Northern States Power 10-Q 2009 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, 2009

or

o TRANSITION REPORTS 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 requirement 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).            oYes  oNo

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

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

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

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

Class	Outstanding at May 4, 2009
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	22
Item 4.	Controls and Procedures	27
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	27
Item 1A.	Risk Factors	27
Item 6.	Exhibits	28
SIGNATURES		29
Certifications Pursuant to Section 302
Certifications Pursuant to Section 906
Statement Pursuant to Private Litigation

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). Additional information on Xcel Energy is available on various filings with the Securities and Exchange Commission (SEC).

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PART 1. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands of dollars)

	Three Months Ended March 31,
	2009			2008
Operating revenues
Electric	$	869,082		$	870,235
Natural gas	329,267			392,605
Other	5,034			4,884
Total operating revenues	1,203,383			1,267,724
Operating expenses
Electric fuel and purchased power	382,146			414,388
Cost of natural gas sold and transported	261,197			319,153
Cost of sales — other	2,468			2,367
Other operating and maintenance expenses	243,096			239,410
Conservation program expenses	14,661			19,346
Depreciation and amortization	104,009			102,656
Taxes (other than income taxes)	36,822			39,539
Total operating expenses	1,044,399			1,136,859
Operating income	158,984			130,865
Interest and other (expenses) income, net	(18		)	4,311
Allowance for funds used during construction — equity	6,706			6,370
Interest charges and financing costs
Interest charges — includes financing costs of $1,467 and $1,353, respectively	50,085			47,655
Allowance for funds used during construction — debt	(4,342		)	(4,348		)
Total interest charges and financing costs	45,743			43,307
Income before income taxes	119,929			98,239
Income taxes	43,730			34,271
Net income	$	76,199		$	63,968

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands of dollars)

	Three Months Ended March 31,
	2009			2008
Operating activities
Net income	$	76,199		$	63,968
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	106,534			104,709
Nuclear fuel amortization	19,290			13,387
Deferred income taxes	13,451			42,077
Amortization of investment tax credits	(876		)	(938		)
Allowance for equity funds used during construction	(6,706		)	(6,370		)
Net realized and unrealized hedging and derivative transactions	5,507			4,636
Changes in operating assets and liabilities:
Accounts receivable	33,106			1,606
Accounts receivable from affiliates	(6,201		)	10,320
Accrued unbilled revenues	53,414			37,826
Inventories	125,739			59,954
Recoverable purchased natural gas and electric energy costs	20,444			(18,696		)
Other current assets	(7,283		)	(2,838		)
Accounts payable	(12,980		)	15,804
Net regulatory assets and liabilities	12,031			14,555
Other current liabilities	19,827			(21,369		)
Change in other noncurrent assets	(21		)	3,777
Change in other noncurrent liabilities	(9,146		)	2,863
Net cash provided by operating activities	442,329			325,271
Investing activities
Utility capital/construction expenditures	(278,003		)	(269,230		)
Allowance for equity funds used during construction	6,706			6,370
Purchase of investments in external decommissioning fund	(396,528		)	(227,987		)
Proceeds from sale of investments in external decommissioning fund	395,815			217,139
Investments in utility money pool arrangement	—			(246,100		)
Repayments from utility money pool arrangement	—			74,800
Advances to affiliate	(21,700		)	(113,100		)
Advances from affiliate	21,700			145,700
Other investments	(1,551		)	1,159
Net cash used in investing activities	(273,561		)	(411,249		)
Financing activities
Repayment of short-term borrowings, net	(65,000		)	(281,500		)
Borrowings under utility money pool arrangement	100,300			183,500
Repayments under utility money pool arrangement	(163,800		)	(278,600		)
Proceeds from issuance of long-term debt	—			493,883
Repayment of long-term debt, including reacquisition premiums	(3		)	(3		)
Capital contributions from parent	120,000			150,000
Dividends paid to parent	(58,415		)	(56,094		)
Net cash (used) provided by financing activities	(66,918		)	211,186
Net increase in cash and cash equivalents	101,850			125,208
Cash and cash equivalents at beginning of period	12,343			24,626
Cash and cash equivalents at end of period	$	114,193		$	149,834
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(76,753	)	$	(70,020	)
Cash received for income taxes (net of refunds received)	24,809			40,898
Supplemental disclosure of non-cash flow investing transactions:
Property, plant and equipment additions in accounts payable	$	9,860		$	13,558

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in thousands of dollars)

	March 31, 2009		Dec. 31, 2008
Assets
Current assets:
Cash and cash equivalents	$	114,193	$	12,343
Accounts receivable, net	380,050		413,156
Accounts receivable from affiliates	18,619		12,418
Accrued unbilled revenues	195,037		248,451
Inventories	220,164		345,903
Recoverable purchased natural gas and electric energy costs	6,161		26,605
Derivative instruments valuation	34,759		70,252
Prepayments and other	60,066		48,493
Total current assets	1,029,049		1,177,621
Property, plant and equipment, net	6,967,868		6,804,794
Other assets:
Nuclear decommissioning fund and other investments	1,033,088		1,084,827
Regulatory assets	868,458		828,712
Derivative instruments valuation	131,550		129,605
Other	20,838		21,266
Total other assets	2,053,934		2,064,410
Total assets	$	10,050,851	$	10,046,825
Liabilities and Equity
Current liabilities:
Current portion of long-term debt	$	250,064	$	250,060
Short-term debt	—		65,000
Borrowings under utility money pool arrangement	—		63,500
Accounts payable	355,647		389,676
Accounts payable to affiliates	59,212		52,291
Taxes accrued	168,683		121,163
Accrued interest	35,464		68,009
Dividends payable to parent	57,256		58,414
Derivative instruments valuation	26,969		39,816
Other	54,772		50,696
Total current liabilities	1,008,067		1,158,625
Deferred credits and other liabilities:
Deferred income taxes	994,629		987,050
Deferred investment tax credits	39,378		40,254
Asset retirement obligations	1,071,330		1,055,689
Regulatory liabilities	443,810		459,880
Derivative instruments valuation	222,281		219,421
Pension and employee benefit obligations	264,366		269,537
Other liabilities	88,748		77,775
Total deferred credits and other liabilities	3,124,542		3,109,606
Commitments and contingent liabilities
Capitalization:
Long-term debt	2,712,957		2,712,689
Common stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares	10		10
Additional paid in capital	2,035,857		1,915,857
Retained earnings	1,168,776		1,149,833
Accumulated other comprehensive income	642		205
Total common stockholder’s equity	3,205,285		3,065,905
Total liabilities and equity	$	10,050,851	$	10,046,825

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of NSP-Minnesota and its subsidiaries as of March 31, 2009 and Dec. 31, 2008; the results of its operations for the three ended March 31, 2009 and 2008; and its cash flows for the three months ended March 31, 2009 and 2008. All adjustments are of a normal, recurring nature, except as otherwise disclosed.  The Dec. 31, 2008 balance sheet information has been derived from the audited 2008 financial statements.  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 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, 2008, filed with the SEC on March 2, 2009.  Due to the seasonality of electric and natural gas sales of NSP-Minnesota, interim results are not necessarily an appropriate base from which to project annual results.

1.   Summary of Significant Accounting Policies

Except to the extent updated or described below, the significant accounting policies set forth in Note 1 to the consolidated financial statements in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2008, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

Reclassification — Conservation program expenses were reclassified as a separate item.  Previously these costs were included in other operating and maintenance expenses on the consolidated statements of income.  This reclassification did not have an impact on total operating expenses.

2.Accounting Pronouncements

Recently Adopted

Business Combinations (Statement of Financial Accounting Standards (SFAS) No. 141 (revised 2007)) — In December 2007, the Financial Accounting Standards Board (FASB) issued SFAS No. 141(R), which establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest; recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) is to be applied prospectively to business combinations for which the acquisition date is on or after the beginning of an entity’s fiscal year that begins on or after Dec. 15, 2008. NSP-Minnesota implemented SFAS No. 141(R) on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Noncontrolling Interests in Consolidated Financial Statements, an Amendment of Accounting Research Bulletin (ARB) No. 51 (SFAS No. 160) — In December 2007, the FASB issued SFAS No. 160, which establishes accounting and reporting standards that require the ownership interest in subsidiaries held by parties other than the parent be clearly identified and presented in the consolidated balance sheets within equity, but separate from the parent’s equity; the amount of consolidated net income attributable to the parent and the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of earnings; and changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently as equity transactions. SFAS No. 160 was effective for fiscal years beginning on or after Dec. 15, 2008. NSP-Minnesota implemented SFAS No. 160 on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (SFAS No. 161) — In March 2008, the FASB issued SFAS No. 161, which is intended to enhance disclosures to help users of the financial statements better understand how derivative instruments and hedging activities affect an entity’s financial position, financial performance and cash flows.  SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, to require disclosures including objectives and strategies for using derivatives, gains and losses on derivative instruments, and credit-risk-related contingent features in derivative contracts.  SFAS No. 161 was effective for financial statements issued for fiscal years and interim periods beginning after Nov. 15, 2008.  NSP-Minnesota implemented SFAS No. 161 on Jan. 1, 2009, and the implementation did not have a material

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impact on its consolidated financial statements.  For further discussion and SFAS No. 161 required disclosures, see Note 8 to the consolidated financial statements.

