Northern States Power 10-Q 2011 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2011

or

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

Commission File Number: 001-31387

Northern States Power Company

(Exact name of registrant as specified in its charter)

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

(612) 330-5500

 (Registrant’s telephone number, including area code)

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

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 Oct. 28, 2011
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	29
Item 4 —	Controls and Procedures	35
PART II — OTHER INFORMATION
Item 1 —	Legal Proceedings	35
Item 1A —	Risk Factors	36
Item 6 —	Exhibits	37
SIGNATURES		38
Certifications Pursuant to Section 302		1
Certifications Pursuant to Section 906		1
Statement Pursuant to Private Litigation		1

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

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PART 1 — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands of dollars)

	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2011			2010			2011			2010
Operating revenues
Electric	$	1,103,875		$	1,068,416		$	2,916,082		$	2,761,268
Natural gas		58,914			57,211			439,562			397,831
Other		5,349			5,286			15,912			15,211
Total operating revenues		1,168,138			1,130,913			3,371,556			3,174,310
Operating expenses
Electric fuel and purchased power		428,333			457,805			1,181,007			1,182,538
Cost of natural gas sold and transported		28,532			28,810			286,744			269,356
Cost of sales — other		3,341			3,159			9,132			8,729
Other operating and maintenance expenses		266,451			258,015			783,291			770,603
Conservation program expenses		33,594			21,511			102,006			56,962
Depreciation and amortization		111,436			105,670			316,264			301,210
Taxes (other than income taxes)		40,580			38,269			126,567			117,876
Total operating expenses		912,267			913,239			2,805,011			2,707,274
Operating income		255,871			217,674			566,545			467,036
Other income, net		102			1,766			1,781			1,409
Allowance for funds used during construction — equity		8,700			9,197			28,439			26,698
Interest charges and financing costs
Interest charges — includes other financing costs of $1,636, $1,405, $4,678 and $4,216, respectively		52,069			50,407			155,997			149,940
Allowance for funds used during construction — debt		(4,753	)		(4,115	)		(16,037	)		(13,592	)
Total interest charges and financing costs		47,316			46,292			139,960			136,348
Income before income taxes		217,357			182,345			456,805			358,795
Income taxes		75,455			72,558			157,505			140,829
Net income	$	141,902		$	109,787		$	299,300		$	217,966

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands of dollars)

	Nine Months Ended Sept. 30,
	2011			2010
Operating activities
Net income	$	299,300		$	217,966
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		320,295			300,455
Nuclear fuel amortization		75,292			78,150
Deferred income taxes		136,672			174,603
Amortization of investment tax credits		(2,021	)		(2,338	)
Allowance for equity funds used during construction		(28,439	)		(26,698	)
Net realized and unrealized hedging and derivative transactions		711			(8,534	)
Changes in operating assets and liabilities:
Accounts receivable		(4,855	)		10,061
Accrued unbilled revenues		65,382			52,331
Inventories		(2,621	)		(13,889	)
Other current assets		10,382			(60,131	)
Accounts payable		(51,371	)		(146,757	)
Net regulatory assets and liabilities		108,126			32,502
Other current liabilities		19,929			(3,590	)
Pension and other employee benefits		(44,394	)		1,557
Change in other noncurrent assets		(1,600	)		284
Change in other noncurrent liabilities		(30,875	)		(16,177	)
Net cash provided by operating activities		869,913			589,795
Investing activities
Utility capital/construction expenditures		(809,953	)		(892,638	)
Merricourt refund		101,261			-
Merricourt deposit		(90,833	)		-
Allowance for equity funds used during construction		28,439			26,698
Purchase of investments in external decommissioning fund		(1,741,907	)		(3,309,093	)
Proceeds from the sale of investments in external decommissioning fund		1,741,909			3,314,356
Investments in utility money pool arrangement		(432,000	)		(55,500	)
Repayments from utility money pool arrangement		432,000			62,500
Advances to affiliate		(111,300	)		(218,200	)
Advances from affiliate		148,300			229,800
Change in restricted cash		(100,007	)		-
Other investments		(3,946	)		444
Net cash used in investing activities		(838,037	)		(841,633	)
Financing activities
Borrowings under utility money pool arrangement		253,600			657,500
Repayments under utility money pool arrangement		(184,600	)		(657,500	)
Proceeds from issuance of long-term debt		-			493,609
Repayment of long-term debt, including reacquisition premiums		(30	)		(175,029	)
Capital contributions from parent		125,000			211,431
Dividends paid to parent		(232,510	)		(174,569	)
Net cash (used in) provided by financing activities		(38,540	)		355,442
Net (decrease) increase in cash and cash equivalents		(6,664	)		103,604
Cash and cash equivalents at beginning of period		38,408			46,303
Cash and cash equivalents at end of period	$	31,744		$	149,907
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(162,167	)	$	(160,079	)
Cash paid for income taxes, net		(19,654	)		(18,846	)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	23,436		$	36,193

See Notes to Consolidated Financial Statements

4

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in thousands of dollars)

