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 Sept. 30, 2009

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 Nov. 2, 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.

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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 Sept. 30,						Nine Months Ended Sept. 30,
	2009			2008			2009			2008
Operating revenues
Electric	$	916,338		$	1,012,555		$	2,573,004		$	2,737,121
Natural gas	48,271			86,422			452,054			641,869
Other	4,750			4,119			14,088			13,695
Total operating revenues	969,359			1,103,096			3,039,146			3,392,685

Operating expenses
Electric fuel and purchased power	369,349			470,760			1,065,658			1,293,482
Cost of natural gas sold and transported	24,643			60,232			329,370			506,399
Cost of sales — other	2,849			2,645			7,864			7,381
Other operating and maintenance expenses	233,232			197,014			721,962			657,458
Conservation program expenses	14,381			16,143			41,784			50,265
Depreciation and amortization	90,776			105,433			291,893			312,014
Taxes (other than income taxes)	37,681			32,550			109,893			104,499
Total operating expenses	772,911			884,777			2,568,424			2,931,498

Operating income	196,448			218,319			470,722			461,187

Other income (expense), net	(1,026		)	849			(1,168		)	9,535
Allowance for funds used during construction — equity	6,876			6,396			21,247			19,577

Interest charges and financing costs
Interest charges — includes other financing costs of $1,424, $1,500, $4,371 and $4,338, respectively	47,651			49,940			147,563			147,600
Allowance for funds used during construction — debt	(4,285		)	(4,124		)	(13,237		)	(12,872		)
Total interest charges and financing costs	43,366			45,816			134,326			134,728

Income before income taxes	158,932			179,748			356,475			355,571
Income taxes	66,383			69,408			137,829			132,910
Net income	$	92,549		$	110,340		$	218,646		$	222,661

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)

	Nine Months Ended Sept. 30,
	2009			2008
Operating activities
Net income	$	218,646		$	222,661
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	295,941			318,568
Nuclear fuel amortization	59,520			46,765
Deferred income taxes	139,343			101,734
Amortization of investment tax credits	(2,628		)	(2,813		)
Allowance for equity funds used during construction	(21,247		)	(19,577		)
Net realized and unrealized hedging and derivative transactions	2,940			(10,868		)
Changes in operating assets and liabilities:
Accounts receivable	132,961			51,925
Accounts receivable from affiliates	(2,494		)	18,207
Accrued unbilled revenues	86,993			79,590
Inventories	77,658			(90,257		)
Recoverable purchased natural gas and electric energy costs	232			11,750
Other current assets	(16,378		)	5,452
Accounts payable	(66,970		)	(12,319		)
Net regulatory assets and liabilities	(25,529		)	(32,797		)
Other current liabilities	(5,094		)	(37,518		)
Change in other noncurrent assets	(225		)	11,702
Change in other noncurrent liabilities	(35,086		)	(11,978		)
Net cash provided by operating activities	838,583			650,227

Investing activities
Utility capital/construction expenditures	(652,863		)	(770,760		)
Allowance for equity funds used during construction	21,247			19,577
Purchase of investments in external decommissioning fund	(1,278,554		)	(643,497		)
Proceeds from sale of investments in external decommissioning fund	1,276,417			610,953
Investments in utility money pool arrangement	(55,500		)	(890,000		)
Repayments from utility money pool arrangement	55,500			890,000
Advances to affiliate	(33,400		)	(337,600		)
Advances from affiliate	33,400			396,200
Other investments	(1,041		)	8,503
Net cash used in investing activities	(634,794		)	(716,624		)

Financing activities
Proceeds from (repayment of) short-term borrowings, net	57,000			(341,500		)
Borrowings under utility money pool arrangement	469,300			259,600
Repayments under utility money pool arrangement	(415,800		)	(354,700		)
Proceeds from issuance of long-term debt	—			493,751
Repayment of long-term debt, including reacquisition premiums	(250,024		)	(7		)
Capital contributions from parent	132,728			206,762
Dividends paid to parent	(174,246		)	(171,211		)
Net cash (used in) provided by financing activities	(181,042		)	92,695

Net increase in cash and cash equivalents	22,747			26,298
Cash and cash equivalents at beginning of period	12,343			24,626
Cash and cash equivalents at end of period	$	35,090		$	50,924

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(163,623	)	$	(159,087	)
Cash received (paid) for income taxes, net	26,506			(36,568		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	13,149		$	11,114

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in thousands of dollars)

	Sept. 30, 2009			Dec. 31, 2008
Assets
Current assets
Cash and cash equivalents	$	35,090		$	12,343
Accounts receivable, net	280,195			413,156
Accounts receivable from affiliates	14,912			12,418
Accrued unbilled revenues	161,458			248,451
Inventories	268,245			345,903
Recoverable purchased natural gas and energy costs	26,373			26,605
Derivative instruments valuation	81,191			70,252
Prepayments and other	65,822			48,493
Total current assets	933,286			1,177,621

Property, plant and equipment, net	7,165,442			6,804,794

Other assets
Nuclear decommissioning fund and other investments	1,244,580			1,084,827
Regulatory assets	754,637			828,712
Derivative instruments valuation	121,535			129,605
Other	20,172			21,266
Total other assets	2,140,924			2,064,410
Total assets	$	10,239,652		$	10,046,825

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	175,048		$	250,060
Short-term debt	122,000			65,000
Borrowings under utility money pool arrangement	117,000			63,500
Accounts payable	316,727			389,676
Accounts payable to affiliates	47,310			52,291
Taxes accrued	134,785			121,163
Accrued interest	34,231			68,009
Dividends payable to parent	58,463			58,414
Derivative instruments valuation	32,823			39,816
Other	63,119			50,696
Total current liabilities	1,101,506			1,158,625

Deferred credits and other liabilities
Deferred income taxes	1,180,622			987,050
Deferred investment tax credits	37,626			40,254
Asset retirement obligations	1,103,316			1,055,689
Regulatory liabilities	490,442			459,880
Pension and employee benefit obligations	254,928			269,537
Derivative instruments valuation	220,633			219,421
Other	73,003			77,775
Total deferred credits and other liabilities	3,360,570			3,109,606

Commitments and contingent liabilities
Capitalization
Long-term debt	2,538,480			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	2,048,584			1,915,857
Retained earnings	1,194,185			1,149,833
Accumulated other comprehensive (loss) income	(3,683		)	205
Total common stockholder’s equity	3,239,096			3,065,905
Total liabilities and equity	$	10,239,652		$	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 Sept. 30, 2009 and Dec. 31, 2008; the results of its operations for the three and nine months ended Sept. 30, 2009 and 2008; and its cash flows for the nine months ended Sept. 30, 2009 and 2008. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2009 up to Nov. 2, 2009, which is the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. 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

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.

2. Accounting Pronouncements

Recently Adopted

Business Combinations — In December 2007, the Financial Accounting Standards Board (FASB) issued new guidance on business combinations 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. This new guidance 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 the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Noncontrolling Interests — Also in December 2007, the FASB issued new guidance on noncontrolling interests in consolidated financial statements 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. This new guidance was effective for fiscal years beginning on or after Dec. 15, 2008. NSP-Minnesota implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Derivatives and Hedging Disclosures — In March 2008, the FASB issued new guidance on disclosures about derivative instruments and hedging activities 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. The guidance amends and expands previous disclosure requirements for derivative instruments and hedging activities, including disclosures of objectives and strategies for using derivatives, gains and losses on derivative instruments, and credit-risk-related contingent features in derivative contracts. This new guidance was effective for fiscal years and interim periods beginning after Nov. 15, 2008. NSP-Minnesota implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements. For further discussion and the required disclosures, see Note 8 to the consolidated financial statements.