Recently Issued

Employers’ Disclosures about Postretirement Benefit Plan Assets (FASB Staff Position (FSP) FAS 132(R)-1) — In December 2008, the FASB issued FSP FAS 132(R)-1, which amends SFAS No. 132 (revised 2003), Employers’ Disclosures about Pensions and Other Postretirement Benefits, to expand an employer’s required disclosures about plan assets of a defined benefit pension or other postretirement plan to include investment policies and strategies, major categories of plan assets, information regarding fair value measurements, and significant concentrations of credit risk.  FSP FAS 132(R)-1 is effective for fiscal years ending after Dec. 15, 2009.  NSP-Minnesota does not expect the implementation of FSP FAS 132(R)-1 to have a material impact on its consolidated financial statements.

Interim Disclosures about Fair Value of Financial Instruments (FSP FAS 107-1 and Accounting Principles Board (APB) 28-1) —In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, which amends SFAS No. 107, Disclosures About Fair Value of Financial Instruments, and APB Opinion No. 28, Interim Financial Reporting, to require disclosures regarding the fair value of financial instruments in interim financial statements. In addition, entities are required to disclose the method and significant assumptions used to estimate the fair value of financial instruments. FSP FAS 107-1 and APB 28-1 are effective for interim periods ending after June 15, 2009. NSP-Minnesota does not expect the implementation of FSP FAS 107-1 and APB 28-1 to have a material impact on its consolidated financial statements.

Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (FSP FAS 157-4) —In April 2009, the FASB issued FSP FAS 157-4, which provides additional guidance for estimating fair value in accordance with SFAS No. 157, Fair Value Measurements, when the volume and level of market activity for an asset or liability have significantly decreased.  FSP FAS 157-4 emphasizes that even if there has been a significant decrease in the volume and level of market activity for the asset or liability, fair value still represents the exit price in an orderly transaction between market participants.  FSP FAS 157-4 is effective for interim and annual periods ending after June 15, 2009.  NSP-Minnesota does not expect the implementation of FSP FAS 157-4 to have a material impact on its consolidated financial statements.

Recognition and Presentation of Other-Than-Temporary Impairments (FSP FAS 115-2 and FAS 124-2) — In April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, which changes the method for determining whether an other-than-temporary impairment exists for debt securities, and also requires additional disclosures regarding other-than-temporary impairments.  FSP FAS 115-2 and FAS 124-2 is effective for interim and annual periods ending after June 15, 2009.  NSP-Minnesota does not expect the implementation of FSP FAS 115-2 and FAS 124-2 to have a material impact on its consolidated financial statements.

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3.   Selected Balance Sheet Data

(Thousands of Dollars)	March 31, 2009			Dec. 31, 2008
Accounts receivable, net:
Accounts receivable	$	404,973		$	438,855
Less allowance for bad debts	(24,923		)	(25,699		)
	$	380,050		$	413,156
Inventories:
Materials and supplies	$	99,915		$	97,945
Fuel	95,572			141,190
Natural gas	24,677			106,768
	$	220,164		$	345,903

Property, plant and equipment, net:
Electric plant	$	9,678,477		$	9,472,073
Natural gas plant	926,477			916,740
Construction work in progress	540,785			615,734
Common and other property	456,887			452,308
Total property, plant and equipment	11,602,626			11,456,855
Less accumulated depreciation	(4,904,603		)	(4,907,681		)
Nuclear fuel	1,644,708			1,611,193
Less accumulated amortization	(1,374,863		)	(1,355,573		)
	$	6,967,868		$	6,804,794

4.   Income Taxes

Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (FIN 48) — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated income tax returns.  In the first quarter of 2008, the Internal Revenue Service (IRS) completed an examination of Xcel Energy’s federal income tax returns for 2004 and 2005 (and research credits for 2003). The IRS did not propose any material adjustments for those tax years. Tax year 2004 is the earliest open year and the statute of limitations applicable to Xcel Energy’s 2004 federal income tax return remains open until Dec. 31, 2009. In the third quarter of 2008, the IRS commenced an examination of tax years 2006 and 2007. As of March 31, 2009, the IRS had not proposed any material adjustments to tax years 2006 and 2007.

In the first quarter of 2008, the state of Minnesota concluded an income tax audit through tax year 2001.  No material adjustments were proposed for this audit. As of March 31, 2009, NSP-Minnesota’s earliest open tax year in which an audit can be initiated by state taxing authorities under applicable statutes of limitations is 2004. There currently are no state income tax audits in progress.

The amount of unrecognized tax benefits was $21.5 million and $20.2 million on March 31, 2009 and Dec. 31, 2008, respectively.  These unrecognized tax benefit amounts were reduced by the tax benefits associated with tax credit carryovers of $2.8 million and $4.4 million as of March 31, 2009 and Dec. 31, 2008, respectively.

The unrecognized tax benefit balance included $7.6 million and $7.2 million of tax positions on March 31, 2009 and Dec. 31, 2008, respectively, which if recognized would affect the annual effective tax rate. In addition, the unrecognized tax benefit balance included $13.9 million and $13.0 million of tax positions on March 31, 2009 and Dec. 31, 2008, respectively, 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 effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

The increase in the unrecognized tax benefit balance of $1.3 million from Dec. 31, 2008 to March 31, 2009, was due to the addition of similar uncertain tax positions related to ongoing activity.  NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and when 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 liability for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with tax credit carryovers.  The amount of interest expense related to unrecognized tax benefits reported within interest charges in the

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first quarter of 2009 was $0.2 million.  The amount reported within interest charges related to unrecognized tax benefits in the first quarter of 2008 reduced interest expense by $1.3 million. The liability for interest related to unrecognized tax benefits was $1.5 million on March 31, 2009 and $1.3 million on Dec. 31, 2008.

No amounts were accrued for penalties as of March 31, 2009 and Dec. 31, 2008.

5.   Rate Matters

Except to the extent noted below, the circumstances set forth in Note 13 to the consolidated financial statements included in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2008 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference. The following section includes unresolved proceedings that are material to NSP-Minnesota’s financial position.

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

Base Rate

NSP-Minnesota Electric Rate Case — On Nov. 3, 2008, NSP-Minnesota filed a request with the MPUC to increase Minnesota electric rates by $156 million annually, or 6.05 percent.  The request is based on a 2009 forecast test-year, an electric rate base of $4.1 billion, a requested return on equity (ROE) of 11.0 percent and an equity ratio of 52.5 percent.

In December 2008, the MPUC approved an interim rate increase of $132 million, or 5.12 percent, effective Jan. 2, 2009.  The primary difference between interim rate levels approved and NSP-Minnesota’s request of  $156 million is due to a previously authorized ROE of 10.54 percent and NSP-Minnesota’s requested ROE of 11.0 percent.

On April 7, 2009, intervenors submitted direct testimony.  The Office of Energy Security (OES) recommended a revenue increase of $72 million, based on a ROE of 10.88 percent and an equity ratio of 52.5 percent.  In addition, the OES recommendation reflected the following adjustments:

·Recognition of a 10 year life extension of the Prairie Island nuclear generating facility, resulting in a decrease of approximately $40 million in depreciation and decommissioning expenses and rejection of NSP-Minnesota’s proposed nuclear rate stability plan.  These adjustments reduce NSP-Minnesota’s overall revenue deficiency while at the same time reducing expense accruals by $40 million.

·An adjustment for increased sales, which reduced the request by $12.3 million, a $7 million reduction in short-term capacity expenses, a decrease in overall salaries of $4.8 million, and chemical commodity cost decreases of $1.6 million.

The Office of the Attorney General (OAG) recommended recognition of depreciation and decommissioning cost decreases resulting from the Prairie Island life extension in the current proceeding and rejection of the proposed nuclear rate stability plan.  However, the OAG did not recommend a specific reduction in revenue requirements.  The OAG also proposed a fuel clause adjustment (FCA) incentive through a 3 percent cap on base fuel costs and requested that any approved increase in rates be applied equally to all classes of customers.

Other parties to the proceeding (Large Customer Group, Minnesota Chamber of Commerce, Suburban Rate Authority, the Customer Group) addressed several non-revenue requirements issues, including FCA reporting and accountability, class cost of service and rate design, and potential changes to NSP-Minnesota’s quality of service metrics.

A final decision from the MPUC is expected in the third quarter of 2009.  The following procedural schedule has been established:

·NSP-Minnesota rebuttal testimony on May 5, 2009;

·State agency and intervenor surrebuttal testimony on May 26, 2009; and

·Evidentiary hearings are scheduled for June 2-9, 2009.

