Northern States Power 10-Q 2012 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2012

or

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

Commission File Number: 001-31387

Northern States Power Company

(Exact name of registrant as specified in its charter)

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

(612) 330-5500

 (Registrant’s telephone number, including area code)

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

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

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

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

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

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

Class	Outstanding at April 30, 2012
Common Stock, $0.01 par value	1,000,000 shares

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

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
Item l —	Financial Statements (Unaudited)	3
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 4 —	Controls and Procedures	28
PART II — OTHER INFORMATION
Item 1 —	Legal Proceedings	29
Item 1A —	Risk Factors	29
Item 4 —	Mine Safety Disclosures	29
Item 5 —	Other Information	29
Item 6 —	Exhibits	30
SIGNATURES		31

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

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

2

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
	2012			2011
Operating revenues
Electric	$	874,384		$	904,137
Natural gas		196,514			283,726
Other		5,875			5,029
Total operating revenues		1,076,773			1,192,892
Operating expenses
Electric fuel and purchased power		365,328			374,077
Cost of natural gas sold and transported		134,190			201,242
Cost of sales — other		3,117			2,926
Operating and maintenance expenses		261,030			255,214
Conservation program expenses		27,684			38,486
Depreciation and amortization		98,980			100,473
Taxes (other than income taxes)		53,768			45,653
Total operating expenses		944,097			1,018,071
Operating income		132,676			174,821
Other income, net		2,405			2,884
Allowance for funds used during construction — equity		8,035			9,593
Interest charges and financing costs
Interest charges — includes other financing costs of $1,477 and $1,426, respectively		52,120			51,615
Allowance for funds used during construction — debt		(4,278	)		(5,323	)
Total interest charges and financing costs		47,842			46,292
Income before income taxes		95,274			141,006
Income taxes		18,288			48,831
Net income	$	76,986		$	92,175

See Notes to Consolidated Financial Statements

3

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended March 31
	2012			2011
Net income	$	76,986		$	92,175
Other comprehensive income
Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $26 and $24, respectively		37			34
Derivative instruments:
Net fair value increase, net of tax of $8,517 and $78, respectively		12,373			113
Reclassification of gains to net income, net of tax of $(22) and $(12), respectively		(33	)		(15	)
		12,340			98
Marketable securities:
Net fair value increase, net of tax of $36 and $34, respectively		52			50
Other comprehensive income		12,429			182
Comprehensive income	$	89,415		$	92,357

See Notes to Consolidated Financial Statements

4

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Three Months Ended March 31
	2012			2011
Operating activities
Net income	$	76,986		$	92,175
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		100,173			101,787
Nuclear fuel amortization		26,000			25,551
Deferred income taxes		62,025			52,162
Amortization of investment tax credits		(675	)		(673	)
Allowance for equity funds used during construction		(8,035	)		(9,593	)
Net derivative gains		(361	)		(4,965	)
Changes in operating assets and liabilities:
Accounts receivable		(86,112	)		(43,599	)
Accrued unbilled revenues		63,486			63,705
Inventories		67,420			65,162
Other current assets		(31,155	)		(7,033	)
Accounts payable		(63,414	)		(29,501	)
Net regulatory assets and liabilities		20,904			16,905
Other current liabilities		8,531			11,616
Pension and other employee benefits		(77,603	)		(43,209	)
Change in other noncurrent assets		(23,427	)		(2,735	)
Change in other noncurrent liabilities		(2,053	)		(22,399	)
Net cash provided by operating activities		132,690			265,356
Investing activities
Utility capital/construction expenditures		(221,874	)		(303,376	)
Merricourt deposit		-			(90,833	)
Allowance for equity funds used during construction		8,035			9,593
Purchases of investments in external decommissioning fund		(213,618	)		(699,156	)
Proceeds from the sale of investments in external decommissioning fund		213,618			699,156
Investments in utility money pool arrangement		-			(274,500	)
Repayments from utility money pool arrangement		-			274,500
Advances to affiliate		-			(111,300	)
Advances from affiliate		-			148,300
Change in restricted cash		86,232			-
Other, net		(2,488	)		(4,994	)
Net cash used in investing activities		(130,095	)		(352,610	)
Financing activities
Proceeds from short-term borrowings, net		2,000			8,000
Borrowings under utility money pool arrangement		229,000			-
Repayments under utility money pool arrangement		(253,000	)		-
Repayments of long-term debt, including reacquisition premiums		-			(30	)
Capital contributions from parent		100,000			125,000
Dividends paid to parent		(58,054	)		(58,372	)
Net cash provided by financing activities		19,946			74,598
Net change in cash and cash equivalents		22,541			(12,656	)
Cash and cash equivalents at beginning of period		26,005			38,408
Cash and cash equivalents at end of period	$	48,546		$	25,752
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(76,530	)	$	(69,811	)
Cash paid for income taxes, net		(8,199	)		(4,082	)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	129,499		$	11,365