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Interim Fair Value Disclosures — In April 2009, the FASB issued new guidance on interim disclosures about fair value of financial instruments which requires that disclosures regarding the fair value of financial instruments be included in interim financial statements. This new guidance was effective for interim periods ending after June 15, 2009. NSP-Minnesota implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements. For further discussion and the required disclosures, see Note 9 to the consolidated financial statements.

Fair Value in Inactive Markets — Also in April 2009, the FASB issued new guidance for identifying market transactions that are not orderly and determining fair value when market trading activity has decreased significantly. The new guidance emphasizes that even if there has been a significant decrease in the volume and level of market activity for an asset or liability, fair value still represents the exit price in an orderly transaction between market participants. This new guidance was effective for interim and annual periods ending after June 15, 2009. NSP-Minnesota implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Other-Than-Temporary Impairments — Additionally in April 2009, the FASB issued new guidance on recognition and presentation of other-than-temporary impairments 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. This new guidance was effective for interim and annual periods ending after June 15, 2009. NSP-Minnesota implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Subsequent Events — In May 2009, the FASB issued new guidance on subsequent events which establishes general standards of accounting and disclosure for events that occur after the balance sheet date but before financial statements are issued. The guidance is consistent with the auditing literature historically used for accounting and disclosure of subsequent events, however, it requires an entity to disclose the date through which subsequent events have been evaluated. This new guidance was effective for interim and annual periods ending after June 15, 2009. NSP-Minnesota implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Accounting Standards Codification — In June 2009, the FASB issued Topic 105 — Generally Accepted Accounting Principles Amendments Based on Statement of Financial Accounting Standards No. 168 — The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles (Accounting Standards Update (ASU) No. 2009-01), which updates the FASB Accounting Standards Codification (ASC or Codification) to state that the Codification is to be the single source of authoritative GAAP, other than the guidance put forth by the SEC. All other accounting literature not included in the Codification is to be considered non-authoritative. The updates to the Codification contained in ASU No. 2009-01 were effective for interim and annual periods ending after Sept. 15, 2009. NSP-Minnesota implemented the guidance set forth by ASU No. 2009-01, recognizing the Codification as the single source of authoritative GAAP, other than the guidance put forth by the SEC, on July 1, 2009. The implementation did not have a material impact on NSP-Minnesota’s consolidated financial statements.

Recently Issued

Postretirement Benefit Plans — In December 2008, the FASB issued new guidance on employers’ disclosures about postretirement benefit plan assets. The guidance will amend and expand previous disclosure requirements for 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. This new guidance is effective for disclosures for fiscal years ending after Dec. 15, 2009. NSP-Minnesota does not expect the implementation of the guidance to have a material impact on its consolidated financial statements.

Consolidation of Variable Interest Entities — In June 2009, the FASB issued new guidance on consolidation of variable interest entities. The guidance will significantly affect various elements of consolidation under existing accounting standards, including the determination of whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary. This new guidance is effective for fiscal years beginning after Nov. 15, 2009. NSP-Minnesota is currently evaluating the impact of this guidance on its consolidated financial statements.

Fair Value of Liabilities — In August 2009, the FASB issued Fair Value Measurements and Disclosures (Topic 820) — Measuring Liabilities at Fair Value (ASU No. 2009-05), which will update the Codification with clarifications for measuring the fair value of liabilities. The liability-specific guidance includes clarifications and guidelines for using, when available, the most observable prices in active markets for identical liabilities or similar liabilities, or the prices of identical liabilities or similar liabilities traded as assets, rather than more complex and less observable valuation techniques and inputs such as those used in a present value model. The updates to the Codification contained in ASU No. 2009-05 are effective for interim and annual periods beginning after its August, 2009 issuance. NSP-Minnesota does not expect the implementation of these changes in the Codification to have a material impact on its consolidated financial statements.

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3. Selected Balance Sheet Data

(Thousands of Dollars)	Sept. 30, 2009			Dec. 31, 2008
Accounts receivable, net
Accounts receivable	$	303,090		$	438,855
Less allowance for bad debts	(22,895		)	(25,699		)
	$	280,195		$	413,156
Inventories
Materials and supplies	$	106,315		$	97,945
Fuel	108,745			141,190
Natural gas	53,185			106,768
	$	268,245		$	345,903
Property, plant and equipment, net
Electric plant	$	9,872,898		$	9,472,073
Natural gas plant	947,008			916,740
Common and other property	458,825			452,308
Construction work in progress	596,749			615,734
Total property, plant and equipment	11,875,480			11,456,855
Less accumulated depreciation	(5,005,992		)	(4,907,681		)
Nuclear fuel	1,711,047			1,611,193
Less accumulated amortization	(1,415,093		)	(1,355,573		)
	$	7,165,442		$	6,804,794

4. Income Taxes

NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated income tax returns.

Federal Audit — 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. The IRS commenced an examination of tax years 2006 and 2007 in the third quarter of 2008, and this audit is expected to be completed in the first quarter of 2010. As of Sept. 30, 2009, the IRS had not proposed any material adjustments to tax years 2006 and 2007.

State Audits — 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 Sept. 30, 2009, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2004. There currently are no state income tax audits in progress.

Unrecognized Tax Benefits — The amount of unrecognized tax benefits was $21.9 million and $20.2 million on Sept. 30, 2009 and Dec. 31, 2008, respectively. The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryovers of $2.7 million on Sept. 30, 2009 and $4.4 million on Dec. 31, 2008.

The unrecognized tax benefit balance included $6.9 million and $7.2 million of tax positions on Sept. 30, 2009 and Dec. 31, 2008, respectively, which if recognized would affect the annual effective tax rate. In addition, the unrecognized tax benefit balance included $15.0 million and $13.0 million of tax positions on Sept. 30, 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 $4.1 million from June 30, 2009 to Sept. 30, 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. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefits could decrease up to approximately $10 million.

The amount of interest expense related to unrecognized tax benefits reported within interest charges in the third quarter of 2009 was $0.4 million. The amount of interest expense related to unrecognized tax benefits reported within interest charges in the third quarter of 2008 was $0.1 million. The liability for interest related to unrecognized tax benefits was $1.8 million and $1.3 million on Sept. 30, 2009 and Dec. 31, 2008, respectively.

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No amounts were accrued for penalties as of Sept. 30, 2009 or 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 discussion 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 — In November 2008, NSP-Minnesota filed a request with the MPUC to increase Minnesota electric rates by $156 million annually. This request was later modified to $136 million.

In September 2009, the MPUC voted to approve a rate increase of approximately $91.4 million. As part of its decision, the MPUC approved a 10-year life extension of the Prairie Island nuclear plant for purposes of determining depreciation and decommissioning expenses, effective Jan. 1, 2009. This decision reduced NSP-Minnesota’s overall revenue deficiency by approximately $40 million, while at the same time reducing expense accruals by a corresponding amount. A summary of the key terms is listed below:

	Revised Request	Approved
Rate increase	$136 million	$91 million
Return on equity	11.0%	10.88%
Equity ratio	52.5%	52.5%
Electric rate base	$4.1 billion	$4.1 billion
Depreciation life extension for Prairie Island nuclear plant	0 years	10 years

As of Sept. 30, 2009, NSP-Minnesota accrued a customer refund of approximately $30.2 million to reflect the difference between interim rates that were implemented Jan. 2, 2009 and the amount approved by the MPUC. The written order was issued Oct. 23, 2009.

Electric, Purchased Gas and Resource Adjustment Clauses

Transmission Cost Recovery (TCR) Rider — The MPUC has approved a TCR rider, which allows annual adjustments to retail electric rates to provide recovery of incremental transmission investments between rate cases. In October 2008, NSP-Minnesota submitted its proposed revised 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. In June 2009, the MPUC approved the rider request. The revised TCR rate recovery factors were placed into effect in July 2009. In September 2009, NSP-Minnesota submitted its proposed revised rate factors, seeking to recover an additional $15.6 million in TCR rates in 2010. The request is pending MPUC action.

