Northern States Power 10-Q 2009 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2009
or
o	TRANSITION REPORTS PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-31387

Northern States Power Company

(Exact name of registrant as specified in its charter)

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

(612) 330-5500

 (Registrant’s telephone number, including area code)

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

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

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

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

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

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

Class	Outstanding at Aug. 3, 2009
Common Stock, $0.01 par value	1,000,000 shares

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

TABLE OF CONTENTS

PART I - FINANCIAL INFORMATION
Item l.	Financial Statements (Unaudited)	3
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 4.	Controls and Procedures	30
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	30
Item 1A.	Risk Factors	30
Item 6.	Exhibits	31
SIGNATURES		32
Certifications Pursuant to Section 302
Certifications Pursuant to Section 906
Statement Pursuant to Private Litigation

This Form 10-Q is filed by Northern States Power Company, a Minnesota corporation (NSP-Minnesota). NSP-Minnesota is a wholly owned subsidiary of Xcel Energy Inc. (Xcel Energy). Additional information on Xcel Energy is available on various filings with the Securities and Exchange Commission (SEC).

2

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 June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Operating revenues
Electric	$	787,584		$	854,331		$	1,656,666		$	1,724,566
Natural gas	74,516			162,842			403,783			555,447
Other	4,304			4,692			9,338			9,576
Total operating revenues	866,404			1,021,865			2,069,787			2,289,589
Operating expenses
Electric fuel and purchased power	314,163			408,334			696,309			822,722
Cost of natural gas sold and transported	43,530			127,014			304,727			446,167
Cost of sales — other	2,547			2,369			5,015			4,736
Other operating and maintenance expenses	245,634			221,034			488,730			460,444
Conservation program expenses	12,742			14,776			27,403			34,122
Depreciation and amortization	97,108			103,925			201,117			206,581
Taxes (other than income taxes)	35,390			32,410			72,212			71,949
Total operating expenses	751,114			909,862			1,795,513			2,046,721
Operating income	115,290			112,003			274,274			242,868
Interest and other (expenses) income, net	(124		)	4,375			(142		)	8,686
Allowance for funds used during construction — equity	7,665			6,811			14,371			13,181
Interest charges and financing costs
Interest charges — includes other financing costs of $1,480, $1,486, $2,947 and $2,839, respectively	49,827			50,005			99,912			97,660
Allowance for funds used during construction — debt	(4,610		)	(4,400		)	(8,952		)	(8,748		)
Total interest charges and financing costs	45,217			45,605			90,960			88,912
Income before income taxes	77,614			77,584			197,543			175,823
Income taxes	27,716			29,231			71,446			63,502
Net income	$	49,898		$	48,353		$	126,097		$	112,321

See Notes to Consolidated Financial Statements

3

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands of dollars)

	Six Months Ended June 30,
	2009			2008
Operating activities
Net income	$	126,097		$	112,321
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	203,849			210,862
Nuclear fuel amortization	37,713			31,045
Deferred income taxes	57,515			62,747
Amortization of investment tax credits	(1,752		)	(1,876		)
Allowance for equity funds used during construction	(14,371		)	(13,181		)
Net realized and unrealized hedging and derivative transactions	5,662			(1,783		)
Changes in operating assets and liabilities:
Accounts receivable	103,400			57,252
Accounts receivable from affiliates	(15,293		)	(4,941		)
Accrued unbilled revenues	75,265			50,984
Inventories	126,879			19,697
Recoverable purchased natural gas and electric energy costs	(13,764		)	(8,646		)
Other current assets	(3,327		)	5,741
Accounts payable	(103,856		)	(763		)
Net regulatory assets and liabilities	8,721			12,753
Other current liabilities	699			(30,934		)
Change in other noncurrent assets	(23		)	7,711
Change in other noncurrent liabilities	(32,685		)	(8,915		)
Net cash provided by operating activities	560,729			500,074
Investing activities
Utility capital/construction expenditures	(495,972		)	(555,615		)
Allowance for equity funds used during construction	14,371			13,181
Purchase of investments in external decommissioning fund	(1,014,130		)	(441,802		)
Proceeds from sale of investments in external decommissioning fund	1,012,705			420,106
Investments in utility money pool arrangement	(55,500		)	(640,000		)
Repayments from utility money pool arrangement	55,500			589,000
Advances to affiliate	(33,200		)	(243,300		)
Advances from affiliate	33,200			265,000
Other investments	(1,037		)	2,545
Net cash used in investing activities	(484,063		)	(590,885		)
Financing activities
Repayment of short-term borrowings, net	(65,000		)	(341,500		)
Borrowings under utility money pool arrangement	160,500			194,100
Repayments under utility money pool arrangement	(186,000		)	(289,200		)
Proceeds from issuance of long-term debt	—			493,751
Repayment of long-term debt, including reacquisition premiums	(34		)	(5		)
Capital contributions from parent	132,728			166,762
Dividends paid to parent	(115,671		)	(112,761		)
Net cash (used in) provided by financing activities	(73,477		)	111,147
Net increase in cash and cash equivalents	3,189			20,336
Cash and cash equivalents at beginning of period	12,343			24,626
Cash and cash equivalents at end of period	$	15,532		$	44,962
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(86,501	)	$	(81,492	)
Cash paid for income taxes (net of refunds received)	(14,430		)	(6,663		)
Supplemental disclosure of non-cash flow investing transactions:
Property, plant and equipment additions in accounts payable	$	11,451		$	8,997

See Notes to Consolidated Financial Statements

4

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in thousands of dollars)