Electric, Purchased Gas and Resource Adjustment Clauses

Transmission Cost Recovery (TCR) Rider — In November 2006, the MPUC approved a TCR rider pursuant to legislation, which allows annual adjustments to retail electric rates to provide recovery of incremental transmission investments between

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rate cases.  In December 2007, NSP-Minnesota filed adjustments to the TCR rate factors and implemented a rider to recover $18.5 million beginning Jan. 1, 2008.  In March 2008, the MPUC approved the 2008 rider but required certain procedural changes for future TCR filings if costs are disputed.  On Oct. 30, 2008, NSP-Minnesota submitted its proposed TCR rate factors, seeking to recover $14 million in 2009.  A portion of amounts previously collected through the TCR rider prior to 2009 has been included for recovery in the NSP-Minnesota electric rate case described above.  MPUC approval is pending.

Renewable Energy Standard (RES) Rider — In March 2008, the MPUC approved an RES rider to recover the costs for utility-owned projects implemented in compliance with the RES, and the RES rider was implemented on April 1, 2008.  Under the rider, NSP-Minnesota could recover up to approximately $14.5 million in 2008 attributable to the Grand Meadow wind farm, a 100 megawatt (MW) wind project, subject to true-up.  In 2008, NSP-Minnesota submitted the RES rider for recovery of approximately $22 million in 2009 attributable to the Grand Meadow wind farm.  On Feb. 12, 2009, the MPUC approved the rider request but required that the issue of whether these costs should be moved to base rates in the currently pending electric rate case or left in the rider, as NSP-Minnesota has proposed, to be addressed through supplemental testimony in the rate case.

Metropolitan Emissions Reduction Project (MERP) Rider — On Oct. 1, 2008, NSP-Minnesota filed a proposed MERP rider for 2009 designed to recover costs related to MERP environmental improvement projects.  Under this rider, NSP-Minnesota proposes to recover $114 million in 2009, an increase of approximately $23 million over 2008.  New rates went into effect automatically on Jan. 1, 2009 as stipulated.  MPUC approval is still pending.

Annual Automatic Adjustment Report for 2008 — In September 2008, NSP-Minnesota filed its annual automatic adjustment reports for July 1, 2007 through June 30, 2008.  During that time period, $848.5 million in fuel and purchased energy costs, including $258.8 million of Midwest Independent Transmission System Operator, Inc. (MISO) charges, were recovered from Minnesota electric customers through the FCA.  In addition, approximately $680 million of purchased natural gas and transportation costs were recovered through the purchased gas adjustment.  The 2008 annual automatic adjustment reports are pending initial comments, scheduled for June 2009, and MPUC action.

MISO Ancillary Service Market (ASM) Cost Recovery — On May 9, 2008, NSP-Minnesota and several other Minnesota electric utilities filed jointly for MPUC regulatory approval to recover ASM costs through the Minnesota FCA cost recovery mechanism.  On March 17, 2009, the MPUC issued an order approving interim FCA recovery of these charges, subject to refund, and required NSP-Minnesota to make quarterly filings addressing the costs and benefits resulting from ASM participation, and a one time compliance filing in February 2010 that demonstrates that there were benefits to ratepayers of the ASM market after one year of operation.  No party requested reconsideration of the MPUC order; therefore, the order is considered final.

Gas Meter Module Failures — Approximately 8,700 customers in the St. Cloud and East Grand Forks areas of Minnesota and about 4,000 customers in the Fargo, N.D. area were under billed for a period of time during the 2007-2008 heating season due to the failure of the automated meter reading (AMR) module installed on their natural gas meters.  While the modules failed to register usage, the meters continued to function.  In the May to July 2008 timeframe, NSP-Minnesota rebilled approximately 5,000 of these customers for their estimated consumption during the period the modules registered no consumption and then ceased rebilling as both the MPUC and North Dakota Public Service Commission (NDPSC) opened investigations into this matter.

North Dakota Module Failures

On July 2, 2008, NSP-Minnesota received a letter from the NDPSC requesting further information on the AMR module failure.  On Dec. 3, 2008, NSP-Minnesota made a filing with the NDPSC regarding its commitments and proposed remedies for rebilling affected customers.  The filing outlined the proposed rebilling plan in detail, which committed to a 10-day, go-forward field response to customer inquiries regarding meter accuracy, offered an adjustment to the natural gas true-up to remove the commodity cost for the under recovered gas due to the rebilling process and indicated willingness to work with NDPSC staff on a service quality credit for customers experiencing a module failure.

On Feb. 27, 2009, NSP-Minnesota filed a request with the NDPSC to rebill the remaining North Dakota customers experiencing a module failure, reiterated the commitments made in previous filings and proposed a $50 service quality credit for each North Dakota customer experiencing a module failure.  The proposed resolution package is expected to cost approximately $0.7 million.   The NDPSC approved NSP-Minnesota’s proposed resolution on April 13, 2009.

Minnesota Module Failures

On Aug. 1, 2008, the MPUC opened a docket and issued a notice directing NSP-Minnesota to file information about the AMR module failure.  NSP-Minnesota responded to the MPUC on Aug. 21, 2008, proposing to rebill affected Minnesota

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customers for the unrecorded natural gas usage during the months that no consumption or intermittent usage was recorded.  NSP-Minnesota proposed to employ the process provided by NSP-Minnesota’s natural gas tariff and the MPUC’s rules to estimate usage, which would be consistent with the process used whenever any other type of meter or module failure affecting the measurement of customer consumption occurs.  The OAG and the OES subsequently submitted comments indicating support for the rebilling plan with certain conditions.  The OAG raised concerns about the timing of the remediation efforts and questions whether customers should be responsible for the entire cost of the unbilled natural gas.

On Nov. 6, 2008, the MPUC reviewed the matter and directed NSP-Minnesota to provide additional information prior to making a final decision on the rebilling plan.

On Dec. 19, 2008, NSP-Minnesota met with MPUC staff, the OES and OAG and in January 2009 filed its response to the questions with the MPUC.  NSP-Minnesota indicated a willingness to work with parties to develop a remedy for the current situation and to develop prospective service quality standards to address this and other concerns around billing accuracy.  NSP-Minnesota has determined that a number of AMR modules designed for commercial customers are defective and as a result is broadening efforts to evaluate the performance of both gas and electric AMR modules.

On March 6, 2009, NSP-Minnesota filed an order with the MPUC to rebill the remaining Minnesota customers experiencing a module failure, reiterated the commitments made in previous filings and proposed a $50 service quality credit for each customer experiencing a module failure. The proposed resolution package is expected to cost approximately $0.9 million.  Comments were filed on the proposed resolution on April 3, 2009, and reply comments were submitted on April 17, 2009.  MPUC action is pending.

Annual Review of Remaining Lives — On Feb. 17, 2009, NSP-Minnesota filed an order with the MPUC requesting an increase in proposed service lives, salvage rates and resulting depreciation rates for its electric and gas production facilities and a depreciation study for other gas and electric assets, effective Jan 1, 2009.  The OES recommended provisional approval to ensure that the decisions in this depreciation docket do not have unintended consequences in the pending NSP-Minnesota electric rate case.  The OES recommended a 10-year lengthening of decommissioning life rather than the three-year level proposed by NSP-Minnesota, reducing the accrual for decommissioning by approximately $9 million.  MPUC action is pending.

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

NSP-Minnesota South Dakota TCR and Environmental Cost Recovery (ECR) Rate Riders — In December 2008, the SDPUC approved two rate riders for recovery of transmission investments and environmental costs effective Feb. 1, 2009.  The TCR rider rate is set to recover approximately $1.9 million during 2009.  The ECR Rider rate is set to recover approximately $2.5 million during 2009.

Both rate riders were allowed a return on equity of 9.5 percent according to the terms of their respective settlement agreements.  However, if NSP-Minnesota makes a general rate filing utilizing a 2008 test-year, the SDPUC may order that an appropriate ROE value be utilized under the rider mechanism, subject to true-up for the period from July 1, 2008 to the effective date of the order.

Pending and Recently Concluded Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Revenue Sufficiency Guarantee (RSG) Charges — In April 2006, the FERC issued an order determining that MISO had incorrectly applied its Transmission Energy Markets Tariff (TEMT) regarding the application of the RSG charge to certain transactions.  The FERC ordered MISO to resettle all affected transactions retroactive to April 2005.  The RSG charges are collected from MISO customers and paid to generators.  In October 2006, the FERC issued an order granting rehearing in part and reversed the prior ruling requiring MISO to issue retroactive refunds, and ordered MISO to submit a compliance filing to implement prospective changes.

In March 2007, the FERC issued orders separately denying rehearing of the FERC order.  Several parties filed appeals to the U.S. Court of Appeals for the District of Columbia seeking judicial review of the FERC’s determinations of the allocation of RSG costs among MISO market participants.  Xcel Energy intervened in each of these proceedings.  In August 2007, Ameren Services Company and the Northern Indiana Public Service Company filed a joint complaint against MISO at the FERC, challenging the MISO’s FERC-approved methodology for the recovery of RSG costs.  In November 2007, the FERC issued an order instituting a proceeding to review evidence and to establish a RSG cost allocation methodology for market participants under the MISO TEMT.  In March 2008, the MISO filed indicative tariff revisions that reflect an alternative

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mechanism for allocating RSG charges and costs.  In August 2008, the FERC rejected this filing and issued an order commencing a hearing.