Renewable Energy Standard (RES) Rider — The MPUC has approved an RES rider to recover the costs for utility-owned projects implemented in compliance with the RES. Under the rider, NSP-Minnesota recovered approximately $14.5 million in 2008 attributable to the Grand Meadow wind farm. In 2008, NSP-Minnesota submitted the RES rider for recovery of approximately $22 million in 2009 attributable to the Grand Meadow wind farm. In February 2009, the MPUC approved the rider request. The revised RES rate recovery factors were placed into effect in March 2009. In September 2009, NSP-Minnesota submitted its proposed revised rate factors, seeking to recover an additional $44.4 million in RES rates in 2010. The request is pending MPUC action.

Metropolitan Emissions Reduction Project (MERP) Rider — In October 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 $113.7 million in 2009, an increase of approximately $18.1 million over 2008. New rates went into effect automatically on Jan. 1, 2009, as stipulated. MPUC approval is still pending. On Oct 1, 2009, NSP-Minnesota filed its proposed MERP rider for 2010 designed to recover costs related to MERP environmental improvement projects of $116.7 million. These new rates are expected to go into effect automatically on Jan. 1, 2010. NSP-Minnesota received comments on its 2009 MERP rider on Oct. 19, 2009, recommending the MPUC approve the 2009 proposed rates.

State Energy Policy (SEP) Rider — In March 2009, NSP-Minnesota filed a proposed SEP rider for 2009 designed to recover costs related to state energy policy mandates and a cast iron natural gas pipe replacement project that is intended to reduce greenhouse gas

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(GHG) emissions. Under this rider, NSP-Minnesota proposes to recover approximately $2.5 million from its electric customers and $0.1 million from its natural gas customers in 2009. In September 2009, the MPUC approved the rider request. The revised SEP rate recovery factors were placed into effect in October 2009.

Annual Automatic Adjustment Report for 2007/2008 — 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 fuel clause adjustment (FCA). In addition, approximately $680 million of purchased natural gas and transportation costs were recovered through the purchased gas adjustment (PGA). NSP-Minnesota received comments on its 2008 electric annual automatic adjustment report in August 2009, which sought clarifications in the areas of transmission maintenance expenses, MISO revenue neutrality uplift charges and costs, and contractor non-performance responsibility for replacement energy costs. NSP-Minnesota received comments on its 2008 natural gas annual automatic adjustment report in June 2009, which recommends that the MPUC accept the 2008 report and PGA true up, and authorize its implementation. MPUC approval of both reports is pending.

Annual Automatic Adjustment Report for 2008/2009 — In September 2009, NSP-Minnesota filed its annual automatic adjustment reports for July 1, 2008 through June 30, 2009. During that time period, $803.6 million in fuel and purchased energy costs were recovered from Minnesota electric customers through the FCA. In addition, approximately $499.4 million of purchased natural gas and transportation costs were recovered through the PGA. MPUC approval is pending.

Conservation Incentive Filing — Minnesota state agencies convened a work group to review the current energy efficiency incentive mechanism. The work group reached a consensus in the spring of 2009 that a shared savings model was the best structure for incenting cost-effective conservation. In July 2009, NSP-Minnesota filed its proposed incentive plan for achieving significantly higher demand side management (DSM) goals. The incentive would allow for sharing of savings of up to 15 percent of the net present value of benefits, depending on the level of savings achieved. NSP-Minnesota received comments on its proposed incentive mechanism in September 2009, which recommended minor modifications that do not significantly impact the potential award scale. An MPUC decision on the proposed plan is pending.

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 2008, NSP-Minnesota rebilled approximately 5,000 of these customers for their estimated consumption and then ceased rebilling as both the MPUC and North Dakota Public Service Commission (NDPSC) opened investigations into this matter. NSP-Minnesota has initiated dispute resolution with its provider of the AMR modules and meter reading services.

Pursuant to the NDPSC-approved plan, which provided customers with a $50 service quality credit for each customer experiencing a module failure, NSP-Minnesota began implementing the service quality credits and the rebilling of remaining North Dakota customers in June 2009. In total, NSP-Minnesota rebilled North Dakota customers approximately $1.5 million for the estimated gas usage during the module failure period.

In March 2009, NSP-Minnesota filed with the MPUC for a proposed $50 service quality credit for each customer experiencing a module failure. On July 15, 2009, NSP-Minnesota filed an application to withdraw its request to rebill affected customers as too much time would have lapsed from the time of meter failures to the expected time (if approved) for rebilling. Although the MPUC order is still pending, the MPUC approved NSP-Minnesota’s withdrawal of its request to rebill affected customers at its hearing in September 2009. 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. As of Sept. 30, 2009, NSP-Minnesota has accrued an amount sufficient to cover the estimated impact.

Annual Review of Remaining Lives — In February 2009, NSP-Minnesota filed a petition 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 Office of Energy Security (OES) recommended a 10-year lengthening of depreciation life of the Prairie Island nuclear plant. In July 2009, the MPUC approved the proposed service lives, salvage rates, and resulting depreciation rates effective Jan. 1, 2009, for plant in service, with the exception of the Prairie Island nuclear plant. The MPUC deferred the determination of the appropriate depreciation rates for the Prairie Island nuclear plant to the pending NSP-Minnesota electric rate case. In the electric rate case, the MPUC extended the depreciation life of the Prairie Island nuclear plant by 10 years beyond the current license life in light of NSP-Minnesota’s application to extend the life of its nuclear plants by 20 years.

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Nuclear Decommissioning Expenses — In June 2009, the MPUC issued its order in its review of NSP-Minnesota’s 2009 nuclear plant decommissioning accruals. The order extended the decommissioning life for the Prairie Island nuclear plant by 10 years. The order reduced the amount of future nuclear decommissioning expenses that must be collected from customers from $32 million to zero, effective Jan. 1, 2009.

In August 2009, NSP-Minnesota filed a proposal with the MPUC to provide one-time refunds to return to customers their contributions of $22.8 million made to the external escrow decommissioning fund for the Monticello nuclear plant. In October 2009, NSP-Minnesota received comments on its proposed refund plan, which recommends approval with minor modifications to the proposed refund mechanics. MPUC action is pending.

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

South Dakota Electric Rate Case — In June 2009, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $18.6 million annually, or 12.7 percent. This proposed increase includes approximately $2.9 million in revenues currently recovered through automatic recovery mechanisms. Thus, the requested increase, net of current automatic recovery mechanisms, is approximately $15.7 million or 10.7 percent. The request is based on a 2008 historic test year adjusted for known and measurable changes in rate base and operating and maintenance expenses, an electric rate base of $282 million, a requested return on equity (ROE) of 11.25 percent, and an equity ratio of 51.63 percent.

Rates may be implemented as early as January 2010, based on statutory requirements in South Dakota. The procedural schedule is as follows:

· Staff and intervenor testimony on Nov. 20, 2009;

· NSP-Minnesota rebuttal testimony on Dec. 4, 2009; and

· Technical and public hearings on Dec. 9 – 11, 2009.

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

Revenue Sufficiency Guarantee (RSG) Charges — The MISO tariff charges certain market participants a real-time RSG charge, which is designed to ensure that any generator scheduled or dispatched by MISO will receive no less than its offer price for start-up, no-load and incremental energy. A proposal in 2005 by MISO to refine the RSG charge initiated protracted proceedings. In the subsequent compliance proceeding, the FERC has issued numerous orders, attempting to refine and clarify the RSG charge. With the issuance of these orders, the FERC has directed certain refunds to market participants, but has subsequently refined or waived various refund requirements. The FERC granted rehearing in part of certain earlier orders directing refunds to correct a rate mismatch in the RSG charge. Specifically, a June 2009 order waived refunds for the period from April 2005 to November 2007, and directed MISO to correct the rate mismatch (through refunds) from November 2007 to November 2008.