See Notes to Consolidated Financial Statements

5

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

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

	March 31, 2012			Dec. 31, 2011
Assets
Current assets
Cash and cash equivalents	$	48,546		$	26,005
Restricted cash		9,055			95,287
Accounts receivable, net		324,342			314,577
Accounts receivable from affiliates		19,930			18,033
Accrued unbilled revenues		167,817			231,303
Inventories		234,428			301,848
Regulatory assets		146,845			141,709
Derivative instruments		48,721			51,517
Prepayments and other		75,971			45,219
Total current assets		1,075,655			1,225,498
Property, plant and equipment, net		9,171,074			8,982,834
Other assets
Nuclear decommissioning fund and other investments		1,433,101			1,357,538
Regulatory assets		841,822			872,014
Derivative instruments		77,616			80,689
Other		59,558			36,638
Total other assets		2,412,097			2,346,879
Total assets	$	12,658,826		$	12,555,211
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	450,005		$	450,000
Short-term debt		28,000			26,000
Borrowings under utility money pool arrangement		41,000			65,000
Accounts payable		355,008			322,979
Accounts payable to affiliates		46,649			47,651
Regulatory liabilities		72,117			132,574
Taxes accrued		188,900			158,319
Accrued interest		40,167			68,362
Dividends payable to parent		58,027			58,054
Derivative instruments		34,635			65,781
Other		159,378			164,736
Total current liabilities		1,473,886			1,559,456
Deferred credits and other liabilities
Deferred income taxes		1,768,374			1,666,005
Deferred investment tax credits		31,396			31,743
Regulatory liabilities		445,290			439,029
Asset retirement obligations		1,591,275			1,581,896
Derivative instruments		183,476			184,190
Pension and employee benefit obligations		335,940			413,755
Other		83,882			65,464
Total deferred credits and other liabilities		4,439,633			4,382,082
Commitments and contingencies
Capitalization
Long-term debt		2,889,144			2,888,897
Common stock – authorized 5,000,000 shares of $0.01 par value; 1,000,000 shares outstanding at March 31, 2012 and Dec. 31, 2011, respectively		10			10
Additional paid in capital		2,466,391			2,366,391
Retained earnings		1,391,685			1,372,727
Accumulated other comprehensive loss		(1,923	)		(14,352	)
Total common stockholder's equity		3,856,163			3,724,776
Total liabilities and equity	$	12,658,826		$	12,555,211

See Notes to Consolidated Financial Statements

6

NSP-MINNESOTA AND SUBSIDIARIES

Notes to Consolidated Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of NSP-Minnesota and its subsidiaries as of March 31, 2012 and Dec. 31, 2011 and the results of its operations and cash flows for the three months ended March 31, 2012 and 2011.  All adjustments are of a normal, recurring nature, except as otherwise disclosed.  Management has also evaluated the impact of events occurring after March 31, 2012 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.  The Dec. 31, 2011 balance sheet information has been derived from the audited 2011 consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2011.  These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q.  Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations.  For further information, refer to the consolidated financial statements and notes thereto included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2011, filed with the SEC on Feb. 27, 2012.  Due to the seasonality of NSP-Minnesota’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

1. Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2011, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2. Accounting Pronouncements

Recently Adopted

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

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

Recently Issued

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

7

3.  Selected Balance Sheet Data

(Thousands of Dollars)	March 31, 2012			Dec. 31, 2011
Accounts receivable, net
Accounts receivable	$	347,414		$	337,581
Less allowance for bad debts		(23,072	)		(23,004	)
	$	324,342		$	314,577
Inventories
Materials and supplies	$	127,926		$	124,961
Fuel		82,729			113,711
Natural gas		23,773			63,176
	$	234,428		$	301,848
Property, plant and equipment, net
Electric plant	$	11,997,519		$	11,948,041
Natural gas plant		1,008,392			1,006,163
Common and other property		475,439			525,139
Construction work in progress		752,231			639,246
Total property, plant and equipment		14,233,581			14,118,589
Less accumulated depreciation		(5,457,349	)		(5,433,106	)
Nuclear fuel		2,062,790			1,939,299
Less accumulated amortization		(1,667,948	)		(1,641,948	)
	$	9,171,074		$	8,982,834

4.  Income Taxes

Except to the extent noted below, the circumstances set forth in Note 6 to the consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2011 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit — NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return.  The statute of limitations applicable to Xcel Energy’s 2007 federal income tax return expired in September 2011.  The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expires in September 2012.

State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns.  As of March 31, 2012, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2007.  As of March 31, 2012, there were no state income tax audits in progress.

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

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

(Millions of Dollars)	March 31, 2012		Dec. 31, 2011
Unrecognized tax benefit — Permanent tax positions	$	3.3	$	3.3
Unrecognized tax benefit — Temporary tax positions		13.2		13.4
Unrecognized tax benefit balance	$	16.5	$	16.7

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

(Millions of Dollars)	March 31, 2012			Dec. 31, 2011
NOL and tax credit carryforwards	$	(17.2	)	$	(18.1	)

8

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

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

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

5.  Rate Matters

Except to the extent noted below, the circumstances set forth in Note 10 to the consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2011 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

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

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

In November 2011, NSP-Minnesota reached a settlement agreement with various parties, which resolved all financial issues and several rate design issues.  The settlement agreement includes:

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

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

· The ability for NSP-Minnesota to seek deferred accounting for incremental property tax increases associated with electric and natural gas businesses in 2012.

· The stipulation that NSP-Minnesota will not file an electric rate case prior to Nov. 1, 2012, provided that both the settlement agreement and the property tax filing are approved by the MPUC.

In February 2012, NSP-Minnesota filed to reduce the interim rate request to $72.8 million to align with the settlement agreement.  On March 29, 2012, the MPUC approved the settlement and a written order is pending.  As of March 31, 2012 and Dec. 31, 2011, NSP-Minnesota recorded a provision for revenue subject to refund of approximately $78 million and $67 million, respectively, to align with the settlement agreement.

Minnesota Property Tax Deferral Request — As part of the settlement agreement in the Minnesota electric rate case, the settling parties acknowledged that NSP-Minnesota would be filing a petition seeking deferred accounting for 2012 property tax expense in excess of the level approved in the rate case.  The settling parties waived any right to object to the petition, but reserved the right to review and comment on the petition.  In December 2011, NSP-Minnesota filed the petition to request deferral of approximately $28 million of incremental 2012 property taxes that will not be recovered in base rates.  The estimate of 2012 incremental property taxes has been subsequently revised to approximately $24 million.

In April 2012, the Minnesota Department of Commerce (DOC) filed comments on the petition.  The DOC concluded that NSP-Minnesota had not made a reasonable case for deferred accounting and recommended that the MPUC deny NSP-Minnesota’s request to defer incremental 2012 property taxes and also opposed the proposed rider mechanism.  The Xcel Large Industrials and the Minnesota Chamber of Commerce filed comments in support of the deferred accounting treatment as preferable to a rider mechanism, with the understanding that all costs will be reviewed in NSP-Minnesota’s next rate case.  Until the MPUC rules on the issue, NSP-Minnesota will continue to expense the incremental property taxes.  An MPUC decision is expected in the second quarter of 2012.

