$	101,965		$	76,986

Other comprehensive (loss) income

Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost,net of tax of $15 and $26, respectively		24			37

Derivative instruments:
Net fair value increase, net of tax of $8 and $8,517, respectively		5			12,373
Reclassification of losses (gains) to net income, net of tax of $135 and $(22), respectively		193			(33	)
		198			12,340
Marketable securities:
Net fair value (decrease) increase, net of tax of $(22) and $36, respectively		(32	)		52
Other comprehensive income		190			12,429
Comprehensive income	$	102,155		$	89,415

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Three Months Ended March 31
	2013			2012
Operating activities
Net income	$	101,965		$	76,986
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		110,327			100,173
Nuclear fuel amortization		27,522			26,000
Deferred income taxes		53,338			62,025
Amortization of investment tax credits		(670	)		(675	)
Allowance for equity funds used during construction		(10,262	)		(8,035	)
Net realized and unrealized hedging and derivative transactions		(607	)		(361	)
Changes in operating assets and liabilities:
Accounts receivable		(25,251	)		(86,112	)
Accrued unbilled revenues		25,672			63,486
Inventories		33,946			67,420
Other current assets		(23,131	)		(31,155	)
Accounts payable		11,242			(63,414	)
Net regulatory assets and liabilities		19,685			20,904
Other current liabilities		38,294			8,531
Pension and other employee benefit obligations		(69,407	)		(77,603	)
Change in other noncurrent assets		17,652			(23,427	)
Change in other noncurrent liabilities		(3,900	)		(2,053	)
Net cash provided by operating activities		306,415			132,690

Investing activities
Utility capital/construction expenditures		(376,588	)		(221,874	)
Proceeds from insurance recoveries		23,500			-
Allowance for equity funds used during construction		10,262			8,035
Purchases of investments in external decommissioning fund		(586,239	)		(213,618	)
Proceeds from the sale of investments in external decommissioning fund		584,948			213,618
Investments in utility money pool arrangement		(20,000	)		-
Repayments from utility money pool arrangement		20,000			-
Change in restricted cash		-			86,232
Other, net.		(2,284	)		(2,488	)
Net cash used in investing activities		(346,401	)		(130,095	)

Financing activities
(Repayments of) proceeds from short-term borrowings, net		(176,000	)		2,000
Borrowings under utility money pool arrangement		238,000			229,000
Repayments under utility money pool arrangement		(58,000	)		(253,000	)
Proceeds from issuance of long-term debt		52			-
Capital contributions from parent		120,000			100,000
Dividends paid to parent		(58,757	)		(58,054	)
Net cash provided by financing activities		65,295			19,946

Net change in cash and cash equivalents		25,309			22,541
Cash and cash equivalents at beginning of period		28,842			26,005
Cash and cash equivalents at end of period	$	54,151		$	48,546

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(61,296	)	$	(76,530	)
Cash received (paid) for income taxes, net		31,362			(8,199	)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	120,689		$	129,499

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

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

	March 31, 2013			Dec. 31, 2012
Assets
Current assets
Cash and cash equivalents	$	54,151		$	28,842
Accounts receivable, net		352,269			325,143
Accounts receivable from affiliates		23,744			26,660
Accrued unbilled revenues		203,992			229,664
Inventories		226,812			260,758
Regulatory assets		164,380			156,223
Derivative instruments		47,424			56,232
Prepayments and other		153,482			94,019
Total current assets		1,226,254			1,177,541

Property, plant and equipment, net		9,747,142			9,546,968

Other assets
Nuclear decommissioning fund and other investments		1,560,902			1,514,156
Regulatory assets		1,021,942			1,039,675
Derivative instruments		55,284			66,480
Other		38,236			56,438
Total other assets		2,676,364			2,676,749
Total assets	$	13,649,760		$	13,401,258

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	6		$	2
Short-term debt		45,000			221,000
Borrowings under utility money pool arrangement		180,000			-
Accounts payable		387,921			367,021
Accounts payable to affiliates		56,237			69,739
Regulatory liabilities		49,866			53,159
Taxes accrued		230,329			175,929
Accrued interest		36,054			58,135
Dividends payable to parent		58,690			58,757
Derivative instruments		19,330			20,117
Other		93,839			102,915
Total current liabilities		1,157,272			1,126,774

Deferred credits and other liabilities
Deferred income taxes		2,036,960			1,944,910
Deferred investment tax credits		29,829			30,304
Regulatory liabilities		436,892			432,471
Asset retirement obligations		1,676,487			1,655,402
Derivative instruments		165,428			174,471
Pension and employee benefit obligations		353,013			422,496
Other		105,178			89,423
Total deferred credits and other liabilities		4,803,787			4,749,477

Commitments and contingencies
Capitalization
Long-term debt		3,488,867			3,488,638
Common stock – authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares outstanding at March 31, 2013 and Dec. 31, 2012, respectively		10			10
Additional paid in capital		2,701,501			2,581,501
Retained earnings		1,521,332			1,478,057
Accumulated other comprehensive loss		(23,009	)		(23,199	)
Total common stockholder's equity		4,199,834			4,036,369
Total liabilities and equity	$	13,649,760		$	13,401,258

See Notes to Consolidated Financial Statements

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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 March 31, 2013 and Dec. 31, 2012; the results of its operations, including the components of net income and comprehensive income, for the three months ended March 31, 2013 and 2012; and its cash flows for the three months ended March 31, 2013 and 2012. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2013 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, 2012 balance sheet information has been derived from the audited 2012 consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2012. 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, 2012, filed with the SEC on Feb. 25, 2013. 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, 2012, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2.	Accounting Pronouncements

Recently Adopted

Balance Sheet Offsetting — In December 2011, the Financial Accounting Standards Board (FASB) issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (Accounting Standards Update (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. In January 2013, the FASB issued Balance Sheet (Topic 210) – Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU No. 2013-01) to clarify the specific instruments that should be considered in these disclosures. These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets, and were effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods. NSP-Minnesota implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements. See Note 8 for the required disclosures.

Comprehensive Income Disclosures — In February 2013, the FASB issued Comprehensive Income (Topic 220) — Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (ASU No. 2013-02), which requires detailed disclosures regarding changes in components of accumulated other comprehensive income and amounts reclassified out of accumulated other comprehensive income. These disclosure requirements do not change how net income or comprehensive income are presented in the consolidated financial statements. These disclosure requirements were effective for annual reporting periods beginning on or after Dec. 15, 2012, and interim periods within those annual reporting periods. NSP-Minnesota implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements. See Note 12 for the required disclosures.