In August 2007, numerous parties filed complaints against MISO, arguing that the allocation of the RSG charge (only to certain market participants actually withdrawing energy) was unjust, unreasonable, and unduly discriminatory. After protracted proceedings, the FERC found in November 2008 that the RSG charge was unjust and unreasonable, and directed refunds. In May 2009, FERC granted rehearing in part regarding the applicability of refunds for the RSG charges. Specifically, the FERC determined that the refund-effective date is November 2008, the date of the FERC order determining that the allocation to market participants of the RSG charges was unjust and unreasonable.

The FERC directed MISO to implement an interim RSG cost allocation to be effective starting in August 2007. The FERC further directed MISO to submit a complete and final proposal, to be implemented on a prospective basis after the commencement of the MISO’s ancillary services markets in January 2009. In February 2009, MISO submitted a filing to implement the new RSG rate design; however, the FERC has not yet rendered a final decision to implement the new rate design. Moreover, disputes have arisen regarding whether or not some resources should be assessed to the RSG under the interim rate. In August 2009, the FERC issued an order in which it invalidated numerous exemptions to the RSG that had previously been utilized by MISO through its business practice manuals. Several parties have sought rehearing and a final FERC decision is still pending.

Xcel Energy is a party to each of the relevant RSG-related proceedings. Each of the relevant RSG-related orders has been the subject of requests for rehearing at the FERC and petitions for review filed at the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit). The separate RSG proceedings have proceeded in parallel at the FERC, and the most recent orders (May, June and August 2009), are subject to pending requests for rehearing. The D.C. Circuit proceedings are being held in abeyance pending final action in the FERC proceedings.

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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 Sept. 30, 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 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 (CAA) 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 CAA’s mobile source program, and does not automatically trigger regulation under other provisions of the CAA 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.

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 SO2 and 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. The EPA has indicated that a CAIR replacement rule will be proposed in early 2010 with finalization planned for early 2011.

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.

On May 12, 2009, EPA issued a proposed rule to stay the effectiveness of CAIR in Minnesota. NSP-Minnesota expects the EPA to complete this regulatory action before 2009 NOx allowances must be surrendered in February 2010. As such, cost estimates are not included at this time for NSP-Minnesota.

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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 consider a cost benefit analysis when establishing BTA. The decision overturned only one aspect of the Court of Appeals’ earlier opinion, and 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 of Appeals’ 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, the parent company of NSP-Minnesota, 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. On Sept. 21, 2009, the Court of Appeals issued an opinion reversing the lower court decision. Xcel Energy intends to file a petition for rehearing or rehearing en banc on or before Nov. 5, 2009.

Comer vs. Xcel Energy Inc. et al. — In April 2006, Xcel Energy, the parent company of NSP-Minnesota, 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 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. On Oct. 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court decision, in part, concluding that the plaintiffs pleaded sufficient facts to overcome the constitutional challenges that formed the basis for dismissal by the district court. It is anticipated that Xcel Energy will file a petition for rehearing or rehearing en banc.

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

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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 GHGs 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. On Oct. 15, 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds. It is unknown whether plaintiffs intend to appeal this decision.

Employment, Tort and Commercial Litigation

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. In late August 2009, the Court agreed to give the DOE an unspecified extension of time to clarify issues regarding NSP-Minnesota’s claim and to file its expert report. Trial is expected to take place in 2010.

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. All briefs have been filed, but the Court has not yet set a date for oral argument.

7. Short-Term Borrowings and Other Financing Instruments

Commercial Paper — At Sept. 30, 2009 and Dec. 31, 2008, NSP-Minnesota had commercial paper outstanding of $122.0 million and $65.0 million, respectively. The weighted average interest rates at Sept. 30, 2009 and Dec. 31, 2008 were 0.11 percent and 2.57 percent, respectively. At Sept. 30, 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 Sept. 30, 2009 and Dec. 31, 2008, NSP-Minnesota had money pool borrowings of $117.0 million and $63.5 million, respectively. The weighted average interest rates at Sept. 30, 2009 and Dec. 31, 2008 were 0.50 percent and 3.48 percent, respectively.

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8. Derivative Instruments

Effective Jan. 1, 2009, NSP-Minnesota adopted new guidance on disclosures about derivative instruments and hedging activities contained in ASC 815 Derivatives and Hedging, 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, vehicle fuel prices, as well as variances in forecasted weather. See additional information pertaining to the valuation of derivative instruments in Note 10 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 generally designated as cash flow hedges for accounting purposes.

At Sept. 30, 2009, accumulated other comprehensive income related to interest rate derivatives included $0.1 million of net losses 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 Sept. 30, 2009, NSP-Minnesota had various utility commodity and vehicle fuel related contracts designated as cash flow hedges extending through December 2012. NSP-Minnesota also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on the commission approved regulatory recovery mechanism. NSP-Minnesota recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three and nine months ended Sept. 30, 2009 and 2008.

At Sept. 30, 2009, NSP-Minnesota had $2.9 million of net losses in accumulated other comprehensive income related to utility commodity and vehicle fuel cash flow hedges of which $2.4 million is expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

Additionally, NSP-Minnesota enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in income.

NSP-Minnesota had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 2009. Therefore, no gains or losses from fair value hedges or related hedged transactions for the period were recognized.

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

	Sept. 30, 2009				Dec. 31, 2008
	Derivative		Derivative		Derivative		Derivative
	Instruments		Instruments		Instruments		Instruments
	Valuation -		Valuation -		Valuation -		Valuation -
(Thousands of Dollars)	Assets		Liabilities		Assets		Liabilities
Long term purchased power agreements	$	133,464	$	219,822	$	151,884	$	230,715
Interest rate derivatives	—		10,865		—		—
Commodity derivatives	69,262		22,769		47,973		28,522
Total	$	202,726	$	253,456	$	199,857	$	259,237

In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting contained in ASC 815 Derivatives and Hedging, 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

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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 tables:

	Three Months Ended Sept. 30,
(Thousands of Dollars)	2009			2008
Accumulated other comprehensive income related to cash flow hedges at July 1	$	4,797		$	7,235
After-tax net unrealized losses related to derivatives accounted for as hedges	(6,533		)	(1,408		)
After-tax net realized losses (gains) on derivative transactions reclassified into earnings	471			(32		)
Accumulated other comprehensive (loss) income related to cash flow hedges at Sept. 30	$	(1,265	)	$	5,795

	Nine Months Ended Sept. 30,
(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	(5,972		)	(2,753		)
After-tax net realized losses (gains) on derivative transactions reclassified into earnings	1,654			(156		)
Accumulated other comprehensive (loss) income related to cash flow hedges at Sept. 30	$	(1,265	)	$	5,795

The following tables detail the fair value of commodity and interest rate derivatives recorded to derivative instruments valuation in the consolidated balance sheet, by category:

	Sept. 30, 2009
						Derivative
			Counterparty			Instruments
(Thousands of Dollars)	Fair Value		Netting (a)			Valuation
Current derivative assets
Other derivative instruments:
Trading commodity	$	14,298	$	(7,651	)	$	6,647
Electric commodity	43,924		945			44,869
Natural gas commodity	4,772		343			5,115
Total current derivative assets	$	62,994	$	(6,363	)	$	56,631

Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	47	$	—		$	47
Other derivative instruments:
Trading commodity	18,124		(6,483		)	11,641
Natural gas commodity	943		—			943
	19,067		(6,483		)	12,584
Total noncurrent derivative assets	$	19,114	$	(6,483	)	$	12,631

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	Sept. 30, 2009
						Derivative
			Counterparty			Instruments
(Thousands of Dollars)	Fair Value		Netting (a)			Valuation
Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate derivatives	$	2,643	$	—		$	2,643
Vehicle fuel and other commodity	2,591		—			2,591
	5,234		—			5,234
Other derivative instruments:
Trading commodity	13,511		(9,696		)	3,815
Electric commodity	7,696		946			8,642
Natural gas commodity	264		343			607
	21,471		(8,407		)	13,064
Total current derivative liabilities	$	26,705	$	(8,407	)	$	18,298