In November 2008, the FERC issued two orders related to RSG.  One order requires the RSG charge allocation to include virtual supply transactions and requires resettlement of RSG charges retroactive to August 2007.  The second order reversed a prior FERC decision and changed the RSG calculation methodology for the May 2006 to August 2007 retroactive period.  Several parties filed requests for rehearing of the November 2008 FERC orders, arguing that the change in RSG allocation should be prospective.  The recent RSG orders have caused several MISO market participant entities to default, which will affect the net financial impact of the orders of the electric production and transmission system of NSP-Minnesota, which is managed as an integrated system with that of NSP-Wisconsin, jointly referred to as the NSP System.  On Feb. 23, 2009, MISO filed proposed compliance changes to the TEMT to redesign the RSG charges to better align cost recovery with cost causation. The RSG-related dockets are pending FERC action.

6.   Commitments and Contingent Liabilities

Except as noted below, the circumstances set forth in Notes 13, 14 and 15 to the consolidated financial statements in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2008 and Note 5 to the consolidated financial statements in this Quarterly Report on Form 10-Q 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 contingencies and unresolved contingencies that are material to NSP-Minnesota’s financial position.

Environmental Contingencies

NSP-Minnesota has been, or is currently, involved with the cleanup of contamination from certain hazardous substances at several sites.  In many situations, NSP-Minnesota believes it will recover some portion of these costs through insurance claims.  Additionally, where applicable, NSP-Minnesota is pursuing, or intends to pursue, recovery from other potentially responsible parties (PRPs) and through the rate regulatory process.  New and changing federal and state environmental mandates can also create added financial liabilities for NSP-Minnesota, which are normally recovered through the rate regulatory process.  To the extent any costs are not recovered through the options listed above, NSP-Minnesota would be required to recognize an expense.

Site Remediation —NSP-Minnesota must pay all or a portion of the cost to remediate sites where past activities of NSP-Minnesota or other parties have caused environmental contamination.  Environmental contingencies could arise from various situations including sites of former manufactured gas plants operated by NSP-Minnesota, its predecessors or other entities; and third party sites, such as landfills, to which NSP-Minnesota is alleged to be a PRP that sent hazardous materials and wastes.  At March 31, 2009, the liability for the cost of remediating these sites was estimated to be $0.4 million, of which $0.2 million was considered to be a current liability.

Third Party and Other Environmental Site Remediation

Asbestos Removal —Some of NSP-Minnesota’s facilities contain asbestos.  Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed.  NSP-Minnesota has recorded an estimate for final removal of the asbestos as an asset retirement obligation.  See additional discussion of asset retirement obligations in Note 14 of the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2008.  It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment.  The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Other Environmental Requirements

Environmental Protection Agency (EPA) Proposed Greenhouse Gas (GHG) Endangerment Finding — On April 17, 2009, the EPA issued a proposed finding that GHGs threaten public health and welfare.  This finding was in response to the U.S. Supreme Court’s decision in Massachusetts v. EPA, 549 U.S. 497 (2007), which held that GHGs are pollutants covered by the Clean Air Act and required the EPA to determine whether emissions of GHGs from motor vehicles endanger public health or welfare.  The EPA’s proposed endangerment finding applies to the Clean Air Act’s mobile source program, and does not automatically trigger regulation under other provisions of the Clean Air Act that are applicable to stationary sources, such as power plants.  As such, the proposed endangerment finding, in and of itself, does not impact NSP-Minnesota.

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Clean Air Interstate Rule (CAIR) — In March 2005, the EPA issued the CAIR to further regulate sulfur dioxide (SO2)and nitrogen oxide (NOx) emissions.  The objective of CAIR was to cap emissions of SO2and NOx in the eastern United States, including Minnesota.  In July 2008, the U. S. Court of Appeals for the District of Columbia vacated CAIR and remanded the rule to the EPA.  On Dec. 23, 2008, the court reinstated CAIR while the EPA develops new regulations in accordance with the court’s July opinion.

As currently written, CAIR has a two-phase compliance schedule, beginning in 2009 for NOx and 2010 for SO2, with a final compliance deadline in 2015 for both emissions.  Under CAIR, each affected state will be allocated an emissions budget for SO2 and NOx that will result in significant emission reductions.  It will be based on stringent emission controls and forms the basis for a cap-and-trade program.  State emission budgets or caps decline over time.  States can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.

The EPA has drafted a proposed rule to stay the effectiveness of CAIR in Minnesota.  As such, cost estimates are not included at this time for NSP-Minnesota.

Clean Air Mercury Rule (CAMR) — In March 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants.  In February 2008, the U.S. Court of Appeals for the District of Columbia vacated CAMR, which impacts federal CAMR requirements, but not necessarily state-only mercury rules and legislation.  Costs to comply with the Minnesota Mercury Emissions Reduction Act of 2006 are discussed below.

Minnesota Mercury Legislation — In May 2006, the Minnesota legislature enacted the Mercury Emissions Reduction Act of 2006 (Act) providing a process for plans, implementation and cost recovery for utility efforts to curb mercury emissions at certain power plants. For NSP-Minnesota, the Act covers units at the A. S. King and Sherco generating facilities. Under the Act, Xcel Energy is operating and maintaining continuous mercury emission monitoring systems. The information obtained will be used to establish a baseline from which to measure mercury emission reductions.

Current plans are to install a sorbent injection system at both A. S. King and Sherco Unit 3. Implementation would occur by Dec. 31, 2009, at Sherco Unit 3 and by Dec. 31, 2010, for A. S. King. For these units, the current total capital cost estimate is $8.5 million, with the annual cost estimate of $4.3 million for A. S. King and $4.2 million for Sherco Unit 3. For Sherco Units 1 and 2, the current cost estimate is $13.6 million for capital and $10 million for annual expenses.  On Nov. 6, 2008, the MPUC approved and ordered the implementation of the Sherco Unit 3 and A. S. King mercury emission reduction plans.

Utilities subject to the Act may also submit plans to address non-mercury pollutants subject to federal and state statutes and regulations, which became effective after Dec. 31, 2004. Cost recovery provisions of the Act also apply to these other environmental initiatives. In September 2006, NSP-Minnesota filed a request with the MPUC for recovery of up to $6.3 million of certain environmental improvement costs that are expected to be recoverable under the Act. In January 2007, the MPUC approved this request to defer these costs as a regulatory asset with a cap of $6.3 million. On Aug. 26, 2008, NSP-Minnesota filed a request with the MPUC to increase the deferral to $19.4 million as NSP-Minnesota anticipated exceeding the authorized deferral amount in September 2008.  On Nov. 21, 2008, NSP-Minnesota filed a request with the MPUC to reduce its deferred accounting request from $19.4 million to $8.7 million to reflect its requested recovery of nearly all emission reduction compliance costs incurred through 2009 in the NSP-Minnesota electric rate case, which was filed on Nov. 3, 2008.

Voluntary Capacity Upgrade and Emissions Reduction Filing — In December 2007, NSP-Minnesota filed a plan with the Minnesota Pollution Control Agency (MPCA) and MPUC for reducing mercury emissions by up to 90 percent at the Sherco Unit 3 and A. S. King plants. Currently, the estimated project costs are approximately $8.5 million.  At the same time, NSP-Minnesota submitted a revised filing to the MPUC for a major emissions reduction project at Sherco Units 1 and 2 to reduce emissions and expand capacity. The revised filing has estimated project costs of approximately $1.1 billion. The filing also contains alternatives for the MPUC to consider to add additional capacity and to achieve even lower emissions. If selected, these alternatives could range from $90.8 to $330.8 million in addition to the $1.1 billion proposal. NSP-Minnesota’s investments are subject to MPUC approval of a cost recovery mechanism. The MPCA has issued its assessment that the Sherco Unit 3 and A. S. King plans are appropriate. In light of recent significant changes in the national economy, lower forecast of energy consumption, and new information concerning an emerging technology that may be more cost effective, NSP-Minnesota filed a request with the MPUC to withdraw the plan on Nov. 6, 2008, to allow NSP-Minnesota to reevaluate alternatives. The MPUC granted the withdrawal request on Dec. 9, 2008.

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Regional Haze Rules — In June 2005, the EPA finalized amendments to the July 1999 regional haze rules.  These amendments apply to the provisions of the regional haze rule that require emission controls, known as BART, for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze.

NSP-Minnesota submitted its BART alternatives analysis for Sherco Units 1 and 2 in October 2006.  The MPCA reviewed the BART analyses for all units in Minnesota and determined that overall, compliance with CAIR is better than BART.  On Nov. 13, 2008, NSP-Minnesota submitted a revised BART alternatives analysis letter to the MPCA to account for increased construction and equipment costs.  The underlying conclusions and proposed emission control equipment, however, remained unchanged from the original 2006 BART analysis. The MPCA completed their BART determination and established SO2 and NOx limits that are equivalent to the reductions made under CAIR.