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3.	Selected Balance Sheet Data

(Thousands of Dollars)	March 31, 2013			Dec. 31, 2012
Accounts receivable, net
Accounts receivable	$	371,985		$	345,563
Less allowance for bad debts		(19,716	)		(20,420	)
	$	352,269		$	325,143

(Thousands of Dollars)	March 31, 2013		Dec. 31, 2012
Inventories
Materials and supplies	$	135,563	$	134,952
Fuel		75,085		80,307
Natural gas		16,164		45,499
	$	226,812	$	260,758

(Thousands of Dollars)	March 31, 2013			Dec. 31, 2012
Property, plant and equipment, net
Electric plant	$	12,366,058		$	12,322,677
Natural gas plant		1,031,918			1,027,632
Common and other property		489,695			493,322
Construction work in progress		1,172,173			951,199
Total property, plant and equipment		15,059,844			14,794,830
Less accumulated depreciation		(5,649,369	)		(5,594,064	)
Nuclear fuel		2,108,788			2,090,801
Less accumulated amortization		(1,772,121	)		(1,744,599	)
	$	9,747,142		$	9,546,968

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, 2012 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 2008 federal income tax return expired in September 2012. The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in June 2015. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011. As of March 31, 2013, the IRS had not proposed any material adjustments to tax years 2010 and 2011.

State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of March 31, 2013, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate (ETR). In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

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

(Millions of Dollars)	March 31, 2013		Dec. 31, 2012
Unrecognized tax benefit — Permanent tax positions	$	5.1	$	2.8
Unrecognized tax benefit — Temporary tax positions		17.3		16.7
Total unrecognized tax benefit	$	22.4	$	19.5

The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:

(Millions of Dollars)		March 31, 2013				Dec. 31, 2012
NOL and tax credit carryforwards		$	(18.0	)		$	(16.8	)

It is reasonably possible that NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $21 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at March 31, 2013 and Dec. 31, 2012 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2013 or Dec. 31, 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, 2012 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Pending Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)

Base Rate

Minnesota 2012 Electric Rate Case — In November 2012, NSP-Minnesota filed a request with the MPUC to increase electric rates approximately $285 million, or 10.7 percent. The rate filing was based on a 2013 forecast test year, a requested return on equity (ROE) of 10.6 percent, an average electric rate base of approximately $6.3 billion and an equity ratio of 52.56 percent. In January 2013, interim rates of approximately $251 million became effective, subject to refund.

On Feb. 28, 2013, intervening parties filed direct testimony proposing modifications to NSP-Minnesota’s rate request. The Minnesota Department of Commerce (DOC) recommended an increase of approximately $93.6 million, based on a recommended ROE of 10.24 percent and an equity ratio of 52.56 percent. Seven other intervenors filed testimony recommending various adjustments, some similar to the DOC, but no other party made a comprehensive analysis of all rate case elements. See the summary of DOC recommendations below.

On March 25, 2013, NSP-Minnesota filed rebuttal testimony and revised the requested annual revenue increase to approximately $219.7 million, or 8.23 percent, based on an ROE of 10.6 percent, a rate base of approximately $6.3 billion and an equity ratio of 52.56 percent. The updated request reflects alternate proposals in several key areas including deferral and removal of certain costs related to Sherco 3 and to Monticello, as well as removal of costs for cancellation of the Prairie Island Extended Power Uprate (EPU) project. Additional adjustments were made for compensation and benefits, amortization of pension market losses and Black Dog remediation costs. NSP-Minnesota’s updated request also reflects more recent information on property taxes and sales forecast, as well as data corrections to the original filing.

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On April 12, 2013, intervenors including the DOC, Office of Attorney General (OAG), Minnesota Chamber (MCC), Xcel Large Industrials (XLI), Commercial Group, Industrial, Commercial and Institutional Customers, and Energy Cents Coalition filed surrebuttal testimony. The DOC recommended a revenue increase of $89.6 million, based on a 9.83 percent ROE, an average electric rate base of approximately $6.1 billion and an equity ratio of 52.56 percent. The following table summarizes the effect of the DOC’s recommendations on NSP-Minnesota’s original request:

(Millions of Dollars)	DOC Direct Testimony February 2013			DOC Surrebuttal Testimony April 2013
NSP-Minnesota's original request	$	285		$	285
ROE		(20	)		(44	)
Sherco Unit 3		(39	)		(44	)
Reduced recovery for the nuclear plants		(9	)		(5	)
Elimination of certain incentive compensation		(25	)		(20	)
Increase to the sales forecast		(24	)		(26	)
Reduced recovery of pension		(25	)		(25	)
Employee benefits		(11	)		(6	)
Other, net		(38	)		(25	)
DOC recommendation	$	94		$	90

In its surrebuttal testimony, the OAG recommends, among other things, no recovery for the Prairie Island EPU project, stating it should have been written off in 2012 when cancellation was approved by the MPUC on Dec. 20, 2012. The DOC is also not supportive of recovery of the Prairie Island EPU cancelled plant costs, but identifies requirements for the next case if deferral is allowed. The OAG suggests pension recovery in rates exceeds benefit payout because of changes made to benefit plans and recommends correction for an alleged over-collection of funds to pay for future benefits which may never be paid out. The OAG supports the DOC in adjustments to recovery of annual incentive compensation and does not find NSP-Minnesota’s Sherco 3 proposal warranted. Other intervenors maintained their primary positions with various adjustments and recommendations for class responsibility and rate design. XLI and MCC opposed recovery of Sherco 3 costs and Monticello EPU costs.

Hearings were held in April and NSP-Minnesota revised its rate request to approximately $215.4 million to reflect updated property tax information and other adjustments. Also at the hearings, the DOC’s recommendation was revised to approximately $98.6 million, largely to reflect updated information. NSP-Minnesota has recognized a liability representing its best estimate of any refund obligation.

Next steps in the procedural schedule are expected to be as follows:

Initial Brief – May 15, 2013

Reply Brief and Findings of Fact – May 30, 2013

Administrative Law Judge (ALJ) Report – July 3, 2013

MPUC Order – Anticipated by September 2013

Pending Regulatory Proceedings — North Dakota Public Service Commission (NDPSC)

Base Rate

North Dakota 2012 Electric Rate Case — In December 2012, NSP-Minnesota filed a request with the NDPSC to increase annual retail electric rates approximately $16.9 million, or 9.25 percent. The rate filing is based on a 2013 forecast test year, a requested ROE of 10.6 percent, an electric rate base of approximately $377.6 million and an equity ratio of 52.56 percent. In January 2013, the NDPSC approved an interim electric increase of $14.7 million, effective Feb. 16, 2013, subject to refund.