Assets	Sept. 30, 2011			Dec. 31, 2010
Current assets
Cash and cash equivalents	$	31,744		$	38,408
Restricted cash		100,007			-
Notes receivable from affiliates		-			37,000
Accounts receivable, net		319,032			313,485
Accounts receivable from affiliates		26,174			26,866
Accrued unbilled revenues		184,011			249,393
Inventories		282,794			280,173
Regulatory assets		160,605			164,943
Derivative instruments		36,611			39,892
Prepayments and other		35,143			39,229
Total current assets		1,176,121			1,189,389
Property, plant and equipment, net		8,515,199			7,822,220
Other assets
Nuclear decommissioning fund and other investments		1,291,076			1,366,069
Regulatory assets		789,869			671,391
Derivative instruments		83,932			101,258
Other		31,423			31,333
Total other assets		2,196,300			2,170,051
Total assets	$	11,887,620		$	11,181,660
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	450,005		$	19
Borrowings under utility money pool arrangement		69,000			-
Accounts payable		306,576			384,455
Accounts payable to affiliates		46,257			61,753
Taxes accrued		153,023			140,020
Accrued interest		42,367			66,641
Dividends payable to parent		-			58,372
Derivative instruments		51,545			27,311
Regulatory liabilities		177,478			42,122
Other		121,661			103,525
Total current liabilities		1,417,912			884,218
Deferred credits and other liabilities
Deferred income taxes		1,594,681			1,449,082
Deferred investment tax credits		32,416			34,437
Asset retirement obligations		1,194,189			875,361
Regulatory liabilities		466,805			462,574
Pension and employee benefit obligations		311,027			351,130
Derivative instruments		183,818			197,771
Other		64,689			93,025
Total deferred credits and other liabilities		3,847,625			3,463,380
Commitments and contingent liabilities
Capitalization
Long-term debt		2,888,643			3,337,893
Common stock – authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares		10			10
Additional paid in capital		2,366,387			2,241,387
Retained earnings		1,377,100			1,251,938
Accumulated other comprehensive (loss) income		(10,057	)		2,834
Total common stockholder's equity		3,733,440			3,496,169
Total liabilities and equity	$	11,887,620		$	11,181,660

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 Sept. 30, 2011 and Dec. 31, 2010; the results of its operations for the three and nine months ended Sept. 30, 2011 and 2010; and its cash flows for the nine months ended Sept. 30, 2011 and 2010. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2011 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2010 balance sheet information has been derived from the audited 2010 consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2010. These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2010, filed with the SEC on Feb. 28, 2011. Due to the seasonality of NSP-Minnesota’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

1. Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2010, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2. Accounting Pronouncements

Recently Issued

Fair Value Measurement — In May 2011, the Financial Accounting Standards Board (FASB) issued Fair Value Measurement (Topic 820) — Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (Accounting Standards Update (ASU) No. 2011-04), which provides additional guidance for fair value measurements. These updates to the FASB Accounting Standards Codification (ASC or Codification) include clarifications regarding existing fair value measurement principles and disclosure requirements, and also specific new guidance for items such as measurement of instruments classified within stockholders’ equity and disclosures regarding the sensitivity of Level 3 measurements to changes in valuation model inputs. These updates to the Codification are effective for interim and annual periods beginning after Dec. 15, 2011. NSP-Minnesota does not expect the implementation of this guidance to have a material impact on its consolidated financial statements.

Comprehensive Income — In June 2011, the FASB issued Comprehensive Income (Topic 220) — Presentation of Comprehensive Income (ASU No. 2011-05), which updates the Codification to require the presentation of the components of net income, the components of other comprehensive income (OCI) and total comprehensive income in either a single continuous statement of comprehensive income or in two separate, but consecutive statements of net income and comprehensive income. These updates do not affect the items reported in OCI or the guidance for reclassifying such items to net income. These updates to the Codification are effective for interim and annual periods beginning after Dec. 15, 2011. NSP-Minnesota does not expect the implementation of this presentation guidance to have a material impact on its consolidated financial statements.

Multiemployer Plans — In September 2011, the FASB issued Multiemployer Plans (Subtopic 715-80) — Disclosures about an Employer’s Participation in a Multiemployer Plan (ASU No. 2011-09), which updates the Codification to require certain disclosures about an entity’s involvement with multiemployer pension and other postretirement benefit plans. These updates do not affect recognition and measurement guidance for an employer’s participation in multiemployer plans, but rather require additional disclosure such as the nature of multiemployer plans and the employer’s participation, contributions to the plans and details regarding significant plans. These updates to the Codification are effective for annual periods ending after Dec. 15, 2011. NSP-Minnesota does not expect the implementation of this disclosure guidance to have a material impact on its consolidated financial statements.