Federal Clean Water Act — The federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available (BTA) for minimizing adverse environmental impacts. In July 2004, the EPA published phase II of the rule, which applies to existing cooling water intakes at steam-electric power plants. Several lawsuits were filed against the EPA in the United States Court of Appeals for the Second Circuit (Court of Appeals) challenging the phase II rulemaking. In January 2007, the Court of Appeals issued its decision and remanded the rule to the EPA for reconsideration. In June 2007, the EPA suspended the deadlines and referred any implementation to each state’s best professional judgment until the EPA is able to fully respond to the remand.  In April 2008, the U.S. Supreme Court granted limited review of the Court of Appeals’ opinion to determine whether the EPA has the authority to consider costs and benefits in assessing BTA.  On April 1, 2009, the U.S. Supreme Court issued a decision in Entergy Corp. v. Riverkeeper, Inc., concluding that the EPA can, but is not required to, consider a cost benefit analysis when establishing BTA.  The decision overturned only one aspect of the Court’s earlier opinion, and merely gives the EPA the discretion to consider costs and benefits when it reconsiders its phase II rules.  Until the EPA fully responds to the Court’s decision, the rule’s compliance requirements and associated deadlines will remain unknown.  As such, it is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time.

The MPCA exercised its authority under best professional judgment to require the Black Dog Generating Station in its recently renewed wastewater discharge permit to create a plan by April 2010 to reduce the plant intake’s impact on aquatic wildlife.  NSP-Minnesota is discussing alternatives with the local community and regulatory agencies to address this concern.

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 of them. The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have a material adverse effect on NSP-Minnesota’s financial position and results of operations.

Environmental Litigation

Carbon Dioxide (CO2) Emissions Lawsuit — In July 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court in the Southern District of New York against five utilities, including Xcel Energy, to force reductions in CO2 emissions. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions. In October 2004, Xcel Energy and the other defendants filed a motion to dismiss the lawsuit. On Sept. 19, 2005, the court granted the motion to dismiss on constitutional grounds. Plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit. In June 2007, the Court of Appeals issued an order requesting the parties to file a letter brief regarding the impact of the United States Supreme Court’s decision in Massachusetts v. EPA, 127 S.Ct. 1438 (April 2, 2007) on the issues raised by the parties on appeal. Among other things, in its decision in Massachusetts v. EPA, the United States Supreme Court held that CO2 emissions are a “pollutant” subject to regulation by the EPA under the CAA. In July 2007, in response to the request of the Court of Appeals, the defendant utilities filed a letter brief stating the position that the United States Supreme Court’s decision supports the arguments raised by the utilities on appeal. The Court of Appeals has taken the matter under advisement and is expected to issue an opinion in due course.

Comer vs. Xcel Energy Inc. et al. — In April 2006, Xcel Energy received notice of a purported class action lawsuit filed in U.S. District Court in the Southern District of Mississippi. The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ CO2 emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.” Plaintiffs allege in support of their claim, several legal

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theories, including negligence and public and private nuisance and seek damages related to the loss resulting from the hurricane. Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims. In August 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds. In September 2007, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Fifth Circuit. Oral arguments were presented to the Court of Appeals on Aug. 6, 2008. Pursuant to the court’s order of Sept. 26, 2008, re-argument was held on Nov. 3, 2008. No explanation was given for the order. The Court of Appeals has taken the matter under advisement.

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, the parent company of NSP-Minnesota, and 23 other utilities, oil, gas and coal companies. The suit was brought on behalf of approximately 400 native Alaskans, the Inupiat Eskimo, who claim that defendants’ emission of CO2 and other GHG contribute to global warming, which is harming their village. Plaintiffs claim that as a consequence, the entire village must be relocated at a cost of between $95 million and $400 million. Plaintiffs assert a nuisance claim under federal and state common law, as well as a claim asserting “concert of action” in which defendants are alleged to have engaged in tortious acts in concert with each other. Xcel Energy was not named in the civil conspiracy claim. Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss on June 30, 2008. The matter has now been fully briefed, with oral arguments set for May 19, 2009. It is unknown when the court will render a decision.

Employment, Tort and Commercial Litigation

Hoffman vs. Northern States Power Company — In March 2006, a purported class action complaint was filed in Minnesota state court, on behalf of NSP-Minnesota’s residential customers in Minnesota, North Dakota and South Dakota for alleged breach of a contractual obligation to maintain and inspect the points of connection between NSP-Minnesota’s wires and customers’ homes within the meter box. Plaintiffs claim NSP-Minnesota’s alleged breach results in an increased risk of fire and is in violation of tariffs on file with the MPUC. Plaintiffs seek injunctive relief and damages in an amount equal to the value of inspections plaintiffs claim NSP-Minnesota was required to perform over the past six years. In August 2006, NSP-Minnesota filed a motion for dismissal on the pleadings. In November 2006, the court issued an order denying NSP-Minnesota’s motion, but later, pursuant to a motion by NSP-Minnesota, certified the issues raised in NSP-Minnesota’s original motion for appeal as important and doubtful, and NSP-Minnesota filed an appeal with the Minnesota Court of Appeals.  In January 2008, the Minnesota Court of Appeals determined the plaintiffs’ claims are barred by the filed rate doctrine and remanded the case to the district court for dismissal. Plaintiffs petitioned the Minnesota Supreme Court for discretionary review, and the Supreme Court granted the petition.  On April 16, 2009, the Minnesota Supreme Court determined that the filed rate doctrine barred plaintiffs’ claims for compensatory damages and that under the primary jurisdiction doctrine plaintiffs’ claims for injunctive relief should be heard by the MPUC.  The Supreme Court stated that claims relating to North Dakota and South Dakota residents were not properly before the Court and should therefore be remanded to the district court for disposition consistent with the Supreme Court’s decision.

Nuclear Waste Disposal Litigation — In 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the United States requesting breach of contract damages for the U.S. Department of Energy’s (DOE) failure to begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contract between the DOE and NSP-Minnesota. At trial, NSP-Minnesota claimed damages in excess of $100 million through Dec. 31, 2004. On Sept. 26, 2007, the court awarded NSP-Minnesota $116.5 million in damages. In December 2007, the court denied the DOE’s motion for reconsideration. In February 2008, the DOE filed an appeal to the U.S. Court of Appeals for the Federal Circuit, and NSP-Minnesota cross-appealed on the cost of capital issue. In April 2008, the DOE asked the Court of Appeals to stay briefing until the appeals in several other nuclear waste cases have been decided, and the Court of Appeals granted the request. In December 2008, NSP-Minnesota made a motion in the Court of Appeals to lift the stay, which was denied by the Court of Appeals in February 2009. Results of the judgment will not be recorded in earnings until the appeal, regulatory treatment and amounts to be shared with ratepayers have been resolved. Given the uncertainties, it is unclear as to how much, if any, of this judgment will ultimately have a net impact on earnings.

In August 2007, NSP-Minnesota filed a second complaint against the DOE in the U.S. Court of Federal Claims (NSP II), again claiming breach of contract damages for the DOE’s continuing failure to abide by the terms of the contract. This lawsuit will claim damages for the period Jan. 1, 2005 through Dec. 31, 2008, which includes costs associated with the storage of spent nuclear fuel at Prairie Island and Monticello, as well as the costs of complying with state regulation relating to the storage of spent nuclear fuel. Per the court’s scheduling order, NSP- Minnesota’s expert report on damages was submitted on April 15, 2009, and asserts damages in excess of $250 million. The DOE must file its expert report by Oct. 15, 2009, and all discovery must be completed by the end of 2009. Trial is expected to take place in 2010.

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Siewert vs. Xcel Energy — In June 2004, plaintiffs, the owners and operators of a Minnesota dairy farm, brought an action in Minnesota state court against NSP-Minnesota alleging negligence in the handling, supplying, distributing and selling of electrical power systems; negligence in the construction and maintenance of distribution systems; and failure to warn or adequately test such systems. Plaintiffs allege decreased milk production, injury, and damage to a dairy herd as a result of stray voltage resulting from NSP-Minnesota’s distribution system. Plaintiffs claim losses of approximately $7 million. NSP-Minnesota denies all allegations. After its motion to dismiss plaintiffs’ claims was denied, NSP-Minnesota filed a motion to certify questions for immediate appellate review. In October 2007, the court granted NSP-Minnesota’s motion for certification, and oral arguments took place on Sept. 11, 2008. Mediation took place on Oct. 14, 2008, but the matter was not resolved. In December 2008, the Court of Appeals issued a decision ordering dismissal of Plaintiffs’ claims for injunctive relief, but otherwise rejecting NSP-Minnesota’s contentions and ordering the matter remanded for trial. The Minnesota Supreme Court subsequently granted NSP-Minnesota’s petition for further review on Feb. 17, 2009.

Fargo Gas Explosion — In September 2008, an explosion occurred at a duplex in Fargo, N.D. The explosion destroyed one side of the duplex and resulted in injuries to some of the residents. Xcel Energy subsequently provided a report to the U.S. Dept. of Transportation Pipeline and Hazardous Materials Safety Administration stating that natural gas migrated into the house and was ignited by an unknown source. Investigators identified a natural gas leak the size of a pinhole located 18 inches underground. The property owners and attorneys representing the injured residents have put Xcel Energy on notice of potential claims. Investigation into the incident is continuing.