Next steps in the procedural schedule are expected to be as follows:

Staff/Intervenor Direct Testimony – July 12, 2013

Rebuttal Testimony – Aug. 12, 2013

Technical Hearings – Aug. 27-28, 2013

Initial Briefs – Sept. 20, 2013

Reply Briefs/Proposed Findings – October 2013

A final NDPSC decision on the case is expected in the fourth quarter of 2013.

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

Base Rate

South Dakota 2012 Electric Rate Case — In June 2012, NSP-Minnesota filed a request with the SDPUC to increase electric rates by $19.4 million annually. The request was based on a 2011 historic test year adjusted for known and measurable changes, a requested ROE of 10.65 percent, an average rate base of $367.5 million and an equity ratio of 52.89 percent. Interim rates of $19.4 million went into effect on Jan. 1, 2013, subject to refund.

In March 2013, NSP-Minnesota and the SDPUC Staff reached a settlement agreement that provides for a base rate increase of approximately $11.6 million and the implementation of a new rider to recover an additional $3.7 million for certain capital projects and incremental property taxes. Combined, the overall revenue increase for 2013 is approximately $15.3 million, or 9.1 percent. The rider is subject to true-up for actual costs and is projected to provide incremental revenue of $2.6 million in 2014. The settlement agreement also includes a moratorium on base rate increases, effective until Jan. 1, 2015. The settlement was approved by the SDPUC on April 9, 2013. Implementation of new rates and the rider began on May 1, 2013.

6.	Commitments and Contingencies

Except to the extent 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, 2012 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 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 March 31, 2013 and Dec. 31, 2012 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.

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 was capped at $20 million under the agreement. The indemnification obligation expired in March 2013.

Environmental Contingencies

Environmental Requirements

Cross-State Air Pollution Rule (CSAPR) — In 2011, the U.S. Environmental Protection Agency (EPA) issued the 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 in the eastern half of the United States, including Minnesota. The CSAPR would have set more stringent requirements than the proposed Clean Air Transport Rule. The rule also would have created an emissions trading program.

In August 2012, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit also stated that the EPA must continue administering the Clean Air Interstate Rule (CAIR) pending adoption of a valid replacement. In October 2012, the EPA, as well as state and local governments and environmental advocates, petitioned the D.C. Circuit to rehear the CSAPR appeal. In January 2013, the D.C. Circuit denied all requests for rehearing. In March 2013, the EPA and a coalition of environmental advocacy groups separately petitioned for U.S. Supreme Court review of the CSAPR decision. It is not known whether the Supreme Court will decide to review the D.C. Circuit’s decision.

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CAIR — In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions. The CAIR does not currently apply to Minnesota.

Regional Haze Rules — In 2005, the EPA finalized amendments to its regional haze rules, known as best available retrofit technology (BART), which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. 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 2009, the Minnesota Pollution Control Agency (MPCA) approved the state implementation plan (SIP) and submitted it 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 source-specific 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. The scrubber upgrades are underway and scheduled to be completed by January 2015.

The EPA’s preliminary review of the SIP in 2011 indicated that SCR controls should be added to Sherco Units 1 and 2. Subsequently, the EPA and MPCA both determined that CSAPR meets BART requirements for purposes of the SIP. In addition, the MPCA retained its source-specific BART determination for Sherco Units 1 and 2 from the 2009 SIP. The EPA approved the SIP for electric generating units, and also approved the source-specific emission limits for Sherco Units 1 and 2 as strengthening the SIP, but avoided characterizing them as BART limits.

In August 2012, the National Parks Conservation Association, Sierra Club, Voyageurs National Park Association, Friends of the Boundary Waters Wilderness, Minnesota Center for Environmental Advocacy and Fresh Energy appealed the EPA’s approval of the SIP to the U.S. Court of Appeals for the Eighth Circuit. The Court denied intervention in the case to NSP-Minnesota and other regulated parties who petitioned to intervene. It is not yet known how the D.C. Circuit’s reversal of the CSAPR may impact the EPA’s approval of the SIP.

The estimated cost for meeting the BART, regional haze and other Clean Air Act requirements is approximately $50 million, of which $32 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. If the above litigation results in further EPA proceedings concerning the SIP, such proceedings may consider whether SCRs should be required for Sherco Units 1 and 2.

In addition to the regional haze rules, there are other visibility rules related to a program called the Reasonably Attributable Visibility Impairment (RAVI) program. In 2009, the U.S. Department of the Interior certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota’s Sherco Units 1 and 2. The EPA is required to 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 December 2012, a lawsuit against the EPA was filed in the U.S. District Court for the District of Minnesota by the following organizations: National Parks Conservation Association, Minnesota Center for Environmental Advocacy, Friends of the Boundary Waters Wilderness, Voyageurs National Park Association, Fresh Energy and Sierra Club. The lawsuit alleges that the EPA has failed to perform a nondiscretionary duty to determine BART for the Sherco Units 1 and 2 under the RAVI program. The EPA filed an answer denying the allegations and asserting that it did not have a nondiscretionary duty under the RAVI program. NSP-Minnesota has requested the Court to allow it to intervene in this litigation. The Court has not yet ruled on NSP-Minnesota’s motion.

Legal Contingencies

NSP-Minnesota is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on NSP-Minnesota’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

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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 the U.S. District Court for the Northern District of California against Xcel Energy and 23 other utility, oil, gas and coal companies. Plaintiffs claim that defendants’ emission of carbon dioxide (CO2) and other greenhouse gases contribute to global warming, which is harming their village. Xcel Energy 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 October 2012, the Ninth Circuit affirmed the U.S. District Court’s dismissal and subsequently rejected plaintiffs’ request for rehearing. Plaintiffs subsequently filed a petition for review with the United States Supreme Court. It is unknown whether the United States Supreme Court will grant this petition. 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. Although Xcel Energy believes the likelihood of loss is remote based primarily on existing case law, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. 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 the 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., SPS, PSCo, NSP-Wisconsin and NSP-Minnesota. The amount of damages claimed by plaintiffs is unknown. The defendants 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. Oral arguments occurred in May 2013. It is uncertain when the Fifth Circuit will issue its decision. Although Xcel Energy believes the likelihood of loss is remote based primarily on existing case law, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. 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 the U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreements. enXco also filed a separate lawsuit in the same court seeking approximately $240 million for an alleged breach of contract. NSP-Minnesota believes enXco’s lawsuit is without merit. On Oct. 22, 2012, NSP-Minnesota filed a motion for summary judgment. In April 2013, the U.S. District Court granted NSP-Minnesota’s motion and entered judgment in its favor. On April 23, 2013 enXco filed a notice of appeal to the Eighth Circuit. It is uncertain when the Eighth Circuit will decide this appeal. Although Xcel Energy believes the likelihood of loss is remote based on existing case law and the U.S. District Court’s April 2013 decision, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. No accrual has been recorded for this matter.