Noncurrent derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate derivatives	$	8,222	$	—		$	8,222
Vehicle fuel and other commodity	547		—			547
	8,769		—			8,769
Other derivative instruments:
Trading commodity	13,053		(6,486		)	6,567
Total noncurrent derivative liabilities	$	21,822	$	(6,486	)	$	15,336

(a)

ASC 815 Derivatives and Hedging, permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between NSP-Minnesota and a counterparty. A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

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The following tables detail the impact of derivative activity during the three and nine months ended Sept. 30, 2009, on other comprehensive income, regulatory assets and liabilities, and income:

	Three Months Ended Sept. 30, 2009
	Fair Value Changes Recognized						Pre-Tax Amounts Reclassified into Income						Pre-Tax Gains
	During the Period in:						During the Period from:						(Losses)
	Other			Regulatory			Other			Regulatory			Recognized
	Comprehensive			Assets and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Income (Loss)			Liabilities			Income			Liabilities			in Income

Derivatives designated as cash flow hedges
Interest rate	$	(10,865	)	$	—		$	(54	)(e)	$	—		$	—
Vehicle fuel and other commodity	(182		)	—			852		(a)	—			—
	$	(11,047	)	$	—		$	798		$	—		$	—

Other derivative instruments
Trading commodity	$	—		$	—		$	—		$	—		$	3,200	(b)
Electric commodity	—			(8,012		)	—			1,284		(c)	—
Natural gas commodity	—			6,527			—			—			—
Other	—			—			—			—			—
	$	—		$	(1,485	)	$	—		$	1,284		$	3,200

	Nine Months Ended Sept. 30, 2009
	Fair Value Changes Recognized						Pre-Tax Amounts Reclassified into Income						Pre-Tax Gains
	During the Period in:						During the Period from:						(Losses)
	Other			Regulatory			Other			Regulatory			Recognized
	Comprehensive			Assets and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Income (Loss)			Liabilities			Income			Liabilities			in Income

Derivatives designated as cash flow hedges

Interest rate	$	(10,865	)	$	—		$	(161	)(e)	$	—		$	—
Electric commodity	—			(18,600		)	—			(4,755		)(c)	—
Natural gas commodity	—			(810		)	—			8,915		(d)	(6,951		)(d)
Vehicle fuel and other commodity	767			—			2,959		(a)	—			—
	$	(10,098	)	$	(19,410	)	$	2,798		$	4,160		$	(6,951	)

Other derivative instruments
Trading commodity	$	—		$	—		$	—		$	—		$	4,724	(b)
Electric commodity	—			35,329			—			898		(c)	—
Natural gas commodity	—			5,451			—			—			—
Other commodity	—			—			—			—			200		(b)
	$	—		$	40,780		$	—		$	898		$	4,924

(a) Recorded to other operating and maintenance expenses.

(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 interest charges.

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At Sept. 30, 2009, commodity derivatives recorded to derivative instruments valuation included derivative contracts with gross notional amounts of approximately 22,892,000 megawatt hours (MwH) of electricity, 16,480,000 MMBtu of natural gas and 2,475,000 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 the derivative instruments that NSP-Minnesota enters into may require the posting of collateral or settlement of the contracts for various reasons, including if NSP-Minnesota is unable to maintain its credit rating. At Sept. 30, 2009, if the credit rating of NSP-Minnesota were downgraded below investment grade, no contracts underlying NSP-Minnesota’s derivative liabilities would require the posting of collateral or contract settlement upon the downgrade.

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 Sept. 30, 2009, NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts.

9. Financial Instruments

The estimated fair values of NSP-Minnesota’s recorded financial instruments are as follows:

	Sept. 30, 2009				Dec. 31, 2008
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Nuclear decommissioning fund	$	1,234,006	$	1,234,006	$	1,075,294	$	1,075,294
Other investments	710		710		725		725
Long-term debt, including current portion	2,713,528		3,094,651		2,962,749		3,100,223

The fair value of cash and cash equivalents, notes and accounts receivable and notes and accounts payable are not materially different from their carrying amounts. The fair value of NSP-Minnesota’s nuclear decommissioning fund is based on published trading data and pricing models, generally using the most observable inputs available for each class of security. The fair values of NSP-Minnesota’s other investments are estimated based on quoted market prices for those or similar investments. The fair value of NSP-Minnesota’s long-term debt is estimated based on the quoted market prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality.

The fair value estimates presented are based on information available to management as of Sept. 30, 2009 and Dec. 31, 2008. These fair value estimates have not been comprehensively revalued for purposes of these consolidated financial statements since that date, and current estimates of fair values may differ significantly.

Letters of Credit — NSP-Minnesota uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Sept. 30, 2009 and Dec. 31, 2008, there were $6.9 million and $6.9 million of letters of credit outstanding, respectively. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

10. Fair Value Measurements

Effective Jan. 1, 2008, NSP-Minnesota adopted new guidance for recurring fair value measurements contained in ASC 820 Fair Value Measurements and Disclosures which provides a single definition of fair value and requires enhanced disclosures about assets and liabilities measured at fair value. A hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value was established by this guidance. The three levels in the 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.

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.

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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 these hierarchy levels, NSP-Minnesota’s assets and liabilities that are measured at fair value on a recurring basis:

	Sept. 30, 2009
							Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting			Net Balance
Assets
Nuclear decommissioning fund
Cash equivalents	$	—	$	16,386	$	—	$	—		$	16,386
Debt securities	—		569,303		98,233		—			667,536
Equity securities	550,084		—		—		—			550,084
Commodity derivatives	—		21,415		60,693		(12,846		)	69,262
Total	$	550,084	$	607,104	$	158,926	$	(12,846	)	$	1,303,268

Liabilities
Commodity derivatives	$	—	$	19,601	$	18,061	$	(14,893	)	$	22,769
Interest rate derivatives	—		10,865		—		—			10,865
Total	$	—	$	30,466	$	18,061	$	(14,893	)	$	33,634

	Dec. 31, 2008
							Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting			Net Balance
Assets
Nuclear decommissioning fund
Cash equivalents	$	—	$	8,449	$	—	$	—		$	8,449
Debt securities	—		491,486		109,423		—			600,909
Equity securities	465,936		—		—		—			465,936
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 tables present the changes in Level 3 recurring fair value measurements for the three and nine months ended Sept. 30, 2009 and 2008:

	Three Months Ended Sept. 30,
	2009					2008
	Commodity			Nuclear		Commodity			Nuclear
	Derivatives,			Decommissioning		Derivatives,			Decommissioning
(Thousands of Dollars)	Net			Fund		Net			Fund
Balance July 1	$	46,637		$	86,337	$	21,641		$	109,416
Purchases, issuances, and settlements, net	(265		)	5,790		(948		)	9,110
Transfers into (out of) Level 3	720			—		(1,466		)	—
Gains recognized in earnings	2,228			—		746			—
(Losses) gains recognized as regulatory assets and liabilities	(6,688		)	6,106		5,758			(4,572		)
Balance Sept. 30	$	42,632		$	98,233	$	25,731		$	113,954

	Nine Months Ended Sept. 30,
	2009						2008
	Commodity			Nuclear			Commodity			Nuclear
	Derivatives,			Decommissioning			Derivatives,			Decommissioning
(Thousands of Dollars)	Net			Fund			Net			Fund
Balance Jan. 1	$	23,247		$	109,423		$	15,345		$	108,656
Purchases, issuances, and settlements, net	(316		)	(22,335		)	(6,416		)	12,760
Transfers into (out of) Level 3	701			—			(1,414		)	—
Losses recognized in earnings	(2,603		)	—			(5,510		)	—
Gains (losses) recognized as regulatory assets and liabilities	21,603			11,145			23,726			(7,462		)
Balance Sept. 30	$	42,632		$	98,233		$	25,731		$	113,954

Gains and losses on Level 3 commodity derivatives recognized in earnings for the three and nine months ended Sept. 30, 2009 include $3.4 million and $4.9 million of net unrealized gains relating to commodity derivatives held at Sept. 30, 2009. Gains and losses on Level 3 commodity derivatives recognized in earnings for the three and nine months ended Sept. 30, 2008, include $0.6 million and $3.6 million, respectively, of net unrealized gains relating to commodity derivatives held at Sept. 30, 2008. Realized and unrealized gains and losses on commodity trading activities are included in electric revenues. Realized and unrealized gains and losses on non-trading derivative instruments are recorded in other comprehensive income or deferred as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on the commission approved regulatory recovery mechanisms. Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a component of a nuclear decommissioning regulatory asset.