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3. Selected Balance Sheet Data

(Thousands of Dollars)	Sept. 30, 2011			Dec. 31, 2010
Accounts receivable, net
Accounts receivable	$	339,764		$	334,481
Less allowance for bad debts		(20,732	)		(20,996	)
	$	319,032		$	313,485
Inventories
Materials and supplies	$	129,264		$	122,706
Fuel		89,764			95,804
Natural gas		63,766			61,663
	$	282,794		$	280,173
Property, plant and equipment, net
Electric plant	$	11,349,307		$	10,563,424
Natural gas plant		994,543			979,256
Common and other property		507,191			510,577
Construction work in progress		722,205			695,292
Total property, plant and equipment		13,573,246			12,748,549
Less accumulated depreciation		(5,370,621	)		(5,222,980	)
Nuclear fuel		1,928,912			1,837,697
Less accumulated amortization		(1,616,338	)		(1,541,046	)
	$	8,515,199		$	7,822,220

4. Income Taxes

Except to the extent noted below, the circumstances set forth in Note 6 to the consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2010 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit — NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2007 federal income tax return expired in September 2011. The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expires in September 2012. The Internal Revenue Service (IRS) commenced an examination of tax years 2008 and 2009 in the third quarter of 2010. As of Sept. 30, 2011, the IRS had not proposed any material adjustments to tax years 2008 and 2009.

State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Sept. 30, 2011, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations was 2007. As of Sept. 30, 2011, there were no state income tax audits in progress.

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

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

(Millions of Dollars)	Sept. 30, 2011		Dec. 31, 2010
Unrecognized tax benefit — Permanent tax positions	$	2.0	$	4.0
Unrecognized tax benefit — Temporary tax positions		17.7		18.5
Unrecognized tax benefit balance	$	19.7	$	22.5

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

(Millions of Dollars)	Sept. 30, 2011			Dec. 31, 2010
NOL and tax credit carryforwards	$	(8.6	)	$	(11.0	)

The decrease in the unrecognized tax benefit balance for the nine months ended Sept. 30, 2011 of $2.8 million was due primarily to the resolution of certain federal audit matters andadjustments for prior year’s activity. NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefits could decrease by up to approximately $13 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Sept. 30, 2011 and Dec. 31, 2010 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2011 or Dec. 31, 2010.

5. Rate Matters

Except to the extent noted below, the circumstances set forth in Note 11 to the consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2010 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Base Rates

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

NSP-Minnesota Electric Rate Case— In November 2010, NSP-Minnesota filed a request with the MPUC to increase annual electric rates in Minnesota for 2011 by approximately $150 million, or an increase of 5.62 percent and an additional increase of $48.3 million or 1.81 percent in 2012. The rate filing was based on a 2011 forecast test year and included a requested return on equity (ROE) of 11.25 percent, an electric rate base of approximately $5.6 billion and an equity ratio of 52.56 percent.

The MPUC approved an interim rate increase of $123 million, subject to refund, effective Jan. 2, 2011. The interim rates will remain in effect until the MPUC makes its final decision on the case.

In June 2011, NSP-Minnesota revised its requested rate increase to $122.8 million, reflecting a revised ROE of 10.85 percent and other adjustments. The Division of Energy Resources (DOER) revised its recommended rate increase to approximately $84.7 million in 2011 and an additional rate increase of $34 million in 2012, reflecting an ROE of 10.37 percent. The primary differences between the NSP-Minnesota requested rate increase and the DOER updated recommendation are associated with ROE and compensation related issues.

In August 2011, NSP-Minnesota submitted supplemental testimony, revising its requested rate increase to approximately $122 million for 2011 and a 2012 step increase of approximately $29 million. The revisions are due to NSP-Minnesota’s decision to delay the Monticello nuclear plant extended power uprate from the fall of 2011 to the fall of 2012. Subsequently, NSP-Minnesota anticipates prolonging the extended power uprate to the spring 2013 refueling outage.

NSP-Minnesota has recorded a provision for revenue subject to refund of approximately $27 million for the first nine months of 2011, of which $12 million was recorded during the three months ended Sept. 30, 2011. The provision reflects an outcome that is consistent with the DOER position on various issues.

The MPUC decision is expected in the first quarter of 2012.

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

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

The NDPSC approved an interim rate increase of approximately $17.4 million, subject to refund, effective Feb. 18, 2011. The interim rates will remain in effect until the NDPSC makes its final decision on the case.

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

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

In October 2011, the NDPSC held hearings on the settlement. An NDPSC decision is expected in the fourth quarter of 2011 with final rates expected to be implemented in the first quarter of 2012.

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

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

As a result of delays in the South Dakota rate case process, NSP-Minnesota anticipates requesting implementation of interim rates beginning Jan. 1, 2012 in the fourth quarter of 2011. A final decision on interim rates is expected in the first quarter of 2012.

Electric, Purchased Gas and Resource Adjustment Clauses

Conservation Improvement Program (CIP) Rider — CIP expenses are recovered through base rates and a rider that is adjusted annually. Under the 2010 electric CIP rider request approved by the MPUC in October 2010, NSP-Minnesota recovered $67.3 million through the rider during November 2010 to September 2011. This is in addition to $48.5 million recovered through base rates. NSP-Minnesota recovered $20.6 million through the natural gas CIP rider approved in November 2010, during December 2010 to September 2011. This is in addition to $3.3 million recovered in base rates.