	June 30, 2009		Dec. 31, 2008
Assets
Current assets
Cash and cash equivalents	$	15,532	$	12,343
Accounts receivable, net	319,257		413,156
Accounts receivable from affiliates	27,711		12,418
Accrued unbilled revenues	173,186		248,451
Inventories	219,024		345,903
Recoverable purchased natural gas and electric energy costs	33,149		26,605
Derivative instruments valuation	84,820		70,252
Prepayments and other	57,375		48,493
Total current assets	930,054		1,177,621
Property, plant and equipment, net	7,083,793		6,804,794
Other assets
Nuclear decommissioning fund and other investments	1,129,163		1,084,827
Regulatory assets	812,251		828,712
Derivative instruments valuation	123,953		129,605
Other	20,387		21,266
Total other assets	2,085,754		2,064,410
Total assets	$	10,099,601	$	10,046,825
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	250,043	$	250,060
Short-term debt	—		65,000
Borrowings under utility money pool arrangement	38,000		63,500
Accounts payable	283,015		389,676
Accounts payable to affiliates	40,848		52,291
Taxes accrued	104,890		121,163
Accrued interest	69,569		68,009
Dividends payable to parent	58,575		58,414
Derivative instruments valuation	32,880		39,816
Other	73,528		50,696
Total current liabilities	951,348		1,158,625
Deferred credits and other liabilities
Deferred income taxes	1,068,482		987,050
Deferred investment tax credits	38,502		40,254
Asset retirement obligations	1,087,204		1,055,689
Regulatory liabilities	485,864		459,880
Derivative instruments valuation	216,386		219,421
Pension and employee benefit obligations	258,911		269,537
Other liabilities	68,730		77,775
Total deferred credits and other liabilities	3,224,079		3,109,606
Commitments and contingent liabilities
Capitalization
Long-term debt	2,713,225		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	1,160,098		1,149,833
Accumulated other comprehensive income	2,257		205
Total common stockholder’s equity	3,210,949		3,065,905
Total liabilities and equity	$	10,099,601	$	10,046,825

See Notes to Consolidated Financial Statements

5

NSP-MINNESOTA AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of NSP-Minnesota and its subsidiaries as of June 30, 2009 and Dec. 31, 2008; the results of its operations for the three and six months ended June 30, 2009 and 2008; and its cash flows for the six months ended June 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 June 30, 2009 up to Aug. 3, 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 (Statement of Financial Accounting Standards (SFAS) No. 141 (revised 2007)) — In December 2007, the Financial Accounting Standards Board (FASB) issued SFAS No. 141(R), which establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest; recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) is to be applied prospectively to business combinations for which the acquisition date is on or after the beginning of an entity’s fiscal year that begins on or after Dec. 15, 2008. NSP-Minnesota implemented SFAS No. 141(R) on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

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

Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (SFAS No. 161) — In March 2008, the FASB issued SFAS No. 161, which is intended to enhance disclosures to help users of the financial statements better understand how derivative instruments and hedging activities affect an entity’s financial position, financial performance and cash flows.  SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, to require disclosures including objectives and strategies for using derivatives, gains and losses on derivative instruments, and credit-risk-related contingent features in derivative contracts.  SFAS No. 161 was effective for financial statements issued for fiscal years and interim periods beginning after Nov. 15, 2008.  NSP-Minnesota implemented SFAS No. 161 on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.  For further discussion and SFAS No. 161 required disclosures, see Note 8 to the consolidated financial statements.

6

Interim Disclosures about Fair Value of Financial Instruments (FASB Staff Position (FSP) FAS 107-1 and Accounting Principles Board (APB) 28-1) — In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, which amends SFAS No. 107, Disclosures About Fair Value of Financial Instruments, and APB Opinion No. 28, Interim Financial Reporting, to require disclosures regarding the fair value of financial instruments in interim financial statements. FSP FAS 107-1 and APB 28-1 was effective for interim periods ending after June 15, 2009. NSP-Minnesota implemented FSP FAS 107-1 and APB 28-1 on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.  For FSP FAS 107-1 and APB 28-1 required disclosures, see Note 9 to the consolidated financial statements.

Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (FSP FAS 157-4) — In April 2009, the FASB issued FSP FAS 157-4, which provides additional guidance for estimating fair value in accordance with SFAS No. 157, Fair Value Measurements, when the volume and level of market activity for an asset or liability have significantly decreased.  FSP FAS 157-4 emphasizes that even if there has been a significant decrease in the volume and level of market activity for the asset or liability, fair value still represents the exit price in an orderly transaction between market participants.  FSP FAS 157-4 was effective for interim and annual periods ending after June 15, 2009.  NSP-Minnesota implemented FSP FAS 157-4 on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Recognition and Presentation of Other-Than-Temporary Impairments (FSP FAS 115-2 and FAS 124-2) — In April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, which changes the method for determining whether an other-than-temporary impairment exists for debt securities, and also requires additional disclosures regarding other-than-temporary impairments.  FSP FAS 115-2 and FAS 124-2 was effective for interim and annual periods ending after June 15, 2009.  NSP-Minnesota implemented FSP FAS 115-2 and FAS 124-2 on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Subsequent Events (SFAS No. 165) — In May 2009, the FASB issued SFAS No. 165, which establishes general standards of accounting and disclosure for events that occur after the balance sheet date but before financial statements are issued.  The accounting guidance contained in SFAS No. 165 is consistent with the auditing literature widely used for accounting and disclosure of subsequent events, however, SFAS No. 165 requires an entity to disclose the date through which subsequent events have been evaluated.  SFAS No. 165 was effective for interim and annual periods ending after June 15, 2009.  NSP-Minnesota implemented SFAS No. 165 on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Recently Issued

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

Amendments to FASB Interpretation No. 46(R) (SFAS No. 167) — In June 2009, the FASB issued SFAS No. 167, which amends the consolidation guidance applicable to variable interest entities. The amendments will significantly affect various elements of consolidation guidance under FASB Interpretation No. 46(R), including guidance for determining whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary.  SFAS No. 167 is effective for fiscal years beginning after Nov. 15, 2009.  NSP-Minnesota is currently evaluating the impact of SFAS No. 167 on its consolidated financial statements.

The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles — a replacement of FASB Statement No. 162 (SFAS No. 168) — In June 2009, the FASB issued SFAS No. 168, which confirms that the FASB Accounting Standards Codification (Codification) will become the single source of authoritative GAAP, other than the guidance put forth by the SEC.  All other accounting literature not included in the Codification will be considered non-authoritative. SFAS No. 168 is effective for interim and annual periods ending after Sept. 15, 2009. NSP-Minnesota expects the implementation of SFAS No. 168 to have no impact on its consolidated financial statements.

7

3.   Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2009			Dec. 31, 2008
Accounts receivable, net
Accounts receivable	$	343,398		$	438,855
Less allowance for bad debts	(24,141		)	(25,699		)
	$	319,257		$	413,156
Inventories
Materials and supplies	$	103,946		$	97,945
Fuel	91,923			141,190
Natural gas	23,155			106,768
	$	219,024		$	345,903
Property, plant and equipment, net
Electric plant	$	9,742,080		$	9,472,073
Natural gas plant	935,370			916,740
Common and other property	457,006			452,308
Construction work in progress	613,018			615,734
Total property, plant and equipment	11,747,474			11,456,855
Less accumulated depreciation	(4,964,403		)	(4,907,681		)
Nuclear fuel	1,694,008			1,611,193
Less accumulated amortization	(1,393,286		)	(1,355,573		)
	$	7,083,793		$	6,804,794

4.   Income Taxes

Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (FIN 48) — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated income tax returns.