Nuclear Power Operations and Waste Disposal

Nuclear Waste Disposal Litigation — In 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the United States requesting breach of contract damages for the U.S. Department of Energy’s (DOE) failure to begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contract between the United States and NSP-Minnesota. NSP-Minnesota sought contract damages in this lawsuit through Dec. 31, 2004. In September 2007, the court awarded NSP-Minnesota $116.5 million in damages. In August 2007, NSP-Minnesota filed a second complaint; this lawsuit claimed damages for the period Jan. 1, 2005 through Dec. 31, 2008.

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In July 2011, the United States and NSP-Minnesota executed a settlement agreement resolving both lawsuits, providing an initial $100 million payment from the United States to NSP-Minnesota, and providing a method by which NSP-Minnesota can recover its spent fuel storage costs through 2013, estimated to be an additional $100 million. The settlement does not address costs for used fuel storage after 2013; such costs could be the subject of future litigation. NSP-Minnesota received the initial $100 million payment in August 2011, the second installment of $18.6 million in March 2012, and the third installment of $20.7 million in October 2012. Amounts were subsequently credited to customers, except for approved reductions such as legal costs, customer credit amounts still in process at March 31, 2013, and amounts set aside to be credited through another regulatory mechanism.

In NSP-Wisconsin’s 2012 Electric and Gas Rate Case, the Public Service Commission of Wisconsin (PSCW) authorized NSP-Wisconsin to utilize the proceeds from the second and third installments to be included as a reduction of the 2013 electric rate increase. In December 2012, the MPUC approved NSP-Minnesota’s triennial nuclear decommissioning filing which required NSP-Minnesota to place the Minnesota retail portion of the DOE settlement payments for the third installment of $15.3 million and the anticipated fourth installment in 2013 into the nuclear decommissioning fund when received. NSP-Minnesota proposed to contribute the second, third and fourth installments to the nuclear decommissioning fund to offset the increase in the decommissioning accrual that was included in the 2012 North Dakota electric rate case. That filing is pending NDPSC action.

7.	Borrowings and Other Financing Instruments

Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. Money pool borrowings for NSP-Minnesota were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	250		$	250
Amount outstanding at period end		180			-
Average amount outstanding		13			56
Maximum amount outstanding		196			236
Weighted average interest rate, computed on a daily basis		0.34	%		0.33	%
Weighted average interest rate at period end		0.34			N/A

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	500		$	500
Amount outstanding at period end		45			221
Average amount outstanding		257			59
Maximum amount outstanding		347			302
Weighted average interest rate, computed on a daily basis		0.36	%		0.39	%
Weighted average interest rate at period end		0.34			0.39

Letters of Credit — NSP-Minnesota uses letters of credit, generally with terms of one-year, to provide financial guarantees for certain operating obligations. At March 31, 2013 and Dec. 31, 2012, there were $11.2 million and $10.2 million of letters of credit outstanding, respectively, under the credit facility. All letters of credit outstanding were issued under the credit facilities at March 31, 2013 and Dec. 31, 2012. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

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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 this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At March 31, 2013, NSP-Minnesota had the following committed credit facility available (in millions):

Credit Facility (a)				Drawn (b)				Available
$	500.0			$	56.2			$	443.8

(a)	Credit facility expires in July 2017.

(b)	Includes outstanding commercial paper and letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. NSP-Minnesota had no direct advances on the credit facility outstanding at March 31, 2013 and Dec. 31, 2012.

8.	Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with 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 also utilizes additional inputs in a discounted cash flow model, including forecasted prepayments and risk adjusted discounting.

Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

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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 or obligate 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 energy congestion, which is caused by overall transmission load and other transmission constraints. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. NSP-Minnesota’s valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model – including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3. 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.

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. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. The MPUC approved NSP-Minnesota’s proposed change in escrow fund investment strategy in September 2012. The MPUC approved an asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust.

NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning.

Unrealized gains for the nuclear decommissioning fund were $171.3 million and $135.8 million at March 31, 2013 and Dec. 31, 2012, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $49.6 million and $46.4 million at March 31, 2013 and Dec. 31, 2012, 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, at March 31, 2013 and Dec. 31, 2012:

	March 31, 2013
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	94,131	$	88,759	$	5,372	$	-	$	94,131
Commingled funds		422,333		-		442,976		-		442,976
International equity funds		67,032		-		70,587		-		70,587
Private equity investments		29,199		-		-		34,506		34,506
Real estate		33,048		-		-		40,406		40,406
Debt securities:
Government securities		16,375		-		16,464		-		16,464
U.S. corporate bonds		210,505		-		216,318		-		216,318
International corporate bonds		18,562		-		19,226		-		19,226
Municipal bonds		103,090		-		103,837		-		103,837
Asset-backed securities		1,636		-		1,636		-		1,636
Mortgage-backed securities		4,627		-		5,106		-		5,106
Equity securities:
Common stock		411,751		488,811		-		-		488,811
Total	$	1,412,289	$	577,570	$	881,522	$	74,912	$	1,534,004

(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $26.9 million of miscellaneous investments.

	Dec. 31, 2012
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	246,904	$	237,938	$	8,966	$	-	$	246,904
Commingled funds		396,681		-		417,583		-		417,583
International equity funds		66,452		-		69,481		-		69,481
Private equity investments		27,943		-		-		33,250		33,250
Real estate		32,561		-		-		39,074		39,074
Debt securities:
Government securities		21,092		-		21,521		-		21,521
U.S. corporate bonds		162,053		-		169,488		-		169,488
International corporate bonds		15,165		-		16,052		-		16,052
Municipal bonds		21,392		-		23,650		-		23,650
Asset-backed securities		2,066		-		-		2,067		2,067
Mortgage-backed securities		28,743		-		-		30,209		30,209
Equity securities:
Common stock		379,093		420,263		-		-		420,263
Total	$	1,400,145	$	658,201	$	726,741	$	104,600	$	1,489,542

(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $24.6 million of miscellaneous investments.