In 2011, NSP-Minnesota filed its annual rider petitions requesting recovery of $84.8 million of electric CIP expenses and financial incentives and $13.6 million of natural gas CIP expenses and financial incentives to be recovered during October 2011 through September 2012. This proposed recovery through the riders is in addition to an estimated $52.6 million and $3.8 million through electric and gas base rates, respectively.

Renewable Development Fund (RDF) Rider —The MPUC has approved an RDF rider that allows annual adjustments to retail electric rates to provide for the recovery of RDF program and project expenses. The primary components of RDF costs are legislatively mandated expenses such as renewable energy production incentive payments and bonus solar rebates. In October 2010, NSP-Minnesota filed its annual request to recover $19.2 million in expenses for 2011. In June 2011, the MPUC approved recovery of the costs requested.

In October 2011, NSP-Minnesota filed its annual request to recover $17.3 million in expenses for 2012.

Transmission Cost Recovery (TCR) Rider — The MPUC has approved a TCR rider that allows annual adjustments to retail electric rates to provide recovery of certain incremental transmission investments between rate cases. In September 2011, the MPUC approved a TCR rider expected to recover $11.5 million in 2011, as well as $22.3 million in 2012. Rates are expected to be effective beginning Nov. 1, 2011.

9

Renewable Energy Standard (RES) Rider — The MPUC has approved a RES rider to recover the costs for utility-owned projects implemented in compliance with the Minnesota RES. In September 2011, the MPUC approved a RES rider to recover $40.8 million during 2011. The MPUC also ordered that $9.5 million of over-recovery be credited to customers during November 2011, and to begin collecting forecasted Dec. 1, 2011 through Dec. 31, 2012 revenue requirements of $43.1 million beginning Dec. 1, 2011.

Annual Automatic Adjustment Report — In September 2011, NSP-Minnesota filed its annual electric and natural gas automatic adjustment reports for July 1, 2010 through June 30, 2011. During that time period, $822.8 million in fuel and purchased energy costs were recovered from Minnesota electric customers through the fuel clause adjustment. In addition, approximately $371.6 million of purchased natural gas and transportation costs were recovered from Minnesota natural gas customers through the purchased gas adjustment.

The DOER recommended approval of the 2009/2010 gas automatic adjustment report in June 2011 for recovery of $354.5 million, and the report is pending MPUC action. The 2009/2010 electric automatic adjustment report for recovery of $749.5 million is pending DOER comments and MPUC action.

The MPUC approved the 2008/2009 gas automatic adjustment report in March 2011 for recovery of $500.8 million. Approval of the 2008/2009 electric automatic adjustment report for recovery of $803.6 million is pending DOER comments and MPUC action.

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

Rate Increase for Grandfathered Transmission Service Customers — In May 2010, NSP-Minnesota filed a request with the FERC to revise the rate applicable to eight wholesale customers taking transmission service under a “grandfathered” 1998 rate schedule (known as Tm-1). A FERC ALJ approved an interim rate increase of approximately $5 million in January 2011. In October 2011, the FERC approved the settlement, which resulted in an increase in revenues for NSP-Minnesota of approximately $3.5 million annually.

6. Commitments and Contingent Liabilities

Except as noted below and in Note 5 to the consolidated financial statements in this Quarterly Report on Form 10-Q, the circumstances set forth in Notes 11, 12 and 13 to the consolidated financial statements in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2010 appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to NSP-Minnesota’s financial position.

Commitments

Variable Interest Entities— The accounting guidance for consolidation of variable interest entities requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary.

Purchased Power Agreements — Under certain purchased power agreements, NSP-Minnesota purchases power from independent power producing entities that own natural gas or biomass fueled power plants for which NSP-Minnesota is required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which NSP-Minnesota procures the natural gas required to produce the energy that it purchases.

NSP-Minnesota has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over operating and maintenance (O&M) expenses, historical and estimated future fuel and electricity prices, and financing activities. NSP-Minnesota has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. NSP-Minnesota had approximately 1,064 megawatts (MW) of capacity under long-term purchased power agreements as of Sept. 30, 2011 and Dec. 31, 2010 with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2028.

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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 —The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and comparable state laws impose liability, without regarding the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances to the environment. 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, for which NSP-Minnesota is alleged to be a PRP that sent hazardous materials and wastes. At Sept. 30, 2011 and Dec. 31, 2010, the liability for the cost of remediating these sites was estimated to be $3.0 million and $0.4 million, respectively, of which $0.8 million and $0.3 million, respectively, was considered to be a current liability.

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 12 of the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2010. 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 not expected to be material and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Other Environmental Requirements

Environmental Protection Agency (EPA) Greenhouse Gas (GHG) Regulation — In December 2009, the EPA issued its “endangerment” finding that GHG emissions endanger public health and welfare. In January 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold.

GHG New Source Performance Standard Proposal — The EPA plans to propose GHG regulations applicable to emissions from new and existing power plants under the Clean Air Act (CAA). The EPA had planned to release its proposal in September 2011, but has delayed it without establishing a new proposal date.