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. In the third quarter of 2008, the IRS commenced an examination of tax years 2006 and 2007. As of June 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 June 30, 2009, NSP-Minnesota’s earliest open tax year for which an audit can be initiated by state taxing authorities under applicable statutes of limitations is 2004. There currently are no state income tax audits in progress.

Unrecognized Tax Benefits — The amount of unrecognized tax benefits was $17.8 million and $20.2 million on June 30, 2009 and Dec. 31, 2008, respectively.  The unrecognized tax benefit amounts were increased by a payable associated with net operating loss (NOL) and tax credit carryovers of $1.7 million on June 30, 2009 and reduced by the tax benefits associated with tax credit carryovers of $4.4 million on Dec. 31, 2008.

The unrecognized tax benefit balance included $5.3 million and $7.2 million of tax positions on June 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 $12.5 million and $13.0 million of tax positions on June 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 decrease in the unrecognized tax benefit balance of $3.7 million from April 1, 2009 to June 30, 2009, was due to the resolution of certain federal audit matters, partially offset by the addition of similar uncertain tax positions related to ongoing activity.  NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and when state audits resume. At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.

8

The amount reported within interest charges related to unrecognized tax benefits in the second quarter of 2009 reduced interest expense by $0.1 million.  The amount of interest expense related to unrecognized tax benefits reported within interest charges in the second quarter of 2008 was $0.2 million.  The liability for interest related to unrecognized tax benefits was $1.4 million and $1.3 million on June 30, 2009 and Dec. 31, 2008, respectively.

No amounts were accrued for penalties as of June 30, 2009 and Dec. 31, 2008.

5.   Rate Matters

Except to the extent noted below, the circumstances set forth in Note 13 to the consolidated financial statements included in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2008 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference. The following 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, or 6.05 percent.  The request is based on a 2009 forecast test-year, an electric rate base of $4.1 billion, a requested return on equity (ROE) of 11.0 percent and an equity ratio of 52.5 percent.

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

On April 7, 2009, intervenors submitted direct testimony.  The Office of Energy Security (OES) recommended a revenue increase of $72 million, based on a ROE of 10.88 percent and an equity ratio of 52.5 percent.  The recommended revenue increase included recognition of a 10-year life extension of the Prairie Island nuclear plant, resulting in a decrease of approximately $40 million in depreciation and decommissioning expenses and rejection of NSP-Minnesota’s proposed nuclear rate stability plan.  These adjustments would reduce NSP-Minnesota’s overall revenue deficiency while at the same time reducing expense accruals by $40 million.

On May 5, 2009, NSP-Minnesota filed rebuttal testimony that reduced its rate increase request to $138 million. The reduction of $18 million is primarily associated with cost decreases in certain commodities, management initiatives to defer a wage increase for non-bargaining employees, reductions in employee expenses and lower projected short-term capacity costs since the time of filing. Partially offsetting these reductions are increases in health care and pension costs.  The rebuttal testimony offered an alternative proposal to reflect a three-year life extension for both decommissioning and depreciation expense accruals for the Prairie Island nuclear plant.  The revenue requirement under NSP-Minnesota’s alternative proposal was $121 million.

Also on May 5, 2009, the Office of the Attorney General (OAG) filed testimony that recommended disallowance of certain Board of Directors’ and employees’ expenses, the aggregate of which NSP-Minnesota estimates to be less than $1.5 million.  In addition, the OAG recommended use of different allocators for corporate costs that would reduce the deficiency by $3.4 million.

On May 26, 2009, parties filed surrebuttal testimony.  The OES revised its revenue deficiency to approximately $92 million.  The OES continues to recommend a 10-year extension of NSP-Minnesota’s nuclear decommissioning and depreciation expense at Prairie Island and a 10.88 percent ROE.  NSP-Minnesota’s surrebuttal testimony proposed an additional $1 million reduction to its rebuttal revenue deficiency.

At the time of hearing, the OES revised its request to $90 million compared to NSP-Minnesota’s initial request of $119 million. Other than the appropriate extension period for Prairie Island decommissioning and depreciation, the difference between NSP-Minnesota’s position and the OES is approximately $6 million. The OAG has one unresolved financial issue related to cost allocations whereby it is seeking a disallowance of approximately $3.4 million. Contested case hearings were completed before an administrative law judge (ALJ) in June 2009, and initial and reply briefs were filed in July.  The ALJ is expected to issue a recommended decision in late August 2009, and a final decision from the MPUC is expected in October 2009.

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Electric, Purchased Gas and Resource Adjustment Clauses

Transmission Cost Recovery (TCR) Rider — In November 2006, the MPUC approved a TCR rider pursuant to legislation, which allows annual adjustments to retail electric rates to provide recovery of incremental transmission investments between rate cases.   On Oct. 30, 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.  On June 25, 2009, the MPUC approved the rider request.  The revised TCR rate recovery factors were placed into effect in July 2009.

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

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

State Energy Policy Rider — On March 2, 2009, NSP-Minnesota filed a proposed State Energy Policy 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 (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.  MPUC approval is pending.

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

Conservation Incentive Filing — As a result of 2007 legislation, Minnesota state agencies convened a work group near the end of 2008 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.  Each Minnesota utility was required to file a separate plan for implementing the shared savings approach.  On July 1, 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 from anywhere from 0 to approximately 15 percent of the net present value of benefits, depending on the level of savings achieved.  Comments on NSP-Minnesota’s proposal are due in August 2009.

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

The NDPSC approved NSP-Minnesota’s proposed resolution in April 2009.  NSP-Minnesota began implementing the service quality credits and the rebilling of remaining North Dakota customers in June 2009. NSP-Minnesota rebilled North Dakota customers approximately $1.5 million for the estimated gas usage during the module failure period.  On March 6, 2009, NSP-Minnesota filed a request with the MPUC to rebill the remaining Minnesota customers experiencing a module failure, reiterated the commitments made in previous filings and proposed a $50 service quality credit for each customer experiencing a module failure.  On July 15, 2009, NSP-

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Minnesota filed an application to withdraw its request to rebill affected customers as too much time will have lapsed from the time of meter failures to the expected time (if approved) for rebilling.  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.