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The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three months ended March 31, 2013 and 2012:

(Thousands of Dollars)	Jan. 1, 2013		Purchases		Settlements			Gains Recognized as Regulatory Liabilities		Transfers Out of Level 3 (a)			March 31, 2013
Private equity investments	$	33,250	$	1,256	$	-		$	-	$	-		$	34,506
Real estate		39,074		4,786		(4,299	)		845		-			40,406
Asset-backed securities		2,067		-		-			-		(2,067	)		-
Mortgage-backed securities		30,209		-		-			-		(30,209	)		-
Total	$	104,600	$	6,042	$	(4,299	)	$	845	$	(32,276	)	$	74,912

(a)	Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements.

(Thousands of Dollars)	Jan. 1, 2012		Purchases		Settlements			Gains (Losses) Recognized as Regulatory Assets and Liabilities			Transfers Out of Level 3		March 31, 2012
Private equity investments	$	9,203	$	10,155	$	-		$	710		$	-	$	20,068
Real estate		26,395		1,636		(1,766	)		1,640			-		27,905
Asset-backed securities		16,501		-		(1	)		47			-		16,547
Mortgage-backed securities		78,664		6,904		(16,728	)		(169	)		-		68,671
Total	$	130,763	$	18,695	$	(18,495	)	$	2,228		$	-	$	133,191

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, at March 31, 2013:

	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	$	-	$	2,498	$	10,165	$	3,801	$	16,464
U.S. corporate bonds		1,441		40,952		92,076		81,849		216,318
International corporate bonds		-		4,300		13,746		1,180		19,226
Municipal bonds		829		16,628		21,917		64,463		103,837
Asset-backed securities		-		1,636		-		-		1,636
Mortgage-backed securities		-		-		-		5,106		5,106
Debt securities	$	2,270	$	66,014	$	137,904	$	156,399	$	362,587

Derivative Instruments Fair Value Measurements

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

Interest Rate Derivatives — NSP-Minnesota enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.

At March 31, 2013, accumulated other comprehensive losses related to interest rate derivatives included $0.8 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for any unsettled hedges.

Wholesale and Commodity Trading Risk — NSP-Minnesota conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. NSP-Minnesota’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

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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 March 31, 2013, NSP-Minnesota had various vehicle fuel contracts designated as cash flow hedges extending through December 2016. NSP-Minnesota also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. NSP-Minnesota recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three months ended March 31, 2013 and 2012.

At March 31, 2013, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million 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 March 31, 2013 and Dec. 31, 2012:

(Amounts in Thousands) (a)(b)	March 31, 2013		Dec. 31, 2012
Megawatt hours (MWh) of electricity		30,966		55,163
Million British thermal units (MMBtu) of natural gas		-		26
Gallons of vehicle fuel		347		375

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

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

Consideration of Credit Risk and Concentrations — NSP-Minnesota continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of NSP-Minnesota’s own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.

NSP-Minnesota employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

NSP-Minnesota’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. At March 31, 2013, eight of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $39.9 million or 36 percent of this credit exposure at March 31, 2013, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. The remaining two significant counterparties, comprising $9.0 million or 8 percent of this credit exposure at March 31, 2013, were not rated by these agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade. All 10 of these significant counterparties are municipal or cooperative electric entities, or other utilities.

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Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on NSP-Minnesota’s accumulated other comprehensive loss, included as a component of common stockholder’s equity and in the consolidated statements of comprehensive income, is detailed in the following table:

	Three Months Ended March 31
(Thousands of Dollars)	2013			2012
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(21,393	)	$	(11,729	)
After-tax net unrealized gains related to derivatives accounted for as hedges		5			12,373
After-tax net realized losses (gains) on derivative transactions reclassified into earnings		193			(33	)
Accumulated other comprehensive (loss) income related to cash flow hedges at March 31	$	(21,195	)	$	611

The following tables detail the impact of derivative activity during the three months ended March 31, 2013 and 2012, on accumulated other comprehensive loss, regulatory assets and liabilities and income:

	Three Months Ended March 31, 2013
	Pre-Tax Fair Value				Pre-Tax (Gains) Losses
	Gains (Losses) Recognized				Reclassified into Income
	During the Period in:				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	$	-	$	-	$	342	(a)	$	-		$	-
Vehicle fuel and other commodity		13		-		(14	) (e)		-			-
Total	$	13	$	-	$	328		$	-		$	-

Other derivative instruments
Commodity trading	$	-	$	-	$	-		$	-		$	2,776	(b)
Electric commodity		-		6,419		-			(15,229	) (c)		-
Natural gas commodity		-		2		-			-			-
Total	$	-	$	6,421	$	-		$	(15,229	)	$	2,776

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	Three Months Ended March 31, 2012
	Pre-Tax Fair Value					Pre-Tax (Gains) Losses
	Gains (Losses) Recognized					Reclassified into Income
	During the Period in:					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	$	20,787	$	-		$	(27	) (a)	$	-		$	-
Vehicle fuel and other commodity		103		-			(28	) (e)		-			-
Total	$	20,890	$	-		$	(55	)	$	-		$	-

Other derivative instruments
Commodity trading	$	-	$	-		$	-		$	-		$	1,723	(b)
Electric commodity		-		1,582			-			(7,972	) (c)		-
Natural gas commodity		-		(2,660	)		-			16,158	(d)		-
Total	$	-	$	(1,078	)	$	-		$	8,186		$	1,723

(a)	Amounts are recorded to interest charges.

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

(c)	Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

(d)	Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

(e)	Amounts are recorded to operating and maintenance (O&M) expenses.

NSP-Minnesota had no derivative instruments designated as fair value hedges during the three months ended March 31, 2013 and 2012. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Credit Related Contingent Features — Contract provisions for derivative instruments that NSP-Minnesota enters into, including those recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale (NPNS) contracts and therefore not reflected on the balance sheet, may require the posting of collateral or settlement of the contracts for various reasons, including if NSP-Minnesota is unable to maintain its credit ratings. If the credit ratings of NSP-Minnesota were downgraded below investment grade, derivative instruments reflected in a $19.3 million gross liability position on the consolidated balance sheet at March 31, 2013 would have required NSP-Minnesota to post collateral or settle outstanding contracts, including other contracts subject to master netting agreements; due to offsetting asset positions, no payments would be required at March 31, 2013. At March 31, 2013 there was no collateral posted on these specific contracts. At Dec. 31, 2012, no derivative instruments in a liability position would have required the posting of collateral or settlement of outstanding contracts if the credit ratings of NSP-Minnesota were downgraded below investment grade.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that NSP-Minnesota’s ability to fulfill its contractual obligations is reasonably expected to be impaired. NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts as of March 31, 2013 and Dec. 31, 2012.