Cross State Air Pollution Rule (CSAPR) — On July 7, 2011, the EPA issued its CSAPR. The rule, previously called the Clean Air Transport Rule (CATR), addresses long range transport of particulate matter and ozone by requiring reductions in sulfur dioxide (SO2) and nitrogen oxide (NOx) from utilities located in the eastern half of the U.S., including Minnesota. The CSAPR sets more stringent requirements than the proposed CATR. The rule creates an emissions trading program. NSP-Minnesota may comply by reducing emissions and/or purchasing allowances. The CSAPR is a final rule and requires compliance beginning in 2012.

To comply with the CSAPR in Minnesota, NSP-Minnesota currently intends to utilize a combination of emissions reductions through control technology upgrades at NSP-Minnesota’s Sherco plant, including the installation of a sparger system for SO2 control, at an estimated cost of $10 million total in 2012 and 2013, and system operating changes to the Black Dog and the Sherco plants. If available, NSP-Minnesota will also consider allowance purchases. In addition, NSP-Minnesota has filed a petition for reconsideration with the EPA and a petition for review of the CSAPR with the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit) seeking the allocation of additional emission allowances to NSP-Minnesota. NSP-Minnesota contends that the EPA’s method of allocating allowances arbitrarily resulted in fewer allowances for its Riverside and High Bridge plants than should have been awarded to reflect their operations during the baseline period, which included coal-fired operations prior to their conversion to natural gas. If successful, additional allowances would reduce NSP-Minnesota’s costs to comply with the reductions imposed by the CSAPR.

NSP-Minnesota continues to evaluate its compliance strategy. NSP-Minnesota believes the cost of any required capital investment, allowance purchases or costs associated with redispatch will be recoverable from customers.

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Clean Air Interstate Rule (CAIR) — In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions. In 2008, the D.C. Circuit vacated and remanded the CAIR, but subsequently allowed the CAIR to continue into effect pending the EPA’s adoption of a new rule that addressed the deficiencies found by the court. In 2011, the EPA finalized the CSAPR to replace the CAIR beginning in 2012. The CAIR does not apply in Minnesota because the court specifically found that the EPA had not adequately justified the application of the CAIR to Minnesota.

Electric Generating Unit (EGU) Maximum Achievable Control Technology (MACT) Rule — In 2005, the EPA issued the Clean Air Mercury Rule (CAMR), which regulated mercury emissions from power plants. In February 2008, the U.S. Court of Appeals for the District of Columbia vacated the CAMR, which impacted federal CAMR requirements, but not necessarily state-only mercury legislation and rules.

In March 2011, the EPA issued the proposed EGU MACT designed to address emissions of mercury and other hazardous air pollutants for coal-fired utility units greater than 25 MW. The EPA has indicated that it intends to issue the final rule by December 2011. NSP-Minnesota anticipates that the EPA will require affected facilities to demonstrate compliance within three to four years. NSP-Minnesota believes these costs would be recoverable through regulatory mechanisms, and it does not expect a material impact on its results of operations.

Minnesota Mercury Legislation — In 2006, the Minnesota legislature enacted the Mercury Emissions Reduction Act (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. NSP-Minnesota installed and is operating continuous mercury emission monitoring systems at these generating facilities.

In November 2008, the MPUC approved the implementation of the Sherco Unit 3 and A.S. King mercury emission reduction plans. A sorbent injection control system was installed at Sherco Unit 3 in December 2009 and at A.S. King in December 2010. In 2010, NSP-Minnesota collected the revenue requirements associated with these projects through the mercury cost reduction (MCR) rider. In the 2010 Minnesota electric general rate case, NSP-Minnesota proposed moving the costs of these projects into base rates as part of the interim rates effective on Jan. 2, 2011. Concurrent with the implementation of interim rates, the MCR rider was reduced to zero.

In December 2009, NSP-Minnesota filed its mercury control plan at Sherco Units 1 and 2 with the MPUC and the Minnesota Pollution Control Agency (MPCA). In October 2010, the MPUC approved the plan, which will require installation of mercury controls on Sherco Units 1 and 2 by the end of 2014. NSP-Minnesota has incurred $1.5 million in study costs to date and spent $0.6 million through Dec. 31, 2010 for testing and studying of technologies. At Sept. 30, 2011, the estimated annual testing and study cost is $0.5 million. NSP-Minnesota projects installation costs of $12.0 million for the units and O&M expense of $10.0 million per year beginning in 2014.

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

NSP-Minnesota submitted its BART alternatives analysis for Sherco Units 1 and 2 in 2006. The MPCA reviewed the BART analyses for all units in Minnesota and determined that overall, compliance with CAIR is better than BART. The MPCA completed their determination and proposed SO2 and NOx limits in the draft state implementation plan (SIP) that are equivalent to the reductions made under CAIR. Neither the MPCA nor the EPA has yet made a determination that the compliance with the CSAPR is better than BART or that compliance with the CSAPR will fulfill the obligation to comply with BART.