7.   Short-Term Borrowings and Other Financing Instruments

Commercial Paper —At Dec. 31, 2008, NSP-Minnesota had commercial paper outstanding of $65.0 million with a weighted average interest rate of 2.57 percent.  NSP-Minnesota had no commercial paper outstanding at March 31, 2009.  At March 31, 2009 and Dec. 31, 2008, NSP-Minnesota had board approval to issue up to $500 million of commercial paper.

Money Pool— Xcel Energy has established a utility money pool arrangement that allows for short-term loans between the utility subsidiaries and from the holding company to the utility subsidiaries at market-based interest rates. The utility money pool arrangement does not allow loans from the utility subsidiaries to the holding company.  NSP-Minnesota has approval to borrow up to $250 million under the arrangement.  At Dec. 31, 2008, NSP-Minnesota had money pool borrowings of $63.5 million with a weighted average interest rate of 3.48 percent.  NSP-Minnesota had no money pool loans outstanding or money pool borrowings at March 31, 2009.

8.   Derivative Instruments

Effective Jan. 1, 2009, NSP-Minnesota adopted SFAS No. 161, which requires additional disclosures regarding why an entity uses derivative instruments, the volume of an entity’s derivative activities, the fair value amounts recorded to the consolidated balance sheet for derivatives, the gains and losses on derivative instruments included in the consolidated statement of income or deferred, and information regarding certain credit-risk-related contingent features in derivative contracts.

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 and vehicle fuel prices.  See additional information pertaining to the valuation of derivative instruments in Note 9 to the consolidated financial statements.

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 a specific period.  These derivative instruments are designated as cash flow hedges for accounting purposes.

At March 31, 2009, accumulated other comprehensive income 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 transactions impact earnings.

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, 2009, NSP-Minnesota had various utility commodity and vehicle fuel related contracts designated as cash flow hedges extending through December 2010.  Changes in the fair value of cash flow hedges are recorded in other comprehensive income or deferred as a regulatory asset or liability.  The classification as a regulatory asset or liability is

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based on the regulatory recovery mechanisms in place.  NSP-Minnesota recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three months ended March 31, 2009 and 2008.

At March 31, 2009, NSP-Minnesota had $5.7 million of net losses in accumulated other comprehensive income related to utility commodity and vehicle fuel cash flow hedges; $3.7 million is expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

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 these derivative instruments are deferred as a regulatory asset or liability, based on the regulatory recovery mechanisms in place.

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 income.

NSP-Minnesota had no derivative instruments designated as fair value hedges during the three months ended March 31, 2009, and as such, had no gains or losses from fair value hedges or related hedged transactions for the period.

The following table shows the major components of derivative instruments valuation in the consolidated balance sheets:

	March 31, 2009				Dec. 31, 2008
(Thousands of Dollars)	Derivative Instruments Valuation - Assets		Derivative Instruments Valuation - Liabilities		Derivative Instruments Valuation - Assets		Derivative Instruments Valuation - Liabilities
Long term purchased power agreements	$	145,744	$	227,084	$	151,884	$	230,715
Commodity derivatives	20,565		22,166		47,973		28,522
Total	$	166,309	$	249,250	$	199,857	$	259,237

In 2003, as a result of FASB Statement 133 Implementation Issue No. C20, 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.

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

	Three Months Ended March 31,
(Thousands of Dollars)	2009			2008
Accumulated other comprehensive income related to cash flow hedges at Jan 1	$	3,053		$	8,704
After-tax net unrealized losses related to derivatives accounted for as hedges	(123		)	(1,454		)
After-tax net realized losses (gains) on derivative transactions reclassified into earnings	618			(92		)
Accumulated other comprehensive income related to cash flow hedges at March 31	$	3,548		$	7,158

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The following table details the fair value of derivatives recorded to derivative instruments valuation in the consolidated balance sheet, by category:

	March 31, 2009
(Thousands of Dollars)	Fair Value		Counterparty Netting (a)			Derivative Instruments Valuation
Current derivative assets
Derivatives designated as cash flow hedges:
Electric commodity	$	3,758	$	311		$	4,069
Other derivative instruments:
Trading commodity	4,415		1,463			5,878
Electric commodity	253		—			253
	4,668		1,463			6,131
Total current derivative assets	$	8,426	$	1,774		$	10,200
Noncurrent derivative assets
Other derivative instruments:
Trading commodity	$	15,701	$	(5,336	)	$	10,365
Total noncurrent derivative assets	$	15,701	$	(5,336	)	$	10,365
Current derivative liabilities
Derivatives designated as cash flow hedges:
Electric commodity	$	3,472	$	311		$	3,783
Vehicle fuel and other commodity	3,877		—			3,877
	7,349		311			7,660
Other derivative instruments:
Trading commodity	3,142		(28		)	3,114
Electric commodity	1,670		—			1,670
	4,812		(28		)	4,784
Total current derivative liabilities	$	12,161	$	283		$	12,444
Noncurrent derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	2,210	$	—		$	2,210
Other derivative instruments:
Trading commodity	12,848		(5,336		)	7,512
Total noncurrent derivative liabilities	$	15,058	$	(5,336	)	$	9,722

(a) FASB Interpretation No. 39 Offsetting of Amounts Relating to Certain Contracts, as amended by FASB Staff Position FIN 39-1 Amendment of FASB Interpretation No. 39, 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.

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The following table details the impact of derivative activity during the three months ended March 31, 2009, on other comprehensive income, regulatory assets and liabilities, and income:

	Fair Value Changes Recognized During the Period in:						Pre-Tax Amounts Reclassified into Income During the Period from:						Pre-Tax Gain (Loss)
	Other			Regulatory			Other			Regulatory			Recognized
	Comprehensive			Assets and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Income (Loss)			Liabilities			Income (Loss)			Liabilities			in Income
Derivatives designated as cash flow hedges:
Interest rate	$	—		$	—		$	(53	)(a)	$	—		$	—
Electric commodity	—			(19,556		)	—			(3,512		)(c)	—
Natural gas commodity	—			(811		)	—			8,915		(d)	(6,950		)(d)
Vehicle fuel and other commodity	(208		)	—			1,097		(e)	—			—
	$	(208	)	$	(20,367	)	$	1,044		$	5,403		$	(6,950	)
Other derivative instruments:
Trading commodity	$	—		$	—		$	—		$	—		$	1,984	(b)
Electric commodity	—			(1,738		)	—			321		(c)	—
	$	—		$	(1,738	)	$	—		$	321		$	1,984

(a)	Recorded to interest charges.
(b)	Recorded to electric operating revenues.
(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 other operating and maintenance expenses.

At March 31, 2009, commodity derivatives recorded to derivative instruments valuation included derivative contracts with gross notional amounts of approximately 16,880,000 megawatt hours (MwH) of electricity and 3,164,000 gallons of vehicle fuel.  These amounts reflect the gross notional amounts of futures, forwards and financial transmission rights and are not reflective of net positions in the underlying commodities.  Notional amounts for options are also included on a gross basis, but are weighted for the probability of exercise.

Credit Related Contingent Features — Contract provisions of NSP-Minnesota’s derivative instruments may require the posting of collateral or settlement of the contracts for various reasons, including if NSP-Minnesota is unable to maintain its credit rating.  At March 31, 2009, NSP-Minnesota had no derivative instruments in a liability position under contracts that require the posting of collateral or settlement of the contracts upon a downgrade of NSP-Minnesota’s credit rating below investment grade.

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.  As of March 31, 2009, NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts.

9.   Fair Value Measurements

Effective Jan. 1, 2008, NSP-Minnesota adopted Fair Value Measurements (SFAS No. 157) for recurring fair value measurements.  SFAS No. 157 provides a single definition of fair value and requires enhanced disclosures about assets and liabilities measured at fair value. SFAS No. 157 establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the SFAS No. 157 hierarchy and examples of each level are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange.

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Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date.  The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.

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 with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value of financial transmission rights.

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 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.