9

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

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

In May 2011, NSP-Minnesota revised its rate request to approximately $18.0 million, or an increase of 11 percent, for 2011 and $2.4 million, or 1.4 percent, for the additional step increase in 2012.

In September 2011, NSP-Minnesota reached a settlement with the NDPSC Advocacy Staff, which provided for a rate increase of $13.7 million in 2011 and an additional step increase of $2.0 million in 2012, based on a 10.4 percent ROE and black box settlement for all other issues.  To address 2012 sales coming in below forecast revenue projections, the settlement includes a true-up to 2012 non-fuel revenues plus the settlement rate increase.  In February 2012, the NDPSC approved the settlement agreement.

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

South Dakota Electric Rate Case — In June 2011, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $14.6 million annually, effective in 2012.  The proposed increase included $0.7 million in revenues currently recovered through automatic recovery mechanisms.  The request is based on a 2010 historic test year adjusted for known and measurable changes, a requested ROE of 11 percent, a rate base of $323.4 million and an equity ratio of 52.48 percent.  NSP-Minnesota also requested approval of a nuclear cost recovery rider to recover the actual investment cost of the Monticello nuclear plant life cycle management and extended power uprate project that is not reflected in the test year. On Jan. 2, 2012, interim rates of $12.7 million were implemented.

In April 2012, the SDPUC Staff filed their direct testimony, which recommended an ROE of approximately 9 percent (ranging from 8.5 percent to 9.5 percent) and a lower cost of debt than the request (6.02 percent compared to the original request of 6.13 percent).  The Staff also recommended disallowance of the Nobles wind project costs unless the SDPUC determines there is energy value in which case the Staff’s recommendation would be to disallow a portion of the costs.  NSP-Minnesota’s rebuttal testimony is due by April 27, 2012 and a final SDPUC decision is expected in the summer of 2012.

6. Commitments and Contingencies

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

Purchased Power Agreements

Under certain purchased power agreements, NSP-Minnesota purchases power from independent power producing entities that own natural gas or biomass fueled power plants for which NSP-Minnesota is required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which NSP-Minnesota procures the natural gas required to produce the energy that it purchases.  These specific purchased power agreements create a variable interest in the associated independent power producing entity.

NSP-Minnesota had approximately 1,064 megawatts (MW) of capacity under long-term purchased power agreements as of March 31, 2012 and Dec. 31, 2011 with entities that have been determined to be variable interest entities.  NSP-Minnesota has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.  These agreements have expiration dates through the year 2028.

10

Guarantees and Indemnifications

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

Environmental Contingencies

Other Environmental Requirements

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

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

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

If the CSAPR is upheld and unmodified, NSP-Minnesota would likely utilize a combination of emissions reductions through upgrades to its existing SO2 control technology at NSP-Minnesota’s Sherco plant, which is estimated to cost a total of $10 million through 2014, and system operating changes to the Black Dog and the Sherco plants.  If available, NSP-Minnesota would also consider allowance purchases.  In addition, NSP-Minnesota has filed a petition for reconsideration with the EPA and a petition for review of the CSAPR with the D.C. Circuit seeking the allocation of additional emission allowances to NSP-Minnesota.  NSP-Minnesota contends that the EPA’s method of allocating allowances arbitrarily resulted in fewer allowances for its Riverside and High Bridge plants than should have been awarded to reflect their operations during the baseline period, which included coal-fired operations prior to their conversion to natural gas.  On April 23, 2012, NSP-Minnesota appealed to the D.C. Circuit on a final rule that the EPA issued that made changes to certain allowance allocations under CSAPR, seeking to secure additional allocations for its Riverside and High Bridge plants.  If successful, additional allowances would reduce NSP-Minnesota’s costs to comply with the CSAPR.

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective April 2012.  The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date.  NSP-Minnesota believes these costs will be recoverable through regulatory mechanisms and does not expect a material impact on results of operations, financial position or cash flows.

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

11

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

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

On April 24, 2012, the MPCA approved a supplement to the 2009 Regional Haze SIP finding that CSAPR meets BART for EGUs in Minnesota.  The supplement also made a source-specific BART determination for Sherco Units 1 and 2 that requires installation of the combustion controls for NOx and scrubber upgrades for SO2 by January 2015.  This SIP supplement will be forwarded to the EPA for approval, and it is anticipated that the EPA will make a decision in May 2012.

In addition to the Regional Haze rules identified in the EPA’s visibility program, and addressed in the MPCA’s SIP discussed above, there are other visibility rules related to a program called the Reasonably Attributable Visibility Impairment (RAVI) program.  In October 2009, the U.S. Department of the Interior certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota’s Sherco Units 1 and 2.  The EPA is required to make its own determination as to whether Sherco Units 1 and 2 cause or contribute to RAVI and, if so, whether the level of controls required by the MPCA is appropriate.  The EPA plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the RAVI program.  It is not yet known when the EPA will publish a proposal under RAVI, or what that proposal will entail.

Legal Contingencies

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

Environmental Litigation

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

Comer vs. Xcel Energy Inc. et al. — In May 2011, less than a year after their initial lawsuit was dismissed, plaintiffs in this purported class action lawsuit filed a second lawsuit against more than 85 utility, oil, chemical and coal companies in U.S. District Court in Mississippi.  The complaint alleges defendants’ CO2 emissions intensified the strength of Hurricane Katrina and increased the damage plaintiffs purportedly sustained to their property.  Plaintiffs base their claims on public and private nuisance, trespass and negligence.  Among the defendants named in the complaint are Xcel Energy Inc., SPS, PSCo, NSP-Wisconsin and NSP-Minnesota.  The amount of damages claimed by plaintiffs is unknown.  The defendants, including Xcel Energy Inc., believe this lawsuit is without merit and filed a motion to dismiss the lawsuit.  On March 20, 2012, the U.S. District Court granted this motion for dismissal.  In April 2012, plaintiffs appealed this decision to the U.S. Court of Appeals for the Fifth Circuit.  While Xcel Energy Inc. believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it could potentially have a material impact on NSP-Minnesota’s consolidated results of operations, cash flows or financial position.  No accrual has been recorded for this matter.