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Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at March 31, 2013:

	March 31, 2013
	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	$	-	$	51	$	-	$	51	$	-		$	51
Other derivative instruments:
Commodity trading		-		18,986		509		19,495		(2,303	)		17,192
Electric commodity		-		-		7,449		7,449		(377	)		7,072
Total current derivative assets	$	-	$	19,037	$	7,958	$	26,995	$	(2,680	)		24,315
Purchased power agreements (a)													23,109
Current derivative instruments												$	47,424
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	48	$	-	$	48	$	(48	)	$	-
Other derivative instruments:
Commodity trading		-		31,726		74		31,800		(2,246	)		29,554
Total noncurrent derivative assets	$	-	$	31,774	$	74	$	31,848	$	(2,294	)		29,554
Purchased power agreements (a)													25,730
Noncurrent derivative instruments												$	55,284
Current derivative liabilities
Derivatives designated as cash flow hedges:
Other derivative instruments:
Commodity trading	$	-	$	10,803	$	13	$	10,816	$	(5,337	)	$	5,479
Electric commodity		-		-		377		377		(377	)		-
Total current derivative liabilities	$	-	$	10,803	$	390	$	11,193	$	(5,714	)		5,479
Purchased power agreements (a)													13,851
Current derivative instruments												$	19,330
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	-	$	12,017	$	-	$	12,017	$	(2,294	)	$	9,723
Total noncurrent derivative liabilities	$	-	$	12,017	$	-	$	12,017	$	(2,294	)		9,723
Purchased power agreements (a)													155,705
Noncurrent derivative instruments												$	165,428

(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)

NSP-Minnesota nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2013 and Dec. 31, 2012. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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The following table presents for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2012:

	Dec. 31, 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	$	-	$	52	$	-	$	52	$	-		$	52
Other derivative instruments:
Commodity trading		-		19,871		692		20,563		(3,374	)		17,189
Electric commodity		-		-		16,724		16,724		(843	)		15,881
Total current derivative assets	$	-	$	19,923	$	17,416	$	37,339	$	(4,217	)		33,122
Purchased power agreements (a)													23,110
Current derivative instruments												$	56,232
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	47	$	-	$	47	$	(47	)	$	-
Other derivative instruments:
Commodity trading		-		37,513		76		37,589		(2,616	)		34,973
Total noncurrent derivative assets	$	-	$	37,560	$	76	$	37,636	$	(2,663	)		34,973
Purchased power agreements (a)													31,507
Noncurrent derivative instruments												$	66,480
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	-	$	12,664	$	-	$	12,664	$	(6,400	)	$	6,264
Electric commodity		-		-		843		843		(843	)		-
Natural gas commodity		-		2		-		2		-			2
Total current derivative liabilities	$	-	$	12,666	$	843	$	13,509	$	(7,243	)		6,266
Purchased power agreements (a)													13,851
Current derivative instruments												$	20,117
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	-	$	17,966	$	-	$	17,966	$	(2,664	)	$	15,302
Total noncurrent derivative liabilities	$	-	$	17,966	$	-	$	17,966	$	(2,664	)		15,302
Purchased power agreements (a)													159,169
Noncurrent derivative instruments												$	174,471

(a)

(b)

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The following table presents the changes in Level 3 commodity derivatives for the three months ended March 31, 2013 and 2012:

	Three Months Ended March 31
(Thousands of Dollars)	2013			2012
Balance at Jan. 1	$	16,649		$	12,417
Settlements		(12,449	)		(8,884	)
Net transactions recorded during the period:
Losses recognized in earnings (a)		(62	)		(9	)
Gains recognized as regulatory liabilities		3,504			1,800
Balance at March 31	$	7,642		$	5,324

(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 months ended March 31, 2013 and 2012.

Fair Value of Long-Term Debt

As of March 31, 2013 and Dec. 31, 2012, other financial instruments for which the carrying amount did not equal fair value were as follows:

	March 31, 2013				Dec. 31, 2012
	Carrying				Carrying
(Thousands of Dollars)	Amount		Fair Value		Amount		Fair Value
Long-term debt, including current portion	$	3,488,873	$	4,096,330	$	3,488,640	$	4,181,580

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 March 31, 2013 and Dec. 31, 2012, 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, Net

Other income, net consisted of the following:

	Three Months Ended March 31
(Thousands of Dollars)	2013			2012
Interest income	$	3,398		$	3,839
Other nonoperating income		277			304
Insurance policy expense		(1,522	)		(1,738	)
Other income, net	$	2,153		$	2,405

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 segment.

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

NSP-Minnesota’s regulated electric utility segment generates 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.

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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 March 31, 2013
Operating revenues from external customers	$	951,314	$	235,286	$	6,635	$	-		$	1,193,235
Intersegment revenues		135		145		-		(280	)		-
Total revenues	$	951,449	$	235,431	$	6,635	$	(280	)	$	1,193,235
Net income	$	69,998	$	21,138	$	10,829	$	-		$	101,965

	Regulated		Regulated		All		Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other		Eliminations			Total
Three Months Ended March 31, 2012
Operating revenues from external customers	$	874,384	$	196,514	$	5,875	$	-		$	1,076,773
Intersegment revenues		123		241		-		(364	)		-
Total revenues	$	874,507	$	196,755	$	5,875	$	(364	)	$	1,076,773
Net income	$	59,281	$	14,297	$	3,408	$	-		$	76,986

11.	Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three Months Ended March 31
	2013			2012			2013			2012
							Postretirement Health
(Thousands of Dollars)	Pension Benefits						Care Benefits
Service cost	$	8,292		$	7,370		$	30		$	24
Interest cost		10,934			12,309			1,225			1,751
Expected return on plan assets		(15,788	)		(16,822	)		(104	)		(110	)
Amortization of transition obligation		-			-			8			337
Amortization of prior service cost (credit)		514			2,955			(759	)		(29	)
Amortization of net loss		13,247			9,869			1,318			749
Net periodic benefit cost		17,199			15,681			1,718			2,722
Costs not recognized due to the effects of regulation		(6,772	)		(8,058	)		-			-
Net benefit cost recognized for financial reporting	$	10,427		$	7,623		$	1,718		$	2,722

In January 2013, contributions of $191.5 million were made across four of Xcel Energy’s pension plans, of which $72.1 million was attributable to NSP-Minnesota. Xcel Energy does not expect additional pension contributions during 2013.