Annual Review of Remaining Lives — On Feb. 17, 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 OES recommended provisional approval to ensure that the decisions in this depreciation docket do not have unintended consequences in the pending NSP-Minnesota electric rate case.  The OES recommended a 10-year lengthening of depreciation life.  On July 1, 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 generating plant.  Consistent with the OES recommendation, the MPUC deferred the determination of the appropriate depreciation rates for the Prairie Island generating plant to the pending NSP-Minnesota electric rate case.

Nuclear Decommissioning Expenses — On June 12, 2009, the MPUC issued its order in its review of NSP-Minnesota’s 2009 nuclear plant decommissioning accrual. The order extended the decommissioning life for Prairie Island by ten years rather than the three years proposed by NSP-Minnesota. The effect of this order was to reduce from $32 million to zero the amount of future nuclear decommissioning expenses that must be collected from customers, effective Jan. 1, 2009.

The MPUC order also directed NSP-Minnesota to proceed with a filing to propose a method to return to customers their contributions of $22.9 million made to the external escrow decommissioning fund for the Monticello nuclear plant.

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

South Dakota Electric Rate Case  — On June 30, 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 of 11.25 percent, and an equity ratio of 51.63 percent.  Rates are expected to be in effect on or before Jan. 1, 2010, based on statutory requirements in South Dakota.

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

Both rate riders were allowed a ROE of 9.5 percent according to the terms of their respective settlement agreements.  However, the SDPUC may order that an appropriate ROE value based on the current South Dakota rate case be utilized under the rider mechanism, subject to true-up for the period from July 1, 2008 to the effective date of the order. As indicated previously, the South Dakota general rate case, filed June 30, 2009, uses a 2008 test-year.

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 after the close of the day-ahead energy market 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 regarding the components of the RSG charge.  In the compliance proceeding, the FERC has issued numerous orders, attempting to refine and clarify the RSG charge.  With the issuance of these orders (including orders on rehearing), the FERC has directed certain refunds to market participants, but has subsequently refined or waived various refund requirements.  Most recently, the FERC issued an order in June 2009 relating to MISO’s ongoing RSG-compliance proceeding.  The FERC granted rehearing in part of certain earlier orders directing refunds to correct a rate mismatch in the RSG charge.  Specifically, the June 2009 order waived refunds for the period up until Nov. 5, 2007, and directed MISO to correct the rate mismatch (through refunds) from Nov. 5, 2007 to Nov. 10, 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 and the submission of briefs and evidence by parties, 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

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charges.  Specifically, the FERC determined that the refund-effective date is Nov. 10, 2008, the date of the FERC order determining that the allocation to market participants of the RSG charges was unjust and unreasonable.  The FERC affirmed that a new RSG charge should be implemented from Nov. 10, 2008 on a prospective basis.  MISO’s Feb. 23, 2009 compliance revisions to the RSG charge, as amended, are still pending at the FERC.

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 request(s) 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 (from May 2009 and June 2009, respectively), are both subject to pending requests for rehearing.  The D.C. Circuit proceedings are being held in abeyance pending final action in the FERC proceedings.

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 June 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

American Clean Energy and Security Act (ACES) — On June 26, 2009, the U.S. House of Representatives passed ACES.  Key provisions include a federal cap-and-trade program to reduce GHG emissions by 17 percent by 2020 and 83 percent by 2050 compared to 2005 levels, a national RES, investments in new clean energy technologies and energy efficiency, and mandates for new energy-saving standards.  The U.S. Senate has delayed consideration of ACES until September 2009, during which time the bill could change considerably.  The ultimate impact of the bill on NSP-Minnesota therefore remains uncertain.

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.

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

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

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.

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

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

In September 2006, NSP-Minnesota filed a request with the MPUC for recovery of up to $6.3 million of certain environmental improvement costs recoverable under the Act.  In January 2007, the MPUC approved this request to defer these costs as a regulatory asset with a cap of $6.3 million. In November 2008, NSP-Minnesota filed a request with the MPUC to reflect its requested recovery of these emission reduction compliance costs incurred through 2009 in the NSP-Minnesota electric rate case, filed on Nov. 3, 2008.  In June 2009, NSP-Minnesota received an order from the MPUC closing the docket to correspond with the inclusion of costs in the still pending electric rate case.

The Act required utilities with dry scrubbed units to submit plans for control of mercury for those units by the end of 2007.  On Nov. 6, 2008, the MPUC approved and ordered the implementation of the Sherco Unit 3 and A. S. King mercury emission reduction plans.  The approved plans are to install a sorbent injection system at both A. S. King and Sherco Unit 3. Implementation would occur by Dec. 31, 2009 at Sherco Unit 3 and by Dec. 31, 2010 at A. S. King. On July 16, 2009, NSP-Minnesota filed a petition with the MPUC requesting to establish a mercury cost recovery rider with 2010 adjustment factors that would recover the 2010 revenue requirement of $3.5 million associated with these two projects from customers.

In the fourth quarter of 2009, NSP-Minnesota expects to file plans for mercury control at Sherco Units 1 and 2 with the MPUC and the MPCA.  Assuming these plans are approved, NSP-Minnesota expects to file for recovery of the costs to implement these plans through the mercury cost recovery rider.

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

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

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

Federal Clean Water Act — The federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available (BTA) for minimizing adverse environmental impacts. In July 2004, the EPA published phase II of the rule, which applies to existing cooling water intakes at steam-electric power plants. Several lawsuits were filed against the EPA in the United States Court of Appeals for the Second Circuit (Court of Appeals) challenging the phase II rulemaking. In January 2007, the Court of Appeals issued its decision and remanded the rule to the EPA for reconsideration. In June 2007, the EPA suspended the deadlines and referred any implementation to each state’s best professional judgment until the EPA is able to fully respond to the remand.  In April 2008, the U.S. Supreme Court granted limited review of the Court of Appeals’ opinion to determine whether the EPA has the authority to consider costs and benefits in assessing BTA.  On April 1, 2009, the U.S. Supreme Court issued a decision in Entergy Corp. v. Riverkeeper, Inc., concluding that the EPA can 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. The Court of Appeals has taken the matter under advisement and is expected to issue an opinion in due course.

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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. No explanation was given for the order. The Court of Appeals has taken the matter under advisement.

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In February 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U.S. District Court for the Northern District of California against Xcel Energy, the parent company of NSP-Minnesota, and 23 other utilities, oil, gas and coal companies. The suit was brought on behalf of approximately 400 native Alaskans, the Inupiat Eskimo, who claim that defendants’ emission of CO2 and other 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. The matter has now been fully briefed.  It is uncertain when the court will render a decision.