In October 2009, the U.S. Department of the Interior certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota’s Sherco Units 1 and 2. The EPA is required to make its own determination as to whether Sherco Units 1 and 2 cause or contribute to visibility impairment and, if so, whether the level of controls proposed by MPCA is appropriate.

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The MPCA determined that this certification does not alter the proposed SIP. The SIP proposes BART controls for the Sherco generating facilities that are designed to improve visibility in the national parks, but does not require selective catalytic reduction (SCR) on Units 1 and 2. The MPCA concluded that the minor visibility benefits derived from SCR do not outweigh the substantial costs. In December 2009, the MPCA Citizens Board approved the SIP, which has been submitted to the EPA for approval. In June 2011, the EPA provided comments to the MPCA on the SIP, stating the EPA’s preliminary review indicates that SCR controls should be added to Sherco Units 1 and 2, and inviting further comment from the MPCA. It is not yet known what the final requirements of the SIP will be. Until the EPA takes final action on the SIP, the total cost of compliance cannot be estimated.

Federal Clean Water Act (CWA Section 316 (b)) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. In April 2011, the EPA published the proposed rule that was modified to address earlier court decisions. The proposed rule sets prescriptive standards for minimization of aquatic species impingement but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office. NSP-Minnesota provided comments to the proposed rule. Due to the uncertainty of the final regulatory requirements, it is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time.

As part of NSP-Minnesota’s 2009 CWA permit renewal for the Black Dog plant, the MPCA required that the plant submit a plan for compliance with the CWA. The compliance plan was submitted for MPCA review and approval in April 2010. The MPCA is currently reviewing the proposal in consultation with the EPA. NSP-Minnesota anticipates a decision on the plan by the end of 2011.

Proposed Coal Ash Regulation — NSP-Minnesota’s operations generate hazardous wastes that are subject to the Federal Resource Recovery and Conservation Act and comparable state laws that impose detailed requirements for handling, storage, treatment and disposal of hazardous waste. In June 2010, the EPA published a proposed rule seeking comment on whether to regulate coal combustion byproducts (often referred to as coal ash) as hazardous or nonhazardous waste. Coal ash is currently exempt from hazardous waste regulation. If the EPA ultimately issues a final rule under which coal ash is regulated as hazardous waste, NSP-Minnesota’s costs associated with the management and disposal of coal ash would significantly increase, and the beneficial reuse of coal ash would be negatively impacted. The EPA has not announced a planned date for a final rule. The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.

Notice of Violation (NOV) — In June 2011, NSP-Minnesota received an NOV from the EPA alleging violations of the New Source Review (NSR) requirements of the CAA at the Sherco plant and Black Dog plant in Minnesota. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid 2000s should have required a permit under the NSR process. NSP-Minnesota believes it has acted in full compliance with the CAA and NSR process. NSP-Minnesota also believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. NSP-Minnesota disagrees with the assertions contained in the NOV and intends to vigorously defend its position. It is not known whether any costs would be incurred as a result of this notice.

Legal Contingencies

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

Environmental Litigation

State of Connecticut vs. Xcel Energy Inc. et al. — In 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against the following utilities, including Xcel Energy Inc., the parent company of NSP-Minnesota, to force reductions in carbon dioxide (CO2) emissions: American Electric Power Co., Southern Co., Cinergy Corp. (merged into Duke Energy Corporation) and Tennessee Valley Authority. The lawsuits allege that CO2 emitted by each company is a public nuisance. 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 September 2005, the court granted plaintiffs’ motion to dismiss on constitutional grounds. In August 2010, this decision was reversed by the Second Circuit and was appealed to the U.S. Supreme Court. In June 2011, the Supreme Court issued a ruling reversing the Second Circuit’s decision, thereby dismissing the plaintiffs’ federal claims and remanding the case for further proceedings regarding the state law claims. In September 2011, plaintiffs submitted a letter to the Second Circuit seeking to voluntarily dismiss the complaint.

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Native Village of Kivalina vs. Xcel Energy Inc. et al. — In 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U.S. District Court for the Northern District of California against Xcel Energy Inc., the parent company of NSP-Minnesota, and 23 other utility, oil, gas and coal companies. Plaintiffs claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village. Xcel Energy Inc. and NSP-Minnesota believe the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss in June 2008. In October 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds. In November 2009, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit. Oral arguments are set for Nov. 28, 2011. It is unknown when the Ninth Circuit will render a final opinion. The amount of damages claimed by plaintiffs is unknown, but likely includes the cost of relocating the village of Kivalina. Plaintiffs’ alleged relocation is estimated to cost between $95 million to $400 million. No accrual has been recorded for this matter.