The following tables present, for each of the SFAS No. 157 hierarchy levels, NSP-Minnesota’s assets and liabilities that are measured at fair value on a recurring basis:

	March 31, 2009
(Thousands of Dollars)	Level 1		Level 2		Level 3		Counterparty  Netting			Net Balance
Assets
Cash equivalents	$	—	$	30,000	$	—	$	—		$	30,000
Nuclear decommissioning fund	412,453		503,999		105,552		—			1,022,004
Commodity derivatives	—		5,085		19,042		(3,562		)	20,565
Total	$	412,453	$	539,084	$	124,594	$	(3,562	)	$	1,072,569
Liabilities
Commodity derivatives	$	—	$	9,721	$	17,498	$	(5,053	)	$	22,166
Total	$	—	$	9,721	$	17,498	$	(5,053	)	$	22,166

	Dec. 31, 2008
(Thousands of Dollars)	Level 1		Level 2		Level 3		Counterparty  Netting			Net Balance
Assets
Nuclear decommissioning fund	$	465,936	$	499,935	$	109,423	$	—		$	1,075,294
Commodity derivatives	—		17,039		38,207		(7,273		)	47,973
Total	$	465,936	$	516,974	$	147,630	$	(7,273	)	$	1,123,267
Liabilities
Commodity derivatives	$	—	$	21,509	$	14,960	$	(7,947	)	$	28,522
Total	$	—	$	21,509	$	14,960	$	(7,947	)	$	28,522

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The following table presents the changes in Level 3 recurring fair value measurements for the three months ended March 31, 2009 and 2008:

	2009						2008
(Thousands of Dollars)	Commodity Derivatives, Net			Nuclear Decommissioning Fund			Commodity Derivatives, Net			Nuclear Decommissioning Fund
Balance Jan. 1	$	23,247		$	109,423		$	15,345		$	108,656
Purchases, issuances, and settlements, net	(7		)	(4,812		)	(2,016		)	(10,251		)
Gains (losses) recognized in earnings	(2,193		)	—			272			—
Gains (losses) recognized as regulatory assets and liabilities	(19,503		)	941			(795		)	(1,173		)
Balance March 31	$	1,544		$	105,552		$	12,806		$	97,232

Losses on Level 3 commodity derivatives recognized in earnings for the three months ended March 31, 2009, include $1.3 million of net unrealized gains relating to commodity derivatives held at March 31, 2009.  Gains on Level 3 commodity derivatives recognized in earnings for the three months ended March 31, 2008, include $2.7 million of net unrealized gains relating to commodity derivatives held at March 31, 2008.  Realized and unrealized gains and losses on commodity trading activities are included in electric revenues.  Realized and unrealized gains and losses on short-term wholesale activities reflect the impact of regulatory recovery and are deferred as regulatory assets and liabilities.  Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a component of a nuclear decommissioning regulatory asset.

10.  Detail of Interest and Other Income (Expenses), Net

Interest and other income (expenses), net, for the three months ended March 31, consisted of the following:

	Three months ended March 31,
(Thousands of Dollars)	2009			2008
Interest income	$	1,176		$	4,710
Other non-operating income	13			919
Insurance policy expenses	(1,183		)	(1,318		)
Other non-operating expenses	(24		)	—
Total interest and other income (expenses), net	$	(18	)	$	4,311

11.Segment Information

NSP-Minnesota has two reportable segments:  regulated electric and regulated natural gas. Commodity trading operations are not a reportable segment and commodity-trading results are included in the regulated electric segment.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Three months ended March 31, 2009
Revenues from:
External customers	$	869,082	$	329,267	$	5,034	$	—		$	1,203,383
Internal customers	130		710		—		(840		)	—
Total revenues	$	869,212	$	329,977	$	5,034	$	(840	)	$	1,203,383
Segment net income	$	52,883	$	21,040	$	2,276	$	—		$	76,199
Three months ended March 31, 2008
Revenues from:
External customers	$	870,235	$	392,605	$	4,884	$	—		$	1,267,724
Internal customers	129		2,508		—		(2,637		)	—
Total revenues	$	870,364	$	395,113	$	4,884	$	(2,637	)	$	1,267,724
Segment net income	$	34,863	$	23,165	$	5,940	$	—		$	63,968

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12.  Comprehensive Income

The components of total comprehensive income are shown below:

	Three months ended March 31,
(Thousands of Dollars)	2009			2008
Net income	$	76,199		$	63,968
Other comprehensive income:
Unrealized loss — marketable securities	(95		)	—
Changes in unrecognized amounts of pension and retiree medical benefits	37			26
After-tax net unrealized losses related to derivatives accounted for as hedges	(123		)	(1,454		)
After-tax net realized losses (gains) on derivative transactions reclassified into earnings	618			(92		)
Other comprehensive income (loss)	437			(1,520		)
Comprehensive income	$	76,636		$	62,448

13.  Benefit Plans and Other Postretirement Benefits

Pension and other postretirement benefit disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to NSP-Minnesota.

Components of Net Periodic Benefit Cost (Credit)

	Three months ended March 31,
	2009			2008			2009			2008
							Postretirement Health
(Thousands of Dollars)	Pension Benefits						Care Benefits
Xcel Energy Inc.
Service cost	$	15,986		$	16,773		$	1,276		$	1,464
Interest cost	41,849			40,583			12,156			12,546
Expected return on plan assets	(63,360		)	(68,472		)	(5,394		)	(7,500		)
Amortization of transition obligation	—			—			3,496			3,644
Amortization of prior service cost (credit)	6,155			5,166			(652		)	(544		)
Amortization of net loss	2,929			2,859			4,885			2,718
Net periodic benefit cost (credit)	3,559			(3,091		)	15,767			12,328
(Cost) credits not recognized and additional cost recognized due to the effects of regulation	(487		)	2,592			973			973
Net benefit cost (credit) recognized for financial reporting	$	3,072		$	(499	)	$	16,740		$	13,301
NSP-Minnesota
Net periodic benefit cost (credit)	$	487		$	(2,372	)	$	3,739		$	3,493
(Cost) credits not recognized due to the effects of regulation	(487		)	2,592			—			—
Net benefit cost recognized for financial reporting	$	—		$	220		$	3,739		$	3,493

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 and the results of operations set forth in general instructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).

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Forward-Looking Information

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 the 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

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 the availability of credit and its impact on capital expenditures and the ability of Xcel Energy and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; 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; 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 of accounting regulatory bodies; the items described under Factors Affecting Results of Continuing 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, 2008 and Exhibit 99.01 to this report on Form 10-Q for the quarter ended March 31, 2009.

Market Risks

NSP-Minnesota is exposed to market risks, including changes in commodity prices and interest rates, as disclosed in Item 7A, Quantitative and Qualitative Disclosures About Market Risk in its Annual Report on Form 10-K for the year ended Dec. 31, 2008.  Commodity price and interest rate risks for NSP- Minnesota are mitigated in most jurisdictions due to cost-based rate regulation.

NSP-Minnesota maintains trust funds, as required by the Nuclear Regulatory Commission (NRC), to fund certain costs of nuclear decommissioning.   Those investments are exposed to price fluctuations in equity markets and changes in interest rates.  However, because the costs of nuclear decommissioning are recovered through NSP-Minnesota rates, fluctuations in investment fair value do not affect NSP-Minnesota’s consolidated results of operations.  Continued distress in the financial markets may impact the fair value of the debt and equity securities in the nuclear decommissioning trust funds, and pension and postretirement health care plan trusts, as well as NSP-Minnesota’s ability to earn a return on short-term investments of excess cash.  As of March 31, 2009, there have been no material changes to market risks from that set forth in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2008.

Results Of Operations

NSP-Minnesota’s net income was approximately $76.2 million for the first three months of 2009, compared with approximately $64.0 million for the first three months of 2008.

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power.  Due to fuel and purchased energy cost-recovery mechanisms for customers,  fluctuations in these costs do not materially affect electric utility margin.

NSP-Minnesota has two distinct forms of wholesale sales: short-term wholesale and commodity trading activities.  Short-term wholesale refers to energy-related purchase and sales activity and the use of certain financial instruments associated with the fuel required for and energy produced from NSP-Minnesota’s generation assets and energy and capacity purchased to serve native load.  Commodity trading is not associated with NSP-Minnesota’s generation assets or the energy or capacity purchased to serve native load.  Wholesale sales were immaterial to revenue and gross margin as a percentage of revenue at March 31, 2009 and 2008.

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Electric Revenues and Margins

Electric —The following tables detail the electric revenues and margin:

	Three months ended March 31,
(Millions of Dollars)	2009			2008
Electric revenues	$	869		$	870
Electric fuel and purchased power	(382		)	(414		)
Electric margin	$	487		$	456

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

Electric Revenues

(Millions of Dollars)	2009 vs. 2008
Fuel and purchased power cost recovery	$	(32	)
Trading revenues	(13		)
Firm wholesale	(3		)
Retail sales decline (excluding weather impact)	(2		)
Minnesota interim retail rate increase	30
MERP rider	5
Non-fuel riders	4
Interchange agreement billing with NSP-Wisconsin	2
Conservation program revenues	2
Other	6
Total decrease in electric revenues	$	(1	)

Electric Margin

(Millions of Dollars)	2009 vs. 2008
Minnesota interim retail rate increase	$	30
Interchange agreement billing with NSP-Wisconsin	8
MERP rider	5
Non-fuel riders	4
Conservation program revenues	2
Transmission revenues, net of expense	(5		)
Purchased capacity costs	(5		)
Retail sales decline (excluding weather impact)	(2		)
Trading margin	(2		)
Firm wholesale	(1		)
Other	(3		)
Total increase in electric margin	$	31

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)	2009			2008
Natural gas revenues	$	329		$	393
Cost of natural gas sold and transported	(261		)	(319		)
Natural gas margin	$	68		$	74

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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)	2009 vs. 2008
Purchased natural gas adjustment clause recovery	$	(63	)
Conservation program revenues	(4		)
Estimated impact of weather	(1		)
Other	4
Total decrease in natural gas revenues	$	(64	)

Natural Gas Margin

(Millions of Dollars)	2009 vs. 2008
Conservation program revenues	$	(4	)
Estimated impact of weather	(1		)
Other	(1		)
Total decrease in natural gas margin	$	(6	)

Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expenses — Other operating and maintenance expenses for the three months of 2009 increased $3.7 million, or 1.5 percent, compared with 2008.  The following summarizes the components of the changes for the three months ended March 31:

(Millions of Dollars)	2009 vs. 2008
Higher nuclear plant operation costs	$	10
Higher employee benefit costs	5
Higher labor costs	2
Interchange agreement billings with NSP-Wisconsin	1
Nuclear outage expenses, net of deferral	(12		)
Lower plant generation costs	(2		)
Lower consulting costs	(2		)
Other	2
Total increase in other operating and maintenance expenses	$	4

The increase in nuclear plant operation costs is driven primarily by an increase in security costs and regulatory fees, resulting from new NRC requirements.  The decline in nuclear outage expense is due to MPUC approval of the change the nuclear refueling outage recovery method from the direct expense method to the deferral and amortization method in the third quarter of 2008.