11. Other Income (Expense), Net

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

	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
(Thousands of Dollars)	2009			2008			2009			2008
Interest income	$	1,270		$	2,185		$	3,574		$	10,090
Other nonoperating income (expenses)	23			—			(17		)	1,285
Insurance policy expenses	(2,319		)	(1,336		)	(4,725		)	(1,840		)
Other income (expense), net	$	(1,026	)	$	849		$	(1,168	)	$	9,535

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12. Segment Information

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

	Regulated		Regulated			All		Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas			Other		Eliminations			Total
Three Months Ended Sept. 30, 2009
Revenues from:
External customers	$	916,338	$	48,271		$	4,750	$	—		$	969,359
Internal customers	90		354			—		(444		)	—
Total revenues	$	916,428	$	48,625		$	4,750	$	(444	)	$	969,359
Segment net income (loss)	$	98,538	$	(6,837	)	$	848	$	—		$	92,549

Three Months Ended Sept. 30, 2008
Revenues from:
External customers	$	1,012,555	$	86,422		$	4,119	$	—		$	1,103,096
Internal customers	147		593			—		(740		)	—
Total revenues	$	1,012,702	$	87,015		$	4,119	$	(740	)	$	1,103,096
Segment net income (loss)	$	111,767	$	(5,985	)	$	4,558	$	—		$	110,340

	Regulated		Regulated		All		Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other		Eliminations			Total
Nine Months Ended Sept. 30, 2009
Revenues from:
External customers	$	2,573,004	$	452,054	$	14,088	$	—		$	3,039,146
Internal customers	282		1,469		—		(1,751		)	—
Total revenues	$	2,573,286	$	453,523	$	14,088	$	(1,751	)	$	3,039,146
Segment net income	$	202,257	$	11,054	$	5,335	$	—		$	218,646

Nine Months Ended Sept. 30, 2008
Revenues from:
External customers	$	2,737,121	$	641,869	$	13,695	$	—		$	3,392,685
Internal customers	437		4,347		—		(4,784		)	—
Total revenues	$	2,737,558	$	646,216	$	13,695	$	(4,784	)	$	3,392,685
Segment net income	$	193,157	$	16,655	$	12,849	$	—		$	222,661

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13. Comprehensive Income

The components of total comprehensive income are shown below:

	Three Months Ended						Nine Months Ended
	Sept. 30,						Sept. 30,
(Thousands of Dollars)	2009			2008			2009			2008
Net income	$	92,549		$	110,340		$	218,646		$	222,661
Other comprehensive income (loss):
Unrealized gain (loss) - marketable securities	89			(122		)	333			(223		)
Changes in unrecognized amounts of pension and retiree medical benefits	33			31			97			96
After-tax net unrealized losses related to derivatives accounted for as hedges	(6,533		)	(1,408		)	(5,972		)	(2,753		)
After-tax net realized losses (gains) on derivative transactions reclassified into earnings	471			(32		)	1,654			(156		)
Other comprehensive loss	(5,940		)	(1,531		)	(3,888		)	(3,036		)
Comprehensive income	$	86,609		$	108,809		$	214,758		$	219,625

14. 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 Sept. 30,
	2009			2008			2009			2008
							Postretirement Health
(Thousands of Dollars)	Pension Benefits						Care Benefits
Xcel Energy Inc.
Service cost	$	16,365		$	15,851		$	1,166		$	1,338
Interest cost	42,448			42,630			12,603			12,720
Expected return on plan assets	(64,135		)	(68,584		)	(5,694		)	(7,963		)
Amortization of transition obligation	—			—			3,611			3,644
Amortization of prior service cost (credit)	6,155			5,166			(681		)	(544		)
Amortization of net loss	3,114			3,185			4,832			2,875
Net periodic benefit cost (credit)	3,947			(1,752		)	15,837			12,070
(Cost) credits not recognized and additional cost recognized due to the effects of regulation	(723		)	2,258			972			972
Net benefit cost recognized for financial reporting	$	3,224		$	506		$	16,809		$	13,042

NSP-Minnesota
Net periodic benefit cost (credit)	$	723		$	(1,918	)	$	3,355		$	3,439
(Cost) credits not recognized and additional cost recognized due to the effects of regulation	(723		)	2,258			—			—
Net benefit cost recognized for financial reporting	$	—		$	340		$	3,355		$	3,439

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	Nine Months Ended Sept. 30,
	2009			2008			2009			2008
							Postretirement Health
(Thousands of Dollars)	Pension Benefits						Care Benefits
Xcel Energy Inc.
Service cost	$	49,095		$	47,553		$	3,499		$	4,013
Interest cost	127,343			127,890			37,809			38,160
Expected return on plan assets	(192,404		)	(205,753		)	(17,082		)	(23,888		)
Amortization of transition obligation	—			—			10,833			10,932
Amortization of prior service cost (credit)	18,464			15,498			(2,044		)	(1,632		)
Amortization of net loss	9,342			9,555			14,497			8,624
Net periodic benefit cost (credit)	11,840			(5,257		)	47,512			36,209
(Cost) credits not recognized and additional cost recognized due to the effects of regulation	(2,169		)	6,775			2,918			2,918
Net benefit cost recognized for financial reporting	$	9,671		$	1,518		$	50,430		$	39,127

NSP-Minnesota
Net periodic benefit cost (credit)	$	2,169		$	(5,752	)	$	10,064		$	10,418
(Cost) credits not recognized and additional cost recognized due to the effects of regulation	(2,169		)	6,775			—			—
Net benefit cost recognized for financial reporting	$	—		$	1,023		$	10,064		$	10,418

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

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

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; environmental laws and regulations; 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 Item 1A and Exhibit 99.01 to this report on Form 10-Q for the quarter ended Sept. 30, 2009.

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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. 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 Sept. 30, 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 $218.6 million for the first nine months of 2009, compared with approximately $222.7 million for the first nine months of 2008.

Electric Revenues and Margins

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.

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

	Nine Months Ended Sept. 30,
(Millions of Dollars)	2009			2008
Electric revenues	$	2,573		$	2,737
Electric fuel and purchased power	(1,066		)	(1,293		)
Electric margin	$	1,507		$	1,444

The following summarizes the components of the changes in electric revenues and electric margin for the nine months ended Sept. 30:

Electric Revenues

(Millions of Dollars)	2009 vs. 2008
Fuel and purchased power cost recovery	$	(185	)
Trading	(42		)
Minnesota rate case provision for refund (largely offset in depreciation expense)	(30		)
Retail sales decline (excluding weather impact)	(17		)
Firm wholesale	(12		)
Estimated impact of weather	(9		)
Minnesota retail rate increase	97
2008 refund of nuclear refueling outage revenues due to change in recovery method	15
MERP rider	13
Non-fuel riders	8
Other, net	(2		)
Total decrease in electric revenues	$	(164	)

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Electric Margin

(Millions of Dollars)	2009 vs. 2008
Minnesota retail rate increase	$	97
Interchange agreement billing with NSP-Wisconsin	18
2008 refund of nuclear refueling outage revenues due to change in recovery method	15
MERP rider	13
Non-fuel riders	8
Minnesota rate case provision for refund (largely offset in depreciation expense)	(30		)
Retail sales decline (excluding weather impact)	(17		)
Estimated impact of weather	(9		)
Transmission revenue, net of expense	(8		)
Higher purchased capacity costs	(6		)
Firm wholesale	(4		)
Trading	(4		)
Other, net	(10		)
Total increase in electric margin	$	63

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.