Employment, Tort and Commercial Litigation

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

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

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

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

Fargo Gas Explosion — In September 2008, an explosion occurred at a duplex in Fargo, N.D. The explosion destroyed one side of the duplex and resulted in injuries to some of the residents. Xcel Energy subsequently provided a report to the U.S. Dept. of Transportation Pipeline and Hazardous Materials Safety Administration stating that natural gas migrated into the house and was ignited by an unknown source.  Investigators identified a natural gas leak the size of a pinhole located 18 inches underground. The property owners and attorneys representing the injured residents put Xcel Energy on notice of potential claims, and the claims of all residents allegedly injured were resolved following mediation in June 2009. Settlement of these claims will not have a material financial impact on NSP-Minnesota.

7.   Short-Term Borrowings and Other Financing Instruments

Commercial Paper — At Dec. 31, 2008, NSP-Minnesota had commercial paper outstanding of $65.0 million with a weighted average interest rate of 2.57 percent.  At June 30, 2009, NSP-Minnesota had no commercial paper outstanding.  At June 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 June 30, 2009 and Dec. 31, 2008, NSP-Minnesota had money pool borrowings of $38.0 million and $63.5 million, respectively.  The weighted average interest rates at June 30, 2009 and Dec. 31, 2008 were 0.90 percent and 3.48 percent, respectively.

8.   Derivative Instruments

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

NSP-Minnesota enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to reduce risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.  See additional information pertaining to the valuation of derivative instruments in Note 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 designated as cash flow hedges for accounting purposes.

At June 30, 2009, accumulated other comprehensive income related to interest rate derivatives included $0.1 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest transactions impact earnings. Net losses in accumulated other comprehensive income related to interest rate derivatives reclassified into earnings during the three and six-month periods ending June 30, 2009 were immaterial.

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.

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At June 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 these 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 six months ended June 30, 2009 and 2008.

At June 30, 2009, NSP-Minnesota had $3.6 million of net losses in accumulated other comprehensive income related to utility commodity and vehicle fuel cash flow hedges of which $2.6 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 six months ended June 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:

	June 30, 2009				Dec. 31, 2008
(Thousands of Dollars)	Derivative Instruments Valuation - Assets		Derivative Instruments Valuation - Liabilities		Derivative Instruments Valuation - Assets		Derivative Instruments Valuation - Liabilities
Long term purchased power agreements	$	139,604	$	223,453	$	151,884	$	230,715
Commodity derivatives	69,169		25,813		47,973		28,522
Total	$	208,773	$	249,266	$	199,857	$	259,237

In 2003, as a result of FASB Statement 133 Implementation Issue No. C20, NSP-Minnesota began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception.  Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

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

	Three Months Ended June 30,
(Thousands of Dollars)	2009		2008
Accumulated other comprehensive income related to cash flow hedges at April 1	$	3,548	$	7,158
After-tax net unrealized gains related to derivatives accounted for as hedges	684		109
After-tax net realized losses (gains) on derivative transactions reclassified into earnings	565		(32		)
Accumulated other comprehensive income related to cash flow hedges at June 30	$	4,797	$	7,235

	Six Months Ended June 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 gains (losses) related to derivatives accounted for as hedges	561		(1,345		)
After-tax net realized losses (gains) on derivative transactions reclassified into earnings	1,183		(124		)
Accumulated other comprehensive income related to cash flow hedges at June 30	$	4,797	$	7,235

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

	June 30, 2009
						Derivative
			Counterparty			Instruments
(Thousands of Dollars)	Fair Value		Netting (a)			Valuation
Current derivative assets
Other derivative instruments:
Trading commodity	$	14,062	$	(9,663	)	$	4,399
Electric commodity	53,966		1,383			55,349
Natural gas commodity	305		7			312
Other	200		—			200
Total current derivative assets	$	68,533	$	(8,273	)	$	60,260
Noncurrent derivative assets
Derivates designated as cash flow hedges:
Vehicle fuel and other commodity	$	57	$	—		$	57
Other derivative instruments:
Trading commodity	14,378		(5,543		)	8,835
Natural gas commodity	15		2			17
	14,393		(5,541		)	8,852
Total noncurrent derivative assets	$	14,450	$	(5,541	)	$	8,909
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	2,810	$	—		$	2,810
Other derivative instruments:
Trading commodity	13,350		(11,549		)	1,801
Electric commodity	11,010		1,383			12,393
Natural gas commodity	1,344		7			1,351
	25,704		(10,159		)	15,545
Total current derivative liabilities	$	28,514	$	(10,159	)	$	18,355
Noncurrent derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	1,052	$	—		$	1,052
Other derivative instruments:
Trading commodity	11,897		(5,546		)	6,351
Natural gas commodity	53		2			55
	11,950		(5,544		)	6,406
Total noncurrent derivative liabilities	$	13,002	$	(5,544	)	$	7,458

(a) FASB Interpretation No. 39 Offsetting of Amounts Relating to Certain Contracts, as amended by FASB Staff Position FIN 39-1 Amendment of FASB Interpretation No. 39, permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between NSP-Minnesota and a counterparty. A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

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The following table details the impact of derivative activity during the three and six months ended June 30, 2009, on other comprehensive income, regulatory assets and liabilities, and income:

	Three Months Ended June 30, 2009
	Fair Value Changes Recognized During the Period in:					Pre-Tax Amounts Reclassified into Income During the Period from:						Pre-Tax Gain (Loss)
	Other		Regulatory			Other			Regulatory			Recognized
	Comprehensive		Assets and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Income		Liabilities			Income			Liabilities			in Income
Derivatives designated as cash flow hedges:
Electric commodity	$	—	$	957		$	—		$	(1,243	)(c)	$	—
Vehicle fuel and other commodity	1,157		—			1,010		(a)	—			—
	$	1,157	$	957		$	1,010		$	(1,243	)	$	—
Other derivative instruments:
Trading commodity	$	—	$	—		$	—		$	—		$	(460	)(b)
Electric commodity	—		45,079			—			(706		)(c)	—
Natural gas commodity	—		(1,076		)	—			—			—
Other	—		—			—			—			200		(c)
	$	—	$	44,003		$	—		$	(706	)	$	(260	)

	Six Months Ended June 30, 2009
	Fair Value Changes Recognized During the Period in:					Pre-Tax Amounts Reclassified into Income During the Period from:						Pre-Tax Gain (Loss)
	Other		Regulatory			Other			Regulatory			Recognized
	Comprehensive		Assets and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Income		Liabilities			Income			Liabilities			in Income
Derivatives designated as cash flow hedges:
Electric commodity	$	—	$	(18,600	)	$	—		$	(4,755	)(c)	$	—
Natural gas commodity	—		(811		)	—			8,916		(d)	(6,951		)(d)
Vehicle fuel and other commodity	949		—			2,107		(a)	—			—
	$	949	$	(19,411	)	$	2,107		$	4,161		$	(6,951	)
Other derivative instruments:
Trading commodity	$	—	$	—		$	—		$	—		$	1,524	(b)
Electric commodity	—		43,341			—			(386		)(c)	—
Natural gas commodity	—		(1,076		)	—			—			—
Other	—		—			—			—			200		(c)
	$	—	$	42,265		$	—		$	(386	)	$	1,724

(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.