12

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.  As a result, NSP-Minnesota recorded a $101 million deposit in the first quarter of 2011, which was collected in April 2011.  In May 2011, NSP-Minnesota filed a declaratory judgment action in U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreements and enXco also filed a separate lawsuit in the same court seeking, among other things, in excess of $240 million for an alleged breach of contract.  NSP-Minnesota believes enXco’s lawsuit is without merit and has filed a motion to dismiss.  In September 2011, the U.S. District Court denied the motion to dismiss.  The trial is set to begin in late 2012 or early 2013.  While NSP-Minnesota believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it could potentially have a material impact on NSP-Minnesota’s consolidated results of operations, cash flows or financial position.  No accrual has been recorded for this matter.

7.  Borrowings and Other Financing Instruments

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2012			Twelve Months Ended Dec. 31, 2011
Borrowing limit	$	500		$	500
Amount outstandingat period end		28			26
Average amount outstanding		23			7
Maximum amount outstanding		72			80
Weighted average interest rate, computed on a daily basis		0.40	%		0.34	%
Weighted average interest rate at period end		0.41			0.45

Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, NSP-Minnesota must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an amount exceeding available capacity under the credit agreement.  The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At March 31, 2012, NSP-Minnesota had the following committed credit facility available (in millions of dollars):

Credit Facility		Drawn (a)		Available
$	500.0	$	35.7	$	464.3

(a) 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, 2012 and Dec. 31, 2011.

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

13

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2012			Twelve Months Ended Dec. 31, 2011
Borrowing limit	$	250		$	250
Amount outstandingat period end		41			65
Average amount outstanding		29			17
Maximum amount outstanding		80			80
Weighted average interest rate, computed on a daily basis		0.31	%		0.34	%
Weighted average interest rate at period end		0.33			0.35

8.  Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosuresprovides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchal 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.  Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion.  Unscheduled distributions from real estate investments may be redeemed with proper notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity.  Based on NSP-Minnesota’s evaluation of its ability to redeem private equity and real estate investments, fair value measurements for private equity and real estate investments have been assigned a Level 3.

Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities, except for asset-backed and mortgage-backed securities, for which the third party service may also consider additional, more subjective inputs.  Since the impact of the use of these less observable inputs can be significant to the valuation of asset-backed and mortgage-backed securities, fair value measurements for these instruments have been assigned a Level 3.  Inputs that may be considered in the valuation of asset-backed and mortgage-backed securities in conjunction with pricing of similar securities in active markets include the use of risk-based discounting and estimated prepayments in a discounted cash flow model.  When these additional inputs and models are utilized, increases in the risk-adjusted discount rates and decreases in the assumed principal prepayment rates each have the impact of reducing reported fair values for these instruments.

Interest rate derivatives— The fair value of interest rate derivatives are based on broker quotes utilizing market interest rate curves.

14

Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2.  When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.

Electric commodity derivatives held by NSP-Minnesota include financial transmission rights (FTRs) purchased from Midwest Independent Transmission System Operator, Inc. (MISO).  FTRs purchased from MISO are financial instruments that entitle the holder to one year of monthly revenues or charges based on transmission congestion across a given transmission path.  The value of an FTR is derived from, and designed to offset, the cost of that energy congestion, which is caused by overall transmission load and other transmission constraints. Congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path.   Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR.  NSP-Minnesota’s valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease.  Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model – including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3.  Monthly FTR settlements are included in the fuel clause adjustment,  and therefore changes in the fair value of the yet to be settled portions of FTRs are deferred as a regulatory asset or liability.  Given this regulatory treatment and the limited magnitude of NSP-Minnesota’s FTRs relative to its electric utility operations, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the consolidated financial statements of NSP-Minnesota.

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

Non-Derivative Instruments Fair Value Measurements

The Nuclear Regulatory Commission (NRC) requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants.  Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning the Monticello and Prairie Island nuclear generating plants.  The fund contains cash equivalents, debt securities, equity securities, and other investments — all classified as available-for-sale securities under the applicable accounting guidance.  NSP-Minnesota plans to reinvest proceeds from matured securities until decommissioning begins.

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

Unrealized gains for the nuclear decommissioning fund were $117.1 million and $79.8 million at March 31, 2012 and Dec. 31, 2011, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $65.7 million and $87.5 million at March 31, 2012 and Dec. 31, 2011, respectively.

15

The following tables present the cost and fair value of NSP-Minnesota’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund investments at March 31, 2012 and Dec. 31, 2011:

	March 31, 2012
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	12,383	$	8,023	$	4,360	$	-	$	12,383
Commingled funds		374,523		-		371,078		-		371,078
International equity funds		65,712		-		67,183		-		67,183
Private equity investments		19,358		-		-		20,068		20,068
Real estate		26,265		-		-		27,905		27,905
Debt securities:
Government securities		131,152		-		131,401		-		131,401
U.S. corporate bonds		156,602		-		163,851		-		163,851
International corporate bonds		25,187		-		26,351		-		26,351
Municipal bonds		53,895		-		56,862		-		56,862
Asset-backed securities		16,515		-		-		16,547		16,547
Mortgage-backed securities		65,803		-		-		68,671		68,671
Equity securities:
Common stock		410,729		447,205		-		-		447,205
Total	$	1,358,124	$	455,228	$	821,086	$	133,191	$	1,409,505

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $23.6 million of miscellaneous investments.