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12.	Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 2013 were as follows:

(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Unrealized Gains and Losses on Marketable Securities			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(21,393	)	$	(99	)	$	(1,707	)	$	(23,199	)
Other comprehensive income (loss) before reclassifications		5			(32	)		-			(27	)
Losses reclassified from net accumulated other comprehensive loss		193			-			24			217
Net current period other comprehensive income (loss)		198			(32	)		24			190
Accumulated other comprehensive loss at March 31	$	(21,195	)	$	(131	)	$	(1,683	)	$	(23,009	)

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2013 were as follows:

(Thousands of Dollars)	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Gains) losses on cash flow hedges:
Interest rate derivatives	$	342	(a)
Vehicle fuel derivatives		(14	) (b)
Total, pre-tax		328
Tax benefit		(135	)
Total, net of tax		193

Defined benefit pension and postretirement (gains) losses:
Amortization of net loss		85	(c)
Prior service cost		(47	) (c)
Transition obligation		1	(c)
Total, pre-tax		39
Tax benefit		(15	)
Total, net of tax		24

Total amounts reclassified, net of tax	$	217

(a)	Included in interest charges.

(b)	Included in O&M expenses.

(c)	Included in the computation of net periodic pension and post retirement benefit costs. See Note 11 for details regarding these benefit plans.

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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.

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, 2012, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended March 31, 2013.

Results of Operations

NSP-Minnesota’s net income was approximately $102.0 million for the first quarter of 2013, compared with approximately $77.0 million for the same period in 2012. The increase is primarily the result of interim electric rate increases, effective in January 2013 subject to refund, in Minnesota and North Dakota, an electric rate increase in South Dakota, cooler weather and lower interest charges. These increases were partially offset by higher O&M expenses, depreciation expense and property taxes.

Electric Revenues and Margin

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:

	Three Months Ended March 31
(Millions of Dollars)	2013			2012
Electric revenues	$	951			$	874
Electric fuel and purchased power		(389	)			(365	)
Electric margin	$	562			$	509

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The following tables summarize the components of the changes in electric revenues and electric margin for the three months ended March 31:

Electric Revenues

(Millions of Dollars)	2013 vs. 2012
Retail rate increases (Minnesota interim, South Dakota and North Dakota interim)	$	48
Fuel and purchased power cost recovery		14
Transmission revenue		13
Estimated impact of weather		12
Conservation revenue (offset by expenses)		(5	)
2012 leap day impact		(4	)
Other, net		(1	)
Total increase in electric revenues	$	77

Electric Margin

(Millions of Dollars)	2013 vs. 2012
Retail rate increases (Minnesota interim, South Dakota and North Dakota interim)	$	48
Estimated impact of weather		12
Transmission revenue, net of costs		8
Conservation revenue (offset by expenses)		(5	)
2012 leap day impact		(4	)
Trading		(2	)
Other, net		(4	)
Total increase in electric margin	$	53

Natural Gas Revenues and Margin

The cost of natural gas tends to vary with changing sales requirements and the cost of natural gas purchases. However, due to the design of purchased natural gas cost recovery mechanisms to recover current expenses for sales to 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:

	Three Months Ended March 31
(Millions of Dollars)	2013			2012
Natural gas revenues	$	235			$	197
Cost of natural gas sold and transported		(159	)			(134	)
Natural gas margin	$	76			$	63

The following tables summarize the components of the changes in natural gas revenues and natural gas margin for the three months ended March 31:

Natural Gas Revenues

(Millions of Dollars)	2013 vs. 2012
Purchased natural gas adjustment clause recovery	$	25
Estimated impact of weather		11
Conservation revenue (offset by expenses)		2
Total increase in natural gas revenues	$	38

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Natural Gas Margin

(Millions of Dollars)	2013 vs. 2012
Estimated impact of weather	$	11
Conservation revenue (offset by expenses)		2
Total increase in natural gas margin	$	13

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $12.3 million, or 4.7 percent, for the first quarter of 2013 compared with the same period in 2012. The following table summarizes the changes in O&M expenses for the three months ended March 31:

(Millions of Dollars)	2013 vs. 2012
Nuclear outage amortization costs	$	5
Employee benefits		4
Nuclear plant operations costs		3
Total increase in O&M expenses	$	12

Conservation Program Expenses — Conservation program expenses decreased $2.8 million, or 10.1 percent, for the first quarter of 2013 compared with the same period in 2012. The decrease is primarily attributable to the timing of recovery of electric conservation improvement program expenses offset by a higher gas rider rate and higher sales volumes. Conservation program expenses are generally recovered concurrently through riders and base rates.

Depreciation and Amortization — Depreciation and amortization expense increased $10.1 million, or 10.2 percent, for the first quarter of 2013 compared with the same period in 2012. The increase is primarily due to normal system expansion, additional amortization as a result of regulatory outcomes and an increase in decommissioning expense.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $5.7 million, or 10.6 percent, for the first quarter of 2013 compared with the same period in 2012. The increase is due to higher property taxes primarily in Minnesota.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC increased $2.5 million for the first quarter of 2013 compared with the same period in 2012. The increase is due to the expansion of transmission facilities relating to CapX2020, construction related to nuclear generation projects and other capital investments.

Interest Charges — Interest charges decreased $7.0 million, or 13.4 percent, for the first quarter of 2013 compared with the same period in 2012. The decrease is due to lower interest rates, primarily related to refinancings completed in the second half of 2012, partially offset by higher long-term debt levels to fund investments in utility operations.

Income Taxes — Income tax expense increased $26.9 million for the first quarter of 2013 compared with the same period in 2012. The increase in income tax expense was primarily due to higher pre-tax earnings in 2013 and a discrete tax benefit of approximately $15.0 million for a carryback in 2012. These were partially offset by recognition of prior year research and experimentation credits in 2013 due to the passage of the American Taxpayer Relief Act of 2012 in 2013.

The ETR was 30.7 percent for the first quarter of 2013 compared with 19.2 percent for the same period in 2012. The lower ETR for 2012 was primarily due to the carryback adjustment referenced above. The ETR for the first quarter of 2012 would have been 34.9 percent without this tax benefit.

Public Utility Regulation

Minnesota Resource Plan — In March 2013, the MPUC approved NSP-Minnesota’s 2011-2025 Resource Plan. The MPUC ordered that a competitive acquisition process be conducted with the goal of adding approximately 500 MW of natural gas-based generation to the NSP System between 2017 and 2019. In February 2013, NSP-Minnesota also issued a Request for Proposal (RFP) for up to 200 MW of wind generation, to the extent that cost effective opportunities can be identified. Proposals for both RFPs may be for purchase power agreements, self-build or contracts with a build-ownership transfer option. Bid proposals in response to the two RFPs were received in April 2013.