At June 30, 2009, commodity derivatives recorded to derivative instruments valuation included derivative contracts with gross notional amounts of approximately 24,892,000-megawatt hours (MwH) of electricity, 8,765,000 MMBtu of natural gas and 2,930,000 gallons of vehicle fuel.  These amounts reflect the gross notional amounts of futures, forwards and financial transmission rights and are not reflective of net positions in the underlying commodities.  Notional amounts for options are also included on a gross basis, but are weighted for the probability of exercise.

Credit Related Contingent Features — Contract provisions of NSP-Minnesota’s derivative instruments may require the posting of collateral or settlement of the contracts for various reasons, including if NSP-Minnesota is unable to maintain its credit rating.  If the

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credit rating of NSP-Minnesota at June 30, 2009 were downgraded below investment grade, contracts underlying $1.0 million of derivative instruments in a liability position would have required NSP-Minnesota to post collateral or settle the contracts, which would have resulted in payments to applicable counterparties of $1.0 million.  At June 30, 2009, there was no collateral posted on these specific contracts.

Certain of NSP-Minnesota’s derivative instruments are also subject to contract provisions that contain adequate assurance clauses.  These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that NSP-Minnesota’s ability to fulfill its contractual obligations is reasonably expected to be impaired.  As of June 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:

	June 30, 2009				Dec. 31, 2008
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Nuclear decommissioning fund	$	1,118,593	$	1,118,593	$	1,075,294	$	1,075,294
Other investments	710		710		725		725
Long-term debt, including current portion	2,963,268		3,175,619		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 June 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 June 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 Fair Value Measurements (SFAS No. 157) for recurring fair value measurements.  SFAS No. 157 provides a single definition of fair value and requires enhanced disclosures about assets and liabilities measured at fair value. SFAS No. 157 establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the SFAS No. 157 hierarchy and examples of each level are as follows:

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

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

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date.  The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value of financial transmission rights.

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

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

	June 30, 2009
(Thousands of Dollars)	Level 1		Level 2		Level 3		Counterparty  Netting			Net Balance
Assets
Nuclear decommissioning fund
Cash equivalents	$	—	$	20,576	$	—	$	—		$	20,576
Debt securities	—		531,071		86,337					617,408
Equity securities	480,609		—		—		—			480,609
Commodity derivatives	—		17,682		65,301		(13,814		)	69,169
Total	$	480,609	$	569,329	$	151,638	$	(13,814	)	$	1,187,762
Liabilities
Commodity derivatives	$	—	$	22,852	$	18,664	$	(15,703	)	$	25,813
Total	$	—	$	22,852	$	18,664	$	(15,703	)	$	25,813

	Dec. 31, 2008
(Thousands of Dollars)	Level 1		Level 2		Level 3		Counterparty  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

The following table presents the changes in Level 3 recurring fair value measurements for the three and six months ended June 30, 2009 and 2008:

	Three months ended June 30,
	2009						2008
(Thousands of Dollars)	Commodity Derivatives, Net			Nuclear Decommissioning Fund			Commodity Derivatives, Net			Nuclear Decommissioning Fund
Balance April 1	$	1,544		$	105,552		$	12,806		$	97,232
Purchases, issuances, and settlements, net	(45		)	(23,314		)	(363		)	13,901
Transfers out of Level 3	(19		)	—			—			—
(Losses) gains recognized in earnings, net	(2,638		)	—			779			—
Gains (losses) recognized as regulatory assets and liabilities	47,795			4,099			8,419			(1,717		)
Balance June 30	$	46,637		$	86,337		$	21,641		$	109,416

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	Six months ended June 30,
	2009						2008
(Thousands of Dollars)	Commodity Derivatives, Net			Nuclear Decommissioning Fund			Commodity Derivatives, Net			Nuclear Decommissioning Fund
Balance Jan 1	$	23,247		$	109,423		$	15,345		$	108,656
Purchases, issuances, and settlements, net	(52		)	(28,126		)	(2,335		)	3,650
Transfers out of Level 3	(19		)	—			—			—
(Losses) gains recognized in earnings, net	(4,831		)	—			1,006			—
Gains (losses) recognized as regulatory assets and liabilities	28,292			5,040			7,625			(2,890		)
Balance June 30	$	46,637		$	86,337		$	21,641		$	109,416

Losses on Level 3 commodity derivatives recognized in earnings for the three and six months ended June 30, 2009, include $0.3 million and 1.6 million of net unrealized gains relating to commodity derivatives held at June 30, 2009.  Gains on Level 3 commodity derivatives recognized in earnings for the three and six months ended June 30, 2008, include $0.7 million and $3.4 million of net unrealized gains relating to commodity derivatives held at June 30, 2008.  Realized and unrealized gains and losses on commodity trading activities are included in electric revenues.  Realized and unrealized gains and losses on short-term wholesale activities reflect the impact of regulatory recovery and are deferred as regulatory assets and liabilities.  Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a component of a nuclear decommissioning regulatory asset.