Natural Gas — The following tables detail natural gas revenues and margin:

	Nine Months Ended Sept. 30,
(Millions of Dollars)	2009			2008
Natural gas revenues	$	452		$	642
Cost of natural gas sold and transported	(329		)	(506		)
Natural gas margin	$	123		$	136

The following summarizes the components of the changes in natural gas revenues and margin for the nine months ended Sept. 30:

Natural Gas Revenues

(Millions of Dollars)	2009 vs. 2008
Purchased natural gas adjustment clause recovery	$	(183	)
Conservation program revenues (generally offset by expenses)	(6		)
Estimated impact of weather	(3		)
Other, net	2
Total decrease in natural gas revenues	$	(190	)

Natural Gas Margin

(Millions of Dollars)	2009 vs. 2008
Conservation program revenues (generally offset by expenses)	$	(6	)
Estimated impact of weather	(3		)
Other, net	(4		)
Total decrease in natural gas margin	$	(13	)

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Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expenses — Other operating and maintenance expenses for the first nine months of 2009 increased $64.5 million, or 9.8 percent, compared with 2008. The following summarizes the components of the changes for the nine months ended Sept. 30:

(Millions of Dollars)	2009 vs. 2008
Nuclear outage costs, net of deferral	$	26
Higher nuclear plant operation costs	20
Higher employee benefit costs	13
Higher insurance costs	5
Higher contract labor costs	4
Interchange agreement billing with NSP-Wisconsin	4
Lower consulting costs	(8		)
Other, net	1
Total increase in other operating and maintenance expenses	$	65

· The increase in nuclear outage costs is due to the timing of outages in conjunction with the MPUC’s approval of the change in the nuclear refueling outage recovery method from the direct expense method to the deferral and amortization method in the third quarter of 2008.

· The increase in nuclear plant operation costs is driven primarily by an increase in security costs and regulatory fees, resulting from new Nuclear Regulatory Commission requirements.

· Higher employee benefits costs are primarily attributable to higher employee medical plan costs as well as increased pension costs, in part, related to market losses on retirement benefit plan assets.

· Lower consulting costs are primarily the result of cost management initiatives implemented in early 2009.

Conservation Program Expenses — Conservation program expenses decreased $8.5 million, or 16.9 percent, for the first nine months of 2009, compared with the first nine months of 2008. The decrease was primarily due to an adjustment in the 2009 rider for over-recovery in 2008, which resulted from the timing of the rider rate approval.

Depreciation and Amortization — Depreciation and amortization expense decreased by approximately $20.1 million, or 6.4 percent, for the first nine months of 2009, compared with the first nine months of 2008. In September 2009, as a result of the MPUC decision, in the Minnesota electric rate case, NSP-Minnesota began recognizing a 10-year life extension of the Prairie Island nuclear plant for purposes of determining depreciation, effective Jan. 1, 2009. In addition, in June 2009, the MPUC extended the recovery period of decommissioning expense by 10 years for the Prairie Island and the Monticello nuclear plants. These decreases were partially offset by normal system expansion.

Other Income (Expense), Net — Other income (expense), net, decreased by approximately $10.7 million for the first nine months of 2009, compared with the first nine months of 2008. The decrease was primarily due to lower interest income in 2009 and changes in non-qualified benefit plan liabilities related to market activity.

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 $2.0 million, or 6.3 percent, for the first nine 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.

Income Taxes — Income tax expense increased by $4.9 million for the first nine months of 2009, compared with the first nine months of 2008. The effective tax rate was 38.7 percent for the first nine months of 2009, compared with 37.4 percent for the same period in 2008. The increase in income tax expense and the higher effective tax rate for the first nine months of 2009 were primarily due to additional state unitary tax expense in 2009, partially offset by wind energy production tax credits. Excluding the additional state tax expense, the effective tax rate for the first nine months of 2009 would have been 37.6 percent.

Factors Affecting Results of Continuing Operations

Public Utility Regulation

Minnesota Resource Plan — In 2007, NSP-Minnesota filed its resource plan, which covers 2008-2022. The plan would reduce CO2 emissions by 22 percent from 2005 by 2020, a 6 million ton reduction.

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In July 2009 the MPUC approved NSP-Minnesota’s 2007 resource plan, including the following components:

· Energy efficiency savings of 1.15 percent in 2010, 1.2 percent in 2011, and 1.3 percent in 2012;

· Install sufficient renewables to meet the Minnesota RES;

· Obtain required approvals to extend the life of the Prairie Island nuclear plant and to increase the output at both Prairie Island and Monticello;

· Continue ongoing capacity expansion at Sherco Unit 3;

· Continue to investigate repowering Black Dog Units 3 and 4, and provide the MPUC with specific plans and timelines for the repowering;

· Obtain approval for the 375 MW intermediate and 350 MW diversity exchange with Manitoba Hydro beginning in 2015; and

· Continue to ensure sufficient transmission available to deliver generation to load.

Additionally, the MPUC required NSP-Minnesota to consider higher levels of DSM and energy efficiency and provide recommendations in NSP-Minnesota’s next resource plan, which is to be filed no later than Aug. 1, 2010.

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. On May 28, 2009, the MPUC affirmed its September 2008 order and denied Excelsior Energy’s motion, which closes the docket. A written order was issued July 7, 2009. On Aug. 6, 2009, Excelsior appealed the MPUC decision to the Minnesota Court of Appeals. Briefings are expected to be completed in November 2009, with oral arguments scheduled subsequently.

Prairie Island Certificate of Need (CON) — On May 16, 2008, NSP-Minnesota filed for a CON for life extension and a separate request for approval of an enhanced power uprate at both Prairie Island Units 1 and 2. The City of Red Wing, Minn. and the Prairie Island Indian Community (PIIC) filed testimony raising concerns about the cost to the community and certain health and safety concerns. The OES filed testimony supporting the uprates. Evidentiary hearings were held in June 2009. The ALJ recommended granting the requested CONs in his report issued Oct. 21, 2009. Pursuant to a 2003 law, if the MPUC grants a CON request for additional dry cask storage, it is stayed for one legislative session. NSP-Minnesota also filed for a license extension with the NRC on April 15, 2008. The PIIC intervened in the proceeding and raised seven points of contention. As of July 15, 2009, NSP-Minnesota and the PIIC have resolved six of these contentions. The final environmental impact statement was published in the state proceeding July 31, 2009.At this time, it is uncertain when ultimate approval of the license extension will occur.

Wind Generation — 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. In June 2009, the MPUC issued an order approving investments in the Nobles and Merricourt Wind Projects. In August 2009, the NDPSC granted advanced determinations of prudence to the Nobles and Merricourt Wind Projects and a certificate of public convenience and necessity (CPCN) to the Merricourt project. In October 2009, the NDPSC voted to obtain additional information to determine whether or not to reopen the Merricourt Wind Project CPCN as a result of the impact on other North Dakota utilities and their retail customers of the MISO cost allocation applicable to transmission investments associated with the Merricourt project. On Oct. 23, 2009, the FERC approved a modified MISO cost allocation method that is expected to reduce the impact on other North Dakota utilities and their customers.

NSP-Minnesota Transmission CONs — In August 2007, NSP-Minnesota and Great River Energy (on behalf of eight other regional transmission providers) filed a CON 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. 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.

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In April 2009, the MPUC granted a CON 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. In September 2009, two intervenors appealed the MPUC’s CON decisions in the Minnesota Court of Appeals.