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The natural gas-based generation procedural schedule is expected to be as follows:

Natural gas-based generation bid evaluation and advocacy assigned to ALJ – April-October 2013

ALJ will report to the MPUC which project should be selected – October 2013

MPUC to make a final ruling – November 2013

The wind-based generation procedural schedule is expected to be as follows:

Project review, selection and negotiation – April-June 2013

Planned application for and receipt of regulatory approval – July-September 2013

CapX2020 Transmission Expansion — In 2009, the MPUC approved separate Certificate of Need (CON) applications 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 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 updated as the projects progress.

Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. 345 kV transmission line

In May 2012, the MPUC issued a route permit for the Minnesota portion of the project and the PSCW approved a certificate of public convenience and necessity (CPCN) for the Wisconsin portion of the project. Federal approval of the project was granted in January 2013. Two parties have filed an appeal with the Minnesota Court of Appeals against the MPUC’s route permit decision. A decision by the Court is scheduled for June 2013. Construction on the project started in Minnesota in January 2013 and the project is expected to go into service in 2015.

Monticello, Minn. to Fargo, N.D. 345 kV transmission line

In December 2011, the Monticello, Minn. to St. Cloud, Minn. portion of the project was placed in service. The MPUC issued a route permit for the Minnesota portion of the St. Cloud, Minn. to Fargo, N.D. section in June 2011. The NDPSC granted a CPCN in January 2011 and a certificate of corridor compatibility and route permit for the North Dakota portion of the line in September 2012. An April 2013 deadline expired in North Dakota and no appeals were filed concerning a district court dismissal of a suit against the NDPSC’s order. Construction continues on the project in Minnesota. Construction started on the project in North Dakota in January 2013.

Brookings County, S.D. to Hampton, Minn. 345 kV transmission line

The MPUC route permit approvals for the Minnesota segments were obtained in 2010 and 2011. In June 2011, the SDPUC approved a facility permit for the South Dakota segment. In December 2011, MISO granted the final approval of the project as a multi-value project (MVP). In May 2012, construction started on the project in Minnesota.

Bemidji, Minn. to Grand Rapids, Minn. 230 kV transmission line

The Bemidji, Minn. to Grand Rapids, Minn. line was placed in service in September 2012.

Nuclear Power Operations

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, 2012 for further discussion regarding the nuclear generating plants.

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 Monticello power uprate request 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.

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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 $35 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 to meet the orders is expected to begin in the second quarter of 2015 with all units expected to be fully compliant by December 2016. On March 19, 2013, the NRC Commissioners sent a memorandum to the NRC Staff directing them to issue a modification to their initial order on reliable hardened containment vents. With the issuance of the revised order, the required completion date for ensuring a reliable hardened containment vent is expected to be delayed by approximately two years for the Monticello plant. Portions of the work that fall under the requests for additional information are expected to be completed by 2018. 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.

Summary of Recent Federal Regulatory Developments

The Federal Energy Regulatory Commission (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, 2012. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

MISO Transmission Pricing — The MISO Tariff presently provides for different allocation methods for the costs of new transmission investments depending on whether the project is primarily local or regional in nature. If a project qualifies as a MVP, the costs would be fully allocated to all loads in the MISO region. MVP eligibility is generally obtained for higher voltage (345 kV and higher) projects expected to serve multiple purposes, such as improved reliability, reduced congestion, transmission for renewable energy, and load serving. Certain parties have appealed the FERC MVP tariff orders to the U.S. Court of Appeals for the Seventh Circuit. The NSP System has certain new transmission facilities for which other customers in MISO contribute to cost recovery. Likewise, the NSP System also pays a share of the costs of projects constructed by other transmission owning entities. The transmission revenues received by the NSP System from MISO, and the transmission charges paid to MISO, associated with projects subject to regional cost allocation could be significant in future periods.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) — The FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation and development to be effective prospectively. In Order 1000, the FERC required utilities to develop tariffs that provide for joint transmission planning and cost allocation for all FERC-jurisdictional utilities within a region. In addition, Order 1000 required that regions coordinate to develop interregional plans for transmission planning and cost allocation. A key provision of Order 1000 is a requirement that FERC-jurisdictional wholesale transmission tariffs exclude provisions that would grant the incumbent transmission owner a federal Right of First Refusal (ROFR) to build certain types of transmission projects in its service area. The removal of a federal ROFR will eliminate rights that NSP-Minnesota currently has under the MISO tariff to build transmission within its footprint. Rather, the FERC required that opportunity to build such projects would extend to competitive transmission developers. Compliance with Order 1000 for NSP-Minnesota will occur through changes to the MISO tariff. MISO has made its initial compliance filings to incorporate new provisions into their tariffs regarding regional planning and cost allocation; the filings to address interregional planning and cost allocation requirements are due July 10, 2013.

In 2012, Minnesota enacted legislation that preserves ROFR rights for Minnesota utilities at the state level. This legislation is similar to legislation previously passed in North Dakota and South Dakota. The FERC’s initial order on MISO’s compliance filing to address the regional requirements of Order 1000 required MISO to remove proposed tariff provisions that would have recognized state ROFR rights and allowed state regulators to select the developer of a transmission project. NSP-Minnesota filed for rehearing of the issues relating to state authority in coordination with other MISO transmission owners on April 22, 2013.

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Nuclear Plant Power Uprates

Monticello Nuclear Plant EPU — In 2008, NSP-Minnesota filed for both state and federal approvals of an EPU of approximately 71 MW for NSP-Minnesota’s Monticello nuclear generating plant. The MPUC approved the CON for the EPU in 2008. The NRC staff has placed the license amendment filing on hold to address concerns raised by the Advisory Committee on Reactor Safeguards related to containment pressure associated with pump performance. In September 2012, NSP-Minnesota made a supplemental filing to the NRC to address the containment accident pressure concern. NSP-Minnesota expects to receive approval of the EPU project by the NRC in the second half of 2013. NSP-Minnesota is planning to complete implementation of the equipment changes needed to support the Monticello life extension and EPU projects in the planned spring 2013 refueling outage, which began in March 2013. The plant will not be permitted to operate at the higher capacity levels without the NRC’s approval.

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 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 March 31, 2013, 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, 2012, 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 March 31, 2013 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)

May 6, 2013
	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