11.   Interest and Other (Expenses) Income, Net

Interest and other (expenses) income, net, consisted of the following:

	Three months ended June 30,					Six months ended June 30,
(Thousands of Dollars)	2009			2008		2009			2008
Interest income	$	1,128		$	3,195	$	2,304		$	7,905
Other non-operating income	42			364		55			1,283
Insurance policy (expenses) income	(1,223		)	816		(2,406		)	(502		)
Other non-operating expenses	(71		)	—		(95		)	—
Total interest and other (expenses) income, net	$	(124	)	$	4,375	$	(142	)	$	8,686

12.Segment Information

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

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas			All Other		Reconciling Eliminations			Consolidated Total
Three months ended June 30, 2009
Revenues from:
External customers	$	787,584	$	74,516		$	4,304	$	—		$	866,404
Internal customers	62		405			—		(467		)	—
Total revenues	$	787,646	$	74,921		$	4,304	$	(467	)	$	866,404
Segment net income (loss)	$	50,836	$	(3,149	)	$	2,211	$	—		$	49,898
Three months ended June 30, 2008
Revenues from:
External customers	$	854,331	$	162,842		$	4,692	$	—		$	1,021,865
Internal customers	161		1,245			—		(1,406		)	—
Total revenues	$	854,492	$	164,087		$	4,692	$	(1,406	)	$	1,021,865
Segment net income (loss)	$	46,527	$	(526	)	$	2,352	$	—		$	48,353

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(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other		Reconciling Eliminations			Consolidated Total
Six months ended June 30, 2009
Revenues from:
External customers	$	1,656,666	$	403,783	$	9,338	$	—		$	2,069,787
Internal customers	192		1,115		—		(1,307		)	—
Total revenues	$	1,656,858	$	404,898	$	9,338	$	(1,307	)	$	2,069,787
Segment net income	$	103,719	$	17,891	$	4,487	$	—		$	126,097
Six months ended June 30, 2008
Revenues from:
External customers	$	1,724,566	$	555,447	$	9,576	$	—		$	2,289,589
Internal customers	290		3,754		—		(4,044		)	—
Total revenues	$	1,724,856	$	559,201	$	9,576	$	(4,044	)	$	2,289,589
Segment net income	$	81,390	$	22,639	$	8,292	$	—		$	112,321

13.  Comprehensive Income

The components of total comprehensive income are shown below:

	Three months ended June 30,					Six months ended June 30,
(Thousands of Dollars)	2009		2008			2009		2008
Net income	$	49,898	$	48,353		$	126,097	$	112,321
Other comprehensive income:
Unrealized gain (loss) – marketable securities	338		(101		)	243		(101		)
Changes in unrecognized amounts of pension and retiree medical benefits	28		39			65		65
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges	684		109			561		(1,345		)
After-tax net realized losses (gains) on derivative transactions reclassified into earnings	565		(32		)	1,183		(124		)
Other comprehensive income (loss)	1,615		15			2,052		(1,505		)
Comprehensive income	$	51,513	$	48,368		$	128,149	$	110,816

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 June 30,
	2009			2008			2009			2008
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost	$	16,744		$	14,929		$	1,057		$	1,211
Interest cost	43,046			44,677			13,050			12,894
Expected return on plan assets	(64,909		)	(68,697		)	(5,993		)	(8,425		)
Amortization of transition obligation	—			—			3,726			3,644
Amortization of prior service cost (credit)	6,154			5,166			(711		)	(544		)
Amortization of net loss	3,299			3,511			4,779			3,031
Net periodic benefit cost (credit)	4,334			(414		)	15,908			11,811
(Cost) credits not recognized and additional cost recognized due to the effects of regulation	(959		)	1,925			973			973
Net benefit cost recognized for financial reporting	$	3,375		$	1,511		$	16,881		$	12,784
NSP-Minnesota
Net periodic benefit cost (credit)	$	959		$	(1,462	)	$	2,971		$	3,486
(Cost) credits not recognized due to the effects of regulation	(959		)	1,925			—			—
Net benefit cost recognized for financial reporting	$	—		$	463		$	2,971		$	3,486

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	Six months ended June 30,
	2009			2008			2009			2008
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost	$	32,730		$	31,702		$	2,333		$	2,675
Interest cost	84,895			85,260			25,206			25,440
Expected return on plan assets	(128,269		)	(137,169		)	(11,388		)	(15,925		)
Amortization of transition obligation	—			—			7,222			7,288
Amortization of prior service cost (credit)	12,309			10,332			(1,363		)	(1,088		)
Amortization of net loss	6,228			6,370			9,665			5,749
Net periodic benefit cost (credit)	7,893			(3,505		)	31,675			24,139
(Cost) credits not recognized and additional cost recognized due to the effects of regulation	(1,446		)	4,517			1,946			1,946
Net benefit cost recognized for financial reporting	$	6,447		$	1,012		$	33,621		$	26,085
NSP-Minnesota
Net periodic benefit cost (credit)	$	1,446		$	(3,834	)	$	6,710		$	6,979
(Cost) credits not recognized due to the effects of regulation	(1,446		)	4,517			—			—
Net benefit cost recognized for financial reporting	$	—		$	683		$	6,710		$	6,979

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; actions of accounting regulatory bodies; the items described under Factors Affecting Results of Continuing Operations; and the other risk factors listed from time to time by NSP-Minnesota in reports filed with the SEC, including “Risk Factors” in Item 1A of NSP-Minnesota’s Form 10-K for the year ended Dec. 31, 2008 and Exhibit 99.01 to this report on Form 10-Q for the quarter ended June 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 June 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 $126.1 million for the first six months of 2009, compared with approximately $112.3 million for the first six 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:

	Six months ended June 30,
(Millions of Dollars)	2009			2008
Electric revenues	$	1,657		$	1,725
Electric fuel and purchased power	(696		)	(823		)
Electric margin	$	961		$	902

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

Electric Revenues

(Millions of Dollars)	2009 vs. 2008
Fuel and purchased power cost recovery	$	(95	)
Trading	(45		)
Retail sales decline (excluding weather impact)	(14		)
Firm wholesale	(6		)
Minnesota interim retail rate increase, net of provision for refund	57
MERP rider	10
Estimated impact of weather	9
Non-fuel riders	6
Other	10
Total decrease in electric revenues	$	(68	)

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Electric Margin

(Millions of Dollars)	2009 vs. 2008
Minnesota interim retail rate increase, net of provision for refund	$	57
Interchange agreement billing with NSP-Wisconsin	13
MERP rider	10
Estimated impact of weather	9
Non-fuel riders	6
Retail sales decline (excluding weather impact)	(14		)
Transmission expense, net	(7		)
Purchased capacity costs	(6		)
Trading	(5		)
Other	(4		)
Total increase in electric margin	$	59

Natural Gas Revenues and Margins

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

The following table details natural gas revenues and margin:

	Six months ended June 30,
(Millions of Dollars)	2009			2008
Natural gas revenues	$	404		$	555
Cost of natural gas sold and transported	(305		)	(446		)
Natural gas margin	$	99		$	109