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

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

16

The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three months ended March 31, 2012 and 2011:

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

(Thousands of Dollars)	Jan. 1, 2011		Purchases		Settlements			Losses Recognized as Regulatory Assets			March 31, 2011
Asset-backed securities	$	33,174	$	756	$	(7,910	)	$	-		$	26,020
Mortgage-backed securities		72,589		46,113		(19,873	)		(462	)		98,367
Total	$	105,763	$	46,869	$	(27,783	)	$	(462	)	$	124,387

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class at March 31, 2012:

	Final Contractual Maturity
(Thousands of Dollars)	Due in 1 Year or Less		Due in 1 to 5  Years		Due in 5 to 10 Years		Due after 10 Years		Total
Government securities	$	113,004	$	701	$	17,696	$	-	$	131,401
U.S. corporate bonds		-		37,556		112,103		14,192		163,851
Foreign securities		-		8,162		18,186		3		26,351
Municipal bonds		-		-		27,039		29,823		56,862
Asset-backed securities		-		13,269		3,278		-		16,547
Mortgage-backed securities		-		-		959		67,712		68,671
Debt securities	$	113,004	$	59,688	$	179,261	$	111,730	$	463,683

Derivative Instruments Fair Value Measurements

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

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

At March 31, 2012, accumulated OCI related to interest rate derivatives included $0.1 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

At March 31, 2012, NSP-Minnesota had unsettled interest rate swaps outstanding with a total notional amount of $225 million.  These interest rate swaps were designated as hedges, and as such, changes in fair value are recorded to OCI.

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

17

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, gas for resale, and vehicle fuel.

At March 31, 2012, NSP-Minnesota had vehicle fuel contracts designated as cash flow hedges extending through December 2014.  NSP-Minnesota also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions.  Changes in the fair value of non-trading commodity derivative instruments are recorded in OCI or deferred as a regulatory asset or liability.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.  NSP-Minnesota recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three months ended March 31, 2012 and 2011.

At March 31, 2012, accumulated OCI related to commodity derivative cash flow hedges 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, 2012 and Dec. 31, 2011:

(Amounts in Thousands) (a)(b)	March 31, 2012		Dec. 31, 2011
Megawatt hours (MWh) of electricity		22,332	37,522
MMBtu of natural gas		-	7,290
Gallons of vehicle fuel		303	330

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

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

The following tables detail the impact of derivative activity during the three months ended March 31, 2012 and 2011, on OCI, regulatory assets and liabilities, and income:

	Three Months Ended March 31, 2012
	Fair Value Changes Recognized					Pre-Tax Amounts Reclassified into
	During the Period in:					Income During the Period from:
	Accumulated					Accumulated						Pre-Tax Gains
	Other		Regulatory			Other			Regulatory			Recognized
	Comprehensive		(Assets) and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Loss		Liabilities			Loss			(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate	$	20,787	$	-		$	(27	) (a)	$	-		$	-
Vehicle fuel and other commodity		103		-			(28	) (e)		-			-
Total	$	20,890	$	-		$	(55	)	$	-		$	-
Other derivative instruments
Trading commodity	$	-	$	-		$	-		$	-		$	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

18

	Three Months Ended March 31, 2011
	Fair Value Changes Recognized					Pre-Tax Amounts Reclassified into
	During the Period in:					Income During the Period from:
	Accumulated					Accumulated						Pre-Tax Gains
	Other		Regulatory			Other			Regulatory			Recognized
	Comprehensive		(Assets) and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Income		Liabilities			Income			(Liabilities)			in Income
Derivatives designated as cash flow hedges
Interest rate	$	-	$	-		$	(27	) (a)	$	-		$	-
Vehicle fuel and other commodity		213		-			(22	) (e)		-			-
Total	$	213	$	-		$	(49	)	$	-		$	-
Other derivative instruments
Trading commodity	$	-	$	-		$	-		$	-		$	5,355	(b)
Electric commodity		-		8,846			-			(8,888	) (c)		-
Natural gas commodity		-		(2,018	)		-			10,928	(d)		-
Total	$	-	$	6,828		$	-		$	2,040		$	5,355

(a) Recorded to interest charges.

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

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

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

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

NSP-Minnesota had no derivative instruments designated as fair value hedges during the three months ended March 31, 2012 and 2011.  Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Credit Related Contingent Features — Contract provisions of the derivative instruments that NSP-Minnesota enters into may require the posting of collateral or settlement of the contracts for various reasons, including if NSP-Minnesota is unable to maintain its credit ratings.  If the credit ratings for NSP-Minnesota were downgraded below investment grade, contracts underlying $4.6 million and $1.4 million of derivative instruments in a gross liability position at March 31, 2012 and Dec. 31, 2011, respectively, would have required NSP-Minnesota to post collateral or settle applicable contracts, which would have resulted in payments to counterparties of $0.8 million and $0.1 million, respectively.  At March 31, 2012 and Dec. 31, 2011, there was no collateral posted on these specific contracts.

Certain of NSP-Minnesota’s derivative instruments are also subject to contract provisions that contain adequate assurance clauses.  These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that NSP-Minnesota’s ability to fulfill its contractual obligations is reasonably expected to be impaired.  NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts as of March 31, 2012 and Dec. 31, 2011.