Depreciation and Amortization — Depreciation and amortization expense increased by approximately $1.4 million, or 1.3 percent, for the first three months of 2009, compared with the first three months of 2008.  The increase was primarily due to planned system expansion.

Conservation Program Expenses — Conservation program expenses decreased $4.7 million, or 24.2%, for the first three months of 2009, compared with the first three months of 2008.  The decrease was primarily due to an adjustment for over-recovery in 2008, which resulted from regulatory delays.

Interest and Other (Expenses) Income, Net — Interest and other (expenses) income, net decreased by approximately $4.3 million, or 100.4 percent, for the first three months of 2009, compared with the first three months of 2008.  The decrease was primarily due to lower interest income in 2008.

Allowance for Funds Used During Construction, Equity and Debt (AFDC) — AFDC is a non-cash amount capitalized as a part of construction costs representing the cost of financing the construction.  Generally, these costs are recovered from customers, in future rates, as the related property is depreciated.  AFDC, resulting in part from these projects, increased by approximately $0.3 million, or 3.1 percent, for the first three months of 2009 compared with the same period in 2008.  NSP-Minnesota’s overall increase in AFDC is due to the Monticello Extended Power Uprate Project and various nuclear projects.

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Income Taxes — Income tax expense increased by $9.5 million for the first quarter of 2009, compared with the same period in 2008.  The increase in income tax expense was primarily due to an increase in pretax income. The effective tax rate was 36.5 percent for the first quarter of 2009, compared with 34.9 percent for the same period in 2008.  The lower effective tax rate for the first quarter of 2008 was primarily due to the reversal of a FIN 48 liability resulting from a settlement with taxing authorities in the first quarter of 2008.  Excluding this reversal, the effective tax rate for the first quarter of 2008 would have been 37.0 percent.

Public Utility Regulation

Excelsior Energy — In December 2005, Excelsior, an independent energy developer, filed a power purchase agreement with the MPUC seeking a declaration that NSP-Minnesota be compelled to enter into an agreement to purchase the output from two integrated gas combined cycle (IGCC) plants to be located in northern Minnesota as part of the Mesaba Energy Project.  Excelsior filed this petition making claims pursuant to Minnesota statutes relating to an Innovative Energy Project and Clean Energy Technology.  NSP-Minnesota opposed the petition.

The MPUC referred this matter to a contested case hearing before an ALJ to act on Excelsior’s petition.  The contested case proceeding considered a 600 MW unit in Phase 1 and a second 600 MW unit in Phase 2 of the Mesaba Energy Project.

The MPUC issued its order for phase 1 of the hearing on Aug. 30, 2007.  In it, the MPUC found among other things, that Excelsior and NSP-Minnesota should resume negotiations toward an acceptable purchase power agreement, with assistance from the Minnesota Department of Commerce (MDOC) and the guidance provided by the order.

On Sept. 24, 2008, the MPUC denied Excelsior Energy’s Phase 2 request to approve a power purchase agreement related to its proposed second 600 MW IGCC generating facility.  The MPUC also set a May 1, 2009 deadline for Phase 1 of the proceeding in which it had previously ordered negotiations.  On Oct. 14, 2008, Excelsior sought rehearing of the MPUC’s Sept. 24, 2008 order.  On Dec. 9, 2008, the MPUC held further action in abeyance until after the May 1, 2009 deadline.

Wind Generation — In December 2008, the first NSP-Minnesota owned wind generation plant, the 100 MW Grand Meadow wind farm, went into service.  The project was developed through a build-own-transfer arrangement with a large wind energy developer (enXco) at a cost of approximately $210 million.  NSP-Minnesota plans to invest approximately $900 million over three years for a 201 MW project in southwestern Minnesota, called the Nobles Wind Project, and a 150 MW project in southeastern North Dakota, called the Merricourt Wind Project.  These projects are expected to be operational by the end of 2010 and 2011, respectively.  On Dec. 3, 2008, NSP-Minnesota filed petitions with the MPUC and the NDPSC seeking the required regulatory approvals for the two wind powered generating facilities.

NSP-Minnesota Transmission Certificates of Need — In August 2007, NSP-Minnesota and Great River Energy (on behalf of eight other regional transmission providers) filed a certificate of need application, for three 345 kilovolt (KV) transmission lines, as part of the CapX 2020 project.  The project to build the three lines includes construction of approximately 600 miles of new facilities at a cost of approximately $1.7 billion, with construction to be completed in phases.  The cost of the project to NSP-Minnesota and NSP-Wisconsin is estimated to be approximately $900 million.  These cost estimates will be revised after the regulatory process is completed.  The applicants filed rebuttal testimony recommending the modification of all three projects to be constructed as double circuit compatible with the first circuit strung during initial construction and the second circuit strung as needed. On April 16, 2009, the MPUC granted a certificate of need to construct three 345 KV electric transmission lines in Minnesota.  The MPUC also included a condition regarding assuring a portion of the capacity of the Brookings, S.D. to Hampton, Minn. line is used for renewable energy.

As part of CapX 2020, NSP-Minnesota and Great River Energy have filed two route permit applications with the MPUC.  On Dec. 29, 2008, the route permit application for the Brookings to Hampton Corner Project was filed.  On April 8, 2009, the route permit application for the Monticello to St. Cloud portion of the Fargo Twin Cities project was filed.  Route permit applications for the remaining parts of the three projects will be filed in Minnesota later this year.  Permit filings will also be made in adjoining states.  NSP-Minnesota anticipates the first routing decisions in early 2010.

As part of CapX 2020, Otter Tail Power Company, Minnesota Power and Minnkota Power Cooperative (on behalf of themselves and NSP-Minnesota and Great River Energy) filed a certificate of need application in March 2008 for a 230 KV transmission line between Bemidji and Grand Rapids, Minn.  A route application for this project was filed in June 2008.  The need application is uncontested; route hearings are expected to be conducted in late 2009, and an MPUC decision is anticipated by the second quarter of 2010.  The Bemidji-Grand Rapids line is expected to entail construction of

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approximately 68 miles of new facilities at a cost of $100 million, with construction to be completed by end of 2011.  The estimated cost to NSP-Minnesota is approximately $26 million.

In the second quarter of 2009, NSP-Minnesota plans to file a certificate of need application with the MPUC for two 161 KV transmission lines in the Rochester, Minn. area to support ongoing development of wind powered generation in southeastern Minnesota.  The proposal consists of an approximately 15 mile long, 161 KV transmission line north of Rochester, and an approximately 30 mile long, 161 KV transmission line southeast of Rochester.  The project’s estimated cost is $30 million.  An MPUC decision is anticipated in early 2010.

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 Xcel Energy’s utility subsidiaries. State and local agencies have jurisdiction over many of Xcel Energy’s utility 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, 2008.  See Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

Item 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports under the Exchange Act 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 the end of the period covered by this report, 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 procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

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

Part II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

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

Additional Information

See Notes 5 and 6 of the consolidated financial statements in this Quarterly Report on Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 and Notes 13 and 14 of NSP-Minnesota’s consolidated financial statements in its Annual Report on Form 10-K for the year ended Dec. 31, 2008 for a description of certain legal proceedings presently pending.

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, 2008, which is incorporated herein by reference. There have been no material changes to risk factors.

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Item 6. EXHIBITS

*Indicates incorporation by reference
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 States Power Co. (a Minnesota corporation) (Exhibit 3.02 to Form 8-K (file no. 001-31387) dated June 3, 2008).
31.01	Principal Executive Officer’s and 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.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on May 4, 2009.

Northern States Power Company (a Minnesota corporation)

(Registrant)

/s/  TERESA S. MADDEN

Teresa S. Madden

Vice President and Controller

/s/  BENJAMIN G.S. FOWKE III

Benjamin G.S. Fowke III

Vice President and Chief Financial Officer

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