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

Natural Gas Revenues

(Millions of Dollars)	2009 vs. 2008
Purchased natural gas adjustment clause recovery	$	(147	)
Conservation program revenues	(5		)
Estimated impact of weather	(3		)
Other	4
Total decrease in natural gas revenues	$	(151	)

Natural Gas Margin

(Millions of Dollars)	2009 vs. 2008
Conservation program revenues	$	(5	)
Estimated impact of weather	(3		)
Other	(2		)
Total decrease in natural gas margin	$	(10	)

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Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expenses — Other operating and maintenance expenses for the first six months of 2009 increased $28.3 million, or 6.1 percent, compared with 2008.  The following summarizes the components of the changes for the six months ended June 30:

(Millions of Dollars)	2009 vs. 2008
Higher nuclear plant operation costs	$	16
Higher employee benefit costs	9
Higher plant generation costs	3
Interchange agreement billings with NSP-Wisconsin	3
Lower consulting costs	(5		)
Other	2
Total increase in other operating and maintenance expenses	$	28

The increase in nuclear plant operation costs is driven primarily by an increase in security costs and regulatory fees, resulting from new NRC requirements.  Employee benefit costs have increased due to higher medical expenses as a result of higher employee utilization.

Depreciation and Amortization — Depreciation and amortization expense decreased by approximately $5.5 million, or 2.6 percent, for the first six months of 2009, compared with the first six months of 2008.  The decrease was primarily due to a reduction in decommissioning expense as the recovery period for the Prairie Island plant was extended in a filing docket approved by the MPUC in June 2009.

Conservation Program Expenses — Conservation program expenses decreased $6.7 million, or 19.7 percent, for the first six months of 2009, compared with the first six months of 2008.  The decrease was primarily due to an adjustment for over-recovery in 2008, which resulted from regulatory delays.

Interest and Other (Expenses) Income, Net — Interest and other (expenses) income, net decreased by approximately $8.8 million, or 101.6 percent, for the first six months of 2009, compared with the first six months of 2008.  The decrease was primarily due to lower interest income in 2009 and proceeds from life insurance policies in 2008.

Allowance for Funds Used During Construction, Equity and Debt (AFDC) — AFDC is a non-cash amount capitalized as a part of construction costs representing the cost of financing the construction.  Generally, these costs are recovered from customers, in future rates, as the related property is depreciated.  AFDC, resulting in part from these projects, increased by approximately $1.4 million, or 6.4 percent, for the first six 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 $7.9 million for the first six months of 2009, compared with the first six months of 2008.  The increase in income tax expense was primarily due to an increase in pretax income. The effective tax rate was 36.2 percent for the first six months of 2009, compared with 36.1 percent for the same period in 2008.

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.

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.

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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.

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.  An ALJ ruling is expected in the third quarter of 2009.  Pursuant to a 2003 law, once the MPUC has acted on a CON request, 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.  Both proceedings are awaiting preparation and filing of environmental impact statements by the respective state and federal agencies. At this time, it is uncertain when ultimate approval of the license extension will occur.

Wind Generation — In December 2008, the first NSP-Minnesota owned wind generation plant, the 100 MW Grand Meadow wind farm, went into service.  The project was developed through a build-own-transfer arrangement with a large wind energy developer (enXco) at a cost of approximately $210 million.  NSP-Minnesota plans to invest approximately $900 million over three years for a 201 MW project in southwestern Minnesota, called the Nobles Wind Project, and a 150 MW project in southeastern North Dakota, called the Merricourt Wind Project.  These projects are expected to be operational by the end of 2010 and 2011, respectively.  On June 10, 2009, the MPUC issued an order approving investments in the Nobles and Merricourt Wind Projects.  NDPSC action is pending.

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.  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.  Several parties have filed petitions asking for reconsideration of various decisions in the MPUC order.   On July 14, 2009, the MPUC voted to reconsider the decision and modify the conditions in a manner supported by NSP-Minnesota. The modifications clarify that schedules for wind project additions are also to be coordinated with MPUC approvals in resource planning dockets.

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

As part of CapX 2020, Otter Tail Power Company, Minnesota Power and Minnkota Power Cooperative (on behalf of themselves and NSP-Minnesota and Great River Energy) filed a 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

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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.

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

On May 11, 2009, the city of Taylors Falls, Minn. filed a petition asking the MPUC to amend the route permit issued to NSP-Minnesota in February 2008 for the Chisago/Apple River 115/161 KV upgrade project, alleging the approved route and configuration violate a 2000 settlement agreement signed to resolve a prior transmission routing proceeding.   NSP-Minnesota filed reply comments on June 2, 2009, arguing the petition was untimely and procedurally improper.  On June 29, 2009, the MPUC issued an order that did not modify the route permit based on the new record information.  The MPUC instead required NSP-Minnesota to notify the MPUC within ten days of a decision by the U.S. Army Corps of Engineers (COE) on the permit application to the COE for construction near the St. Croix River.  NSP-Minnesota is now attempting to resolve all issues with the city.

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

The NSP System was subject to electric reliability standards compliance audits 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.  Xcel Energy expects that penalties may be assessed by certain of the NERC regional entities in conjunction with some of the self-reports.  The penalties are not expected to be material.

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.

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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.

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.

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

Legislative and regulatory responses related to climate change create financial risk.  Increased public awareness and concern may result in more regional and/or federal requirements to reduce or mitigate the effects of GHG.  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 issued an Advanced Notice of Proposed Rulemaking that proposes to regulate GHGs under the Clean Air Act.  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.

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.  An 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.

Item 6. EXHIBITS

*Indicates incorporation by reference

3.01*	Articles of Incorporation and Amendments of Northern Power Corp. (renamed Northern States Power Co. (a Minnesota corporation) on Aug. 21, 2000)(Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
3.02*	By-Laws of Northern States Power Co. (a Minnesota corporation) (Exhibit 3.02 to Form 8-K (file no. 001-31387) dated June 3, 2008).
10.01*	Amendment dated as of April 13, 2009 to the NSP-Minnesota Credit Agreement dated as of Dec. 14, 2006 (Exhibit 10.02 of Form 10-Q of Xcel Energy dated July 31, 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.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on Aug. 3, 2009.

Northern States Power Company (a Minnesota corporation)

(Registrant)

/s/  TERESA S. MADDEN

Teresa S. Madden

Vice President and Controller

/s/  BENJAMIN G.S. FOWKE III

Benjamin G.S. Fowke III

Vice President and Chief Financial Officer

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