19

Recurring Fair Value Measurements—The following table presents, for each of the hierarchy levels, NSP-Minnesota’s derivative assets and liabilities that are measured at fair value on a recurring basis at March 31, 2012:

	March 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:
Interest rate	$	-	$	179	$	-	$	179	$	-		$	179
Vehicle fuel and other commodity		-		114		-		114		-			114
Other derivative instruments:
Trading commodity		-		32,363		-		32,363		(12,373	)		19,990
Electric commodity		-		-		5,898		5,898		(570	)		5,328
Total current derivative assets	$	-	$	32,656	$	5,898	$	38,554	$	(12,943	)		25,611
Purchased power agreements (a)													23,110
Current derivative instruments												$	48,721
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	115	$	-	$	115	$	(115	)	$	-
Other derivative instruments:
Trading commodity		-		31,459		-		31,459		(2,681	)		28,778
Total noncurrent derivative assets	$	-	$	31,574	$	-	$	31,574	$	(2,796	)		28,778
Purchased power agreements (a)													48,838
Noncurrent derivative instruments												$	77,616
Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate	$	-	$	7,511	$	-	$	7,511	$	-		$	7,511
Other derivative instruments:
Trading commodity		-		27,481		4		27,485		(14,213	)		13,272
Electric commodity		-		-		570		570		(570	)		-
Total current derivative liabilities	$	-	$	34,992	$	574	$	35,566	$	(14,783	)		20,783
Purchased power agreements (a)													13,852
Current derivative instruments												$	34,635
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	16,716	$	-	$	16,716	$	(2,797	)	$	13,919
Total noncurrent derivative liabilities	$	-	$	16,716	$	-	$	16,716	$	(2,797	)		13,919
Purchased power agreements (a)													169,557
Noncurrent derivative instruments												$	183,476

(a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception.  Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

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

20

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

	Dec. 31, 2011
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	93	$	-	$	93	$	-		$	93
Other derivative instruments:
Trading commodity		-		26,133		-		26,133		(9,679	)		16,454
Electric commodity		-		-		13,333		13,333		(1,471	)		11,862
Total current derivative assets	$	-	$	26,226	$	13,333	$	39,559	$	(11,150	)		28,409
Purchased power agreements (a)													23,108
Current derivative instruments												$	51,517
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	59	$	-	$	59	$	(59	)	$	-
Other derivative instruments:
Trading commodity		-		28,307		-		28,307		(2,234	)		26,073
Total noncurrent derivative assets	$	-	$	28,366	$	-	$	28,366	$	(2,293	)		26,073
Purchased power agreements (a)													54,616
Noncurrent derivative instruments												$	80,689
Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate	$	-	$	28,119	$	-	$	28,119	$	-		$	28,119
Other derivative instruments:
Trading commodity		-		21,816		-		21,816		(11,647	)		10,169
Electric commodity		-		698		916		1,614		(1,471	)		143
Natural gas commodity		-		13,499		-		13,499		-			13,499
Total current derivative liabilities	$	-	$	64,132	$	916	$	65,048	$	(13,118	)		51,930
Purchased power agreements (a)													13,851
Current derivative instruments												$	65,781
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	13,464	$	-	$	13,464	$	(2,293	)	$	11,171
Total noncurrent derivative liabilities	$	-	$	13,464	$	-	$	13,464	$	(2,293	)		11,171
Purchased power agreements (a)													173,019
Noncurrent derivative instruments												$	184,190

(a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, NSP-Minnesota began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception.  Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

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

21

The following table presents the changes in Level 3 commodity derivatives for the three months ended March 31, 2012 and 2011:

	Three Months Ended March 31
(Thousands of Dollars)	2012			2011
Balance at Jan. 1	$	12,417		$	2,392
Settlements		(8,884	)		(7,790	)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a)		(9	)		68
Gains recognized as regulatory liabilities		1,800			7,662
Balance at March 31	$	5,324		$	2,332

(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, 2012 and 2011.

Fair Value of Long-Term Debt

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

	March 31, 2012				Dec. 31, 2011
	Carrying				Carrying
(Thousands of Dollars)	Amount		Fair Value		Amount		Fair Value
Long-term debt, including current portion	$	3,339,149	$	3,942,691	$	3,338,897	$	4,066,367

The fair value of NSP-Minnesota’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities.  The fair value estimates are based on information available to management as of March 31, 2012 and Dec. 31, 2011, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.  These fair value estimates have not been comprehensively revalued for purposes of these consolidated financial statements since those dates and current estimates of fair values may differ significantly.

9.  Other Income, Net

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

	Three Months Ended March 31
(Thousands of Dollars)	2012			2011
Interest income	$	3,839		$	3,079
Other nonoperating income		304			194
Insurance policy expense		(1,738	)		(389	)
Other income, net	$	2,405		$	2,884

10.  Segment Information

Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by NSP-Minnesota’s chief operating decision maker.  NSP-Minnesota evaluates performance based on profit or loss generated from the product or service provided.  These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each reportable segment.

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

· NSP-Minnesota’s regulated electric utility segment generates electricity which is transmitted and distributed in Minnesota, North Dakota and South Dakota.  In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States.  Regulated electric utility also includes NSP-Minnesota’s commodity trading operations.

· NSP-Minnesota’s regulated natural gas utility segment transports, stores and distributes natural gas in portions of Minnesota and North Dakota.

22

· 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, 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
Three Months Ended March 31, 2011
Operating revenues from external customers	$	904,137	$	283,726	$	5,029	$	-		$	1,192,892
Intersegment revenues		125		191		-		(316	)		-
Total revenues	$	904,262	$	283,917	$	5,029	$	(316	)	$	1,192,892
Net income	$	68,304	$	21,075	$	2,796	$	-		$	92,175

11.  Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three Months Ended March 31
	2012			2011			2012			2011
							Postretirement Health
(Thousands of Dollars)	Pension Benefits						Care Benefits
Service cost	$	7,370		$	5,993		$	24		$	21
Interest cost		12,309			12,930			1,751			1,775
Expected return on plan assets		(16,822	)		(18,593	)		(110	)		(144	)
Amortization of transition obligation		-			-			337			337
Amortization of prior service cost (credit)		2,955			3,292			(29	)		(29	)
Amortization of net loss		9,869			6,661			749			567
Net periodic benefit cost		15,681			10,283			2,722			2,527
Costs not recognized due to the effects of regulation		(8,058	)		(7,310	)		-			-
Net benefit cost recognized for financial reporting	$	7,623		$	2,973		$	2,722		$	2,527

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

23

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, 2011, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended March 31, 2012.