Comer vs. Xcel Energy Inc. et al. — On May 27, 2011, less than a year after their initial lawsuit was dismissed, plaintiffs in this purported class action lawsuit filed a second lawsuit against more than 85 utility, oil, chemical and coal companies in U.S. District Court in Mississippi. The complaint alleges defendants’ CO2 emissions intensified the strength of Hurricane Katrina and increased the damage plaintiffs purportedly sustained to their property. Plaintiffs base their claims on public and private nuisance, trespass and negligence. Among the defendants named in the complaint are Xcel Energy Inc., SPS, PSCo, NSP-Wisconsin and NSP-Minnesota. The amount of damages claimed by plaintiffs is unknown. It is believed that this lawsuit is without merit. No accrual has been recorded for this matter.

Employment, Tort and Commercial Litigation

Merricourt Wind Project Litigation — On April 1, 2011, NSP-Minnesota terminated its agreements with enXco Development Corporation (enXco) for the development of a 150 MW wind project in southeastern North Dakota. NSP-Minnesota’s decision to terminate the agreements was based in large part on the adverse impact this project could have on endangered or threatened species protected by federal law and the uncertainty in cost and timing in mitigating this impact. NSP-Minnesota also terminated the agreements due to enXco’s nonperformance of certain other conditions, including failure to obtain a Certificate of Site Compatibility and the failure to close on the contracts by an agreed upon date of March 31, 2011. As a result, NSP-Minnesota recorded a $101 million deposit in the first quarter 2011, which was collected in April 2011. On May 5, 2011, NSP-Minnesota filed a declaratory judgment action in U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreements. On that same day, enXco also filed a separate lawsuit in the same court seeking, among other things, in excess of $240 million for an alleged breach of contract. NSP-Minnesota believes enXco’s lawsuit is without merit and has filed a motion to dismiss. On Sept. 16, 2011, the U.S. District Court denied the motion to dismiss. The trial is set to begin in late 2012 or early 2013. No accrual has been recorded for this matter.

Nuclear Power Operations and Waste Disposal

Nuclear Waste Disposal Litigation — In 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the U.S. 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 U.S. and NSP-Minnesota. At trial, NSP-Minnesota claimed damages in excess of $100 million through Dec. 31, 2004. In September 2007, the court awarded NSP-Minnesota $116.5 million in damages. In February 2008, the U.S. 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 August 2007, NSP-Minnesota filed a second complaint against the U.S. 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 claimed damages for the period Jan. 1, 2005 through Dec. 31, 2008, which included 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.

In July 2011, the U.S. and NSP-Minnesota executed a settlement agreement resolving both lawsuits, providing an initial $100 million payment from the U.S. to NSP-Minnesota, and providing a method by which NSP-Minnesota can recover its spent fuel storage costs through 2013, currently estimated to be an additional $100 million. The settlement does not address costs for used fuel storage after 2013; such costs could be the subject of future litigation. NSP-Minnesota received the initial $100 million payment in August 2011, of which $15 million is expected to be allocated to NSP-Wisconsin through the interchange agreement. NSP-Minnesota will make the appropriate regulatory filings to address the best means of returning these settlement amounts to ratepayers and to deal with costs of litigation. As of Sept. 30, 2011, the payment received from the DOE has been recorded as restricted cash and a regulatory liability.

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7. Borrowings and Other Financing Instruments

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

(Millions of Dollars)	Three Months Ended Sept. 30, 2011			Twelve Months Ended Dec. 31, 2010
Borrowing limit	$	500		$	482
Amount outstanding at period end		-			-
Average amount outstanding		21			35
Maximum amount outstanding		80			389
Weighted average interest rate, computed on a daily basis		0.34	%		0.37	%
Weighted average interest rate at period end		N/A			N/A

Credit Facilities — In order to use its commercial paper program to fulfill short-term funding needs, NSP-Minnesota must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an amount exceeding available capacity under the credit agreement.

During March of 2011, NSP-Minnesota executed a new four-year credit agreement. The total size of the credit facility is $500 million and terminates in March 2015. NSP-Minnesota has the right to request an extension of the revolving termination date for two additional one-year periods, subject to majority bank group approval.

The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. Other features of NSP-Minnesota’s credit facility include:

· The credit facility may be increased by up to $100 million.

· The credit facility has a financial covenant requiring that NSP-Minnesota’s debt-to-total capitalization ratio be less than or equal to 65 percent. NSP-Minnesota was in compliance as its debt-to-total capitalization ratio was 48 percent at Sept. 30, 2011. If NSP-Minnesota does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender.

· The credit facility has a cross-default provision that provides NSP-Minnesota will be in default on its borrowings under the facility if NSP-Minnesota or any of its subsidiaries whose total assets exceed 15 percent of NSP-Minnesota’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million.

· The interest rates under the line of credit are based on the Eurodollar rate or an alternate base rate, plus a borrowing margin of 0 to 200 basis points per year based on the applicable credit ratings.

· The commitment fees, also based on applicable long-term credit ratings, are calculated on the unused portion of the line of credit at a range of 10 to 35 basis points per year.

· NSP-Wisconsin’s intercompany borrowing arrangement with NSP-Minnesota was subsequently terminated.