As part of CapX 2020, NSP-Minnesota and Great River Energy have filed two route permit applications with the MPUC. In December 2008, the route permit application for the Brookings to Hampton Corner Project was filed. In April 2009, the route permit application for the Monticello to St. Cloud portion of the Fargo Twin Cities project was filed. In October 2009, the route permit application for the St. Cloud to Fargo project was filed with the MPUC. Route permit applications for the remaining parts of the three projects are expected to be filed in Minnesota later this year. Permit filings are expected to 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 CON 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 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.

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, including enforcement of North American Electric Reliability Corporation (NERC) mandatory electric reliability standards. 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. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

Electric Reliability Standards Compliance

Compliance Audits

NSP-Minnesota and NSP-Wisconsin share all NSP System generation and transmission costs by means of a FERC-approved tariff commonly referred to as the Interchange Agreement. The NSP System was subject to an electric reliability standards compliance audit in the first quarter of 2008. The Midwest Reliability Organization (MRO) found the NSP System in compliance with all NERC standards audited. In 2008, the NSP System filed self-reports with the MRO relating to failure to complete certain generation station battery tests, relay maintenance intervals and certain critical infrastructure protection standards. In August and September of 2009, the NSP System reached agreement with the MRO that would resolve all open audit findings and self reports by payment of a non-material penalty. Xcel Energy is in the process of developing a definitive settlement agreement. The settlement agreement will be subject to NERC and FERC approval.

MRO/NERC Compliance Investigation

On Sept. 18, 2007, portions of the NSP System and transmission systems west and north of the NSP System briefly islanded from the rest of the Eastern Interconnection, as a result of a series of transmission line outages. The initial transmission line outage appears to have occurred on the NSP System. In March 2008, NSP-Minnesota received notice that the MRO was commencing a compliance investigation of the Sept 18, 2007 event. Because the event affected more than one region, the NERC took over the investigation. The final outcome of the NERC compliance investigation is unknown at this time. Given the ongoing investigation, NSP-Minnesota Energy is unable to determine if the outcome of this matter will result in any finding of standards violations, and if so, whether any associated penalties will have a material adverse impact on operations, cash flows or financial condition.

MISO Generation Interconnection Cost Allocation Tariff — On July 9, 2009, MISO and its transmission owners (including NSP-Minnesota and NSP-Wisconsin) filed to change the cost allocation procedures in the MISO tariff associated with interconnection of new generation. The current rule requires the interconnecting generator to fund 50 percent of the network upgrades associated with the interconnection, with 50 percent funded by the affected transmission owner(s). The proposed change would require the interconnecting generator to fund 90 or 100 percent of the costs (based on the size of the facility) on an interim basis until MISO and its stakeholders can develop a replacement tariff in 2010. Approximately 40 parties, including Xcel Energy, filed interventions or protests with extensive objections filed by several wind generation developers. Xcel Energy urged the FERC to require MISO and its stakeholders to develop and file a replacement tariff by April 1, 2010, so the tariff could be in effect by July 1, 2010. Xcel Energy

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indicated uncertainly regarding cost allocation and cost recovery could affect pending transmission projects. On Oct. 23, 2009, FERC approved the modified tariff effective July 9, 2009, conditioned on MISO filing a revised tariff by July 2010. FERC also ruled the interim tariff will be applicable to all generation interconnection agreements executed or filed with FERC during the period July 9, 2009 to July 2010.

FERC Audit of Wholesale FCA — On Oct. 14, 2009, the FERC notified NSP-Minnesota and NSP-Wisconsin that the FERC audit division began an audit of compliance with the FERC’s accounting and reporting regulations related to the calculation of the NSP-Minnesota and NSP-Wisconsin wholesale FCA for the period commencing Jan. 1, 2008. The audit is a periodic financial audit and does not imply any non-compliance has occurred.

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. In addition, the 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 our 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

Except to the extent updated or described below, 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.

We are subject to credit risks.

Credit risk includes the risk that our retail customers will not pay their bills, which may lead to a reduction in liquidity and an eventual increase in bad debt expense. Retail credit risk is comprised of numerous factors including the overall economy and the price of products and services provided.

Credit risk also includes the risk that various counterparties that owe us money or product will breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses.

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One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges. The credit risk is then socialized through the exchange central clearinghouse function. While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which creates an additional need for liquidity to post margin as exchange positions change value daily. Additional margin requirements could impact our liquidity.

NSP-Minnesota may at times have direct credit exposure in its short-term wholesale and commodity trading activity to various financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. NSP-Minnesota may also have some indirect credit exposure due to participation in organized markets such as the PJM Interconnection and MISO in which any credit losses are socialized to all market participants.

NSP-Minnesota does have additional indirect credit exposures to various financial institutions in the form of letters of credit provided as security by power suppliers under various long-term physical purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below the designated investment grade rating stipulated in the underlying long term purchased power contracts, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party would be in technical default under the contract, which would enable NSP-Minnesota to exercise its contractual rights.

We may be subject to litigation, legislative and regulatory responses to climate change, with which compliance could be difficult and costly.

Legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk. Increased public awareness and concern may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. Numerous states have announced or adopted programs to stabilize and reduce GHG and federal legislation has been introduced in both houses of Congress. Likewise, the EPA has drafted regulations pursuant to which GHGs from certain stationary sources would be regulated under the Clean Air Act by March 2010. NSP-Minnesota’s electric generating facilities are likely to be subject to regulation under climate change laws introduced at either the state or federal level within the next few years. Xcel Energy, the parent company of NSP-Minnesota, is also currently a party to climate change lawsuits and may be subject to additional climate change lawsuits, including lawsuits similar to those described in the Note 6, Commitments and Contingent Liabilities, in our Notes to our Consolidated Financial Statements. While Xcel Energy believes such lawsuits are without merit, an adverse outcome in any of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Many of the federal and state climate change legislative proposals, such as ACES, use a “cap and trade” policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap. Under the proposals, the cap becomes more stringent with the passage of time. The proposals establish mechanisms for GHG sources, such as power plants, to obtain “allowances” or permits to emit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emissions allowances for their own operations. Proponents of the cap and trade policy believe it will result in the most cost effective, flexible emission reductions. The impact of legislation and regulations, including a “cap and trade” structure, on NSP-Minnesota and its customers will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. Another important factor is NSP-Minnesota’s ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed. We may not recover all costs related to complying with regulatory requirements imposed on NSP-Minnesota. If our regulators do not allow us to recover all or a part of the cost of capital investment or the operating and maintenance costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.

For further discussion see Note 6 to the consolidated financial statements.

3.01*		Articles of Incorporation and Amendments of Northern Power Corp. (renamed NSP-Minnesota on Aug. 21, 2000)(Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
3.02*		By-Laws (Exhibit 3.02 to Form 8-K (file no. 001-31387) dated June 3, 2008).
10.01*		Credit Agreement dated Dec. 14, 2006 between NSP-Minnesota and various lenders (Exhibit 10.02 to Form 10-Q of Xcel Energy dated Oct. 30, 2009 (file no. 001-03034)).
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.

	/s/ TERESA S. MADDEN
	Teresa S. Madden
	Vice President and Controller

	/s/ DAVID M. SPARBY
	David M. Sparby
	Vice President and Chief Financial Officer

	/s/ JUDY M. POFERL
	Judy M. Poferl
	President and Chief Executive Officer

	/s/ DAVID M. SPARBY
	David M. Sparby
	Vice President and Chief Financial Officer

PART I - FINANCIAL INFORMATION

Item l.	Financial Statements (Unaudited)	3
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 4.	Controls and Procedures	31

PART II - OTHER INFORMATION

Item 1.	Legal Proceedings	31
Item 1A.	Risk Factors	31
Item 6.	Exhibits	33

SIGNATURES		34

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