Results of Operations

NSP-Minnesota’s net income was approximately $77.0 million for the first quarter of 2012, compared with approximately $92.2 million for the same period in 2011.The decrease is primarily the result of warmer weather impacting electric and gas sales, differences between rates effective in the first quarter of 2012 as compared to interim rates in the first quarter of 2011, higher property taxes and higher O&M expenses.  The decreases were partially offset by a lower effective tax rate.

Electric Revenues and Margins

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

	Three Months Ended March 31
(Millions of Dollars)	2012			2011
Electric revenues	$	874		$	904
Electric fuel and purchased power		(365	)		(374	)
Electric margin	$	509		$	530

24

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

Electric Revenues

(Millions of Dollars)	2012 vs. 2011
Estimated impact of weather	$	(13	)
Differences in Minnesota retail rates (2011 interim compared to 2012 settlement) (a)		(11	)
Non-fuel riders		(5	)
Trading		(4	)
Conservation revenue (offset by expenses)		(3	)
Fuel and purchased power cost recovery		(3	)
Retail sales decrease (excluding weather impact)		(3	)
Retail rate increases (North Dakota and South Dakota interim)		4
Transmission revenue		4
Conservation incentive		2
Other, net		2
Total decrease in electric revenues	$	(30	)

(a) NSP-Minnesota reduced depreciation expense and revenues by approximately $8 million in the first quarter of 2012 to reflect the settlement in the Minnesota electric rate case.

Electric Margin

(Millions of Dollars)	2012 vs. 2011
Estimated impact of weather	$	(13	)
Differences in Minnesota retail rates (2011 interim compared to 2012 settlement) (a)		(11	)
Non-fuel riders		(5	)
Conservation revenue (offset by expenses)		(3	)
Retail sales decrease (excluding weather impact)		(3	)
Retail rate increases (North Dakota and South Dakota interim)		4
Transmission revenue, net of costs		4
Conservation incentive		2
Other, net		4
Total decrease in electric margin	$	(21	)

(a) NSP-Minnesota reduced depreciation expense and revenues by approximately $8 million in the first quarter of 2012 to reflect the settlement in the Minnesota electric rate case.

Natural Gas Revenues and Margins

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

	Three Months Ended March 31
(Millions of Dollars)	2012			2011
Natural gas revenues	$	197		$	284
Cost of natural gas sold and transported		(134	)		(201	)
Natural gas margin	$	63		$	83

25

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

Natural Gas Revenues

(Millions of Dollars)	2012 vs. 2011
Purchased natural gas adjustment clause recovery	$	(67	)
Estimated impact of weather		(13	)
Conservation revenue (offset by expenses)		(8	)
Other, net		1
Total decrease in natural gas revenues	$	(87	)

Natural Gas Margin

(Millions of Dollars)	2012 vs. 2011
Estimated impact of weather	$	(13	)
Conservation revenue (offset by expenses)		(8	)
Other, net		1
Total decrease in natural gas margin	$	(20	)

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $5.8 million, or 2.3 percent, for the first quarter of 2012, compared with the same period in 2011.  The following summarizes the components of the changes for the three months ended March 31:

(Millions of Dollars)	2012 vs. 2011
Higher plant generation costs	$	4
Higher nuclear plant operation costs		3
Lower nuclear outage costs, net of deferral		(2	)
Lower employee benefit expenses		(2	)
Other, net		3
Total increase in O&M expenses	$	6

Conservation Program Expenses — Conservation program expenses decreased $10.8 million, or 28.1 percent, for the first quarter of 2012, compared with the same period in 2011.  The lower expense is primarily attributable to lower sales volumes and lower rider rates, as well as a change in the cost allocation formula used to account for electric conservation improvement program expenses.  Conservation program expenses are generally recovered in our major jurisdictions concurrently through riders and base rates.

Depreciation and Amortization — Depreciation and amortization expense decreased $1.5 million, or 1.5 percent, for the first quarter of 2012, compared with the same period in 2011.  This decrease is primarily due to a change in depreciation lives for certain assets to reflect the settlement in the recent Minnesota electric rate case, which resulted in a reduction in depreciation expense of approximately $8 million.  This was partially offset by a portion of the Monticello extended power uprate going into service in May 2011 and normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $8.1 million, or 17.8 percent, for the first quarter of 2012, compared with the same period in 2011.  The increase was due to increased property taxes.  NSP-Minnesota has requested to defer incremental property taxes in Minnesota, effective as of Jan. 1, 2012.  However, until the MPUC rules on this issue, NSP-Minnesota will continue to expense the incremental property taxes.  Assuming MPUC approval of NSP-Minnesota’s request, which is currently expected in the second quarter of 2012, NSP-Minnesota would reflect the deferral retroactive to Jan. 1, 2012.  For more information see Note 5 to the consolidated financial statements.

Interest Charges — Interest charges increased $0.5 million, or 1.0 percent, for the first quarter of 2012, compared with the same period in 2011.  The increase is due to higher long-term debt levels to fund investments in utility operations, partially offset by lower interest rates.

26

Income Taxes — Income tax expense decreased $30.5 million for the first quarter of 2012, compared with the same period in 2011.  The decrease in income tax expense was primarily due to lower pretax earnings and a tax benefit associated with a carryback.  The effective tax rate was 19.2 percent for the first quarter of 2012, compared with 34.6 percent for the same period in 2011.  The lower effective tax rate for 2012 was primarily due to the completion of an analysis in the first quarter of 2012 on the eligibility of certain expenses that qualified for an extended carryback beyond the typical two-year carryback period.  As a result, NSP-Minnesota recognized a discrete tax benefit of approximately $15 million.  Without this tax benefit, the effective tax rate for continuing operations for the first quarter of 2012 would have been 34.9 percent.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC decreased $2.6 million, or 17.5 percent for the first quarter of 2012, compared with the same period in 2011.  The decrease is primarily due to lower average construction work in progress balances.