At Sept. 30, 2011, NSP-Minnesota had the following committed credit facility available (in millions of dollars):

Credit Facility		Drawn (a)		Available
$	500.0	$	7.1	$	492.9

(a) Includes outstanding letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. NSP-Minnesota had no direct advances on the credit facility outstanding at Sept. 30, 2011 and Dec. 31, 2010.

Letters of Credit — NSP-Minnesota uses letters of credit, generally with terms of one-year, to provide financial guarantees for certain operating obligations. At Sept. 30, 2011 and Dec. 31, 2010, there were $7.1 million and $5.3 million of letters of credit outstanding, respectively, under the credit facility. An additional $1.1 million of letters of credit not issued under the credit facility were outstanding at Sept. 30, 2011 and Dec. 31, 2010. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

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

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The following table presents money pool borrowings for NSP-Minnesota:

(Millions of Dollars)	Three Months Ended Sept. 30, 2011			Twelve Months Ended Dec. 31, 2010
Borrowing limit	$	250		$	250
Amount outstanding at period end		69			-
Average amount outstanding		13			18
Maximum amount outstanding		69			142
Weighted average interest rate, computed on a daily basis		0.35	%		0.37	%
Weighted average interest rate at period end		0.35			N/A

Long-Term Borrowings — NSP-Minnesota plans to refinance the current portion of long-term debt coming due in 2012.

8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

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

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with discounted cash flow or option pricing models using highly observable inputs.

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.

Specific valuation methods include the following:

Cash equivalents— The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values.

Investments in equity securities and other funds— Equity securities are valued using quoted prices in active markets. The fair values for commingled funds and international equity funds are measured using net asset values, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value. The investments in commingled funds and international equity funds may be redeemed for net asset value.

Investments in debt securities— Debt securities are primarily priced using recent trades and observable spreads from benchmark interest rates for similar securities, except for asset-backed and mortgage-backed securities, which also require significant, subjective risk-based adjustments to the interest rate used to discount expected future cash flows, which include estimated principal prepayments. Therefore, fair value measurements for asset-backed and mortgage-backed securities have been assigned a Level 3.

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

Commodity derivatives— The methods utilized to measure the fair value of commodity derivatives include the use of forward prices and volatilities to value commodity forwards and options. Levels are assigned to these fair value measurements based on the significance of the use of subjective forward price and volatility forecasts for commodities and delivery locations with limited observability, or the significance of contractual settlements that extend to periods beyond those readily observable on active exchanges or quoted by brokers. Electric commodity derivatives include financial transmission rights (FTRs), for which fair value is determined using complex predictive models and inputs including forward commodity prices as well as subjective forecasts of retail and wholesale demand, generation and resulting transmission system congestion. Given the limited observability of management’s forecasts for several of these inputs, fair value measurements for FTRs have been assigned a Level 3.

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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 as an assessment of the impact of NSP-Minnesota’s own credit risk when determining the fair value of commodity derivative liabilities, the impact of considering credit risk was immaterial to the fair value of commodity derivative assets and liabilities presented in the consolidated balance sheets.

Non-Derivative Instruments Fair Value Measurements

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

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

Unrealized gains for the nuclear decommissioning fund were $54.4 million and $82.5 million at Sept. 30, 2011 and Dec. 31, 2010, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $140.9 million and $65.2 million at Sept. 30, 2011 and Dec. 31, 2010, respectively.

The following tables present the cost and fair value of NSP-Minnesota’s non-derivative instruments recurring fair value measurements, the nuclear decommissioning fund investments, at Sept. 30, 2011 and Dec. 31, 2010:

	Sept. 30, 2011
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	77,875	$	75,370	$	2,505	$	-	$	77,875
Commingled funds		296,629		-		267,511		-		267,511
International equity funds		63,781		-		56,956		-		56,956
Debt securities:
Government securities		163,744		-		168,798		-		168,798
U.S. corporate bonds		174,314		-		176,450		-		176,450
Foreign securities		35,434		-		35,558		-		35,558
Municipal bonds		43,652		-		46,229		-		46,229
Asset-backed securities		10,251		-		-		10,246		10,246
Mortgage-backed securities		51,674		-		-		54,815		54,815
Equity securities:
Common stock		440,855		377,253		-		-		377,253
Total	$	1,358,209	$	452,623	$	754,007	$	65,061	$	1,271,691

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $19.4 million of miscellaneous investments.

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	Dec. 31, 2010
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	83,837	$	76,281	$	7,556	$	-	$	83,837
Commingled funds		131,000		-		133,080		-		133,080
International equity funds		54,561		-		58,584		-		58,584
Debt securities:
Government securities		146,473		-		146,654		-		146,654
U.S. corporate bonds		279,028		-		288,304		-		288,304
Foreign securities		1,233		-		1,581		-		1,581
Municipal bonds		100,277		-		97,557		-		97,557
Asset-backed securities		32,558		-		-		33,174		33,174
Mortgage-backed securities		68,072		-		-		72,589		72,589
Equity securities:
Common stock		436,334		435,270		-		-		435,270
Total	$	1,333,373	$	511,551	$	733,316	$	105,763	$	1,350,630

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $15.4 million