Public Utility Regulation

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

NSP-Minnesota and Great River Energy filed four route permit applications with the MPUC in addition to a facility permit application with the SDPUC, a certificate of corridor compatibility application with the NDPSC and a Certificate of Public Convenience and Necessity application with the Public Service Commission of Wisconsin.  The MPUC has issued route permits for the Minnesota portion of the Fargo, N.D. to St. Cloud, Minn. project, the Brookings, S.D. project, and the Bemidji, Minn. to Grand Rapids, Minn. project.  In April 2012, the MPUC approved the route permit for the portions of the new transmission lines between Hampton, Minn. and La Crosse, Wis. to be constructed in Minnesota.  The remaining required permit activities are on-going in North Dakota and Wisconsin.

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

Summary of Recent Federal Regulatory Developments

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

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

Nuclear Power Operations and Waste Disposal

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

27

NRC Regulation — The NRC regulates the nuclear operations of NSP-Minnesota.  Decisions by the NRC can significantly impact the operations of the nuclear plants.  The event at the nuclear plant in Fukushima, Japan could impact the NRC’s deliberations on NSP-Minnesota’s power uprates discussed below.  This event could also result in additional regulation by the NRC, which could require additional capital expenditures or operating expenses.  The NRC has created an internal task force that has developed recommendations for NRC consideration 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.  On July 12, 2011, the task force released its recommendations in a written report.  The report confirms the safety of U.S. nuclear energy facilities and recommends actions to enhance U.S. nuclear plant readiness to safely manage severe events.  To better coordinate response activities, the U.S. nuclear energy industry has created a steering committee made up of representatives from major electric sector organizations to integrate and coordinate the industry’s ongoing responses.

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.  The requirements were consistent with the approach proposed by the industry and is expected to result in NSP-Minnesota spending approximately $20 to $50 million to comply with the requirements at the Monticello and Prairie Island plants.  NSP-Minnesota is evaluating the information requests and orders and expects to fully comply.  Based on current refueling outage plans specific to each nuclear facility, the dates of the required compliance begin in the second quarter of 2015 with all units being fully compliant by December 2016.  NSP-Minnesota believes the costs associated with compliance would be recoverable from customers through regulatory mechanisms and does not expect a material impact on its results of operations, financial position, or cash flows.

Nuclear Plant Power Uprates

Prairie Island Nuclear Extended Power Uprate — In 2009, the MPUC approved a CON for an extended power uprate of approximately 164 MW for Prairie Island Units 1 and 2.  Recent analysis of the extended power uprate submittals to the NRC concluded that significant additional design work beyond NSP-Minnesota’s estimated schedule and cost plan would be required for a successful application submittal.  As a result, NSP-Minnesota completed an economic and new project design analysis and submitted a Change in Circumstances filing with the MPUC in March 2012.  NSP-Minnesota asked the MPUC to confirm that the extended power uprate project is in the best interest of customers prior to NSP-Minnesota making the significant investments necessary to complete an application and undertake the NRC licensing process.  The updated analysis shows the project continues to show system benefits, however the magnitude of the benefits is substantially lower than originally anticipated.  An MPUC decision is expected in the first half of 2013.

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

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure.  As of March 31, 2012, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.

28

Internal Control Over Financial Reporting

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

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

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

Additional Information

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

Item 1A — RISK FACTORS

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

Item 4 — MINE SAFETY DISCLOSURES

None.

Item 5 — OTHER INFORMATION

In June 2011, the FASB issued Comprehensive Income (Topic 220) — Presentation of Comprehensive Income (ASU No. 2011-05).  On Jan. 1, 2012, NSP-Minnesota implemented the requirements of ASU No. 2011-05 by presenting net income, the components of OCI and total comprehensive income in two separate, but consecutive financial statements of net income and comprehensive income. The implementation resulted in more prominent presentation of total comprehensive income and more detailed presentation of the components of OCI.

The following presents retrospective application of ASU No. 2011-05 to the consolidated financial statements of NSP-Minnesota as a separate but consecutive statement following NSP-Minnesota’s consolidated statements of income for the years ended Dec. 31, 2011, 2010 and 2009.  The financial statement presentation requirements of ASU No. 2011-05 do not affect the items previously reported in net income, OCI or total comprehensive income, or the guidance for reclassifying components of OCI to net income, and therefore retrospective application of the new guidance does not result in significant changes to the information reported in the previously issued consolidated financial statements of NSP-Minnesota.

29

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended Dec. 31
(Thousands of Dollars)	2011			2010			2009
Net income	$	352,981		$	274,225		$	293,770
Other comprehensive (loss) income
Pension and retiree medical benefits:
Net pension and retiree medical benefit gains arising during the period, net of tax of $97, $68 and $85, respectively		140			99			124
Amortization of (gains) losses included in net periodic benefit cost, net of tax of $(362), $(99) and $57, respectively		(528	)		(142	)		84
		(388	)		(43	)		208
Derivative instruments:
Net fair value decrease, net of tax of $(11,422), $(57) and $(843), respectively		(16,578	)		(80	)		(1,219	)
Reclassification of (gains) losses to net income, net of tax of $(94), $774 and $1,458, respectively		(128	)		1,116			2,107
		(16,706	)		1,036			888
Marketable securities:
Net fair value (decrease) increase, net of tax of $(63), $89 and $284, respectively		(92	)		129			411
Other comprehensive (loss) income		(17,186	)		1,122			1,507
Comprehensive income	$	335,795		$	275,347		$	295,277

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, 2012 are formatted in XBRL (eXtensible Business Reporting Language):  (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) Notes to Condensed Consolidated Financial Statements, and (vi) document and entity information.

30

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)
April 30, 2012
	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Vice President and Controller
		/s/ TERESA S. MADDEN
		Teresa S. Madden
		Senior Vice President, Chief Financial Officer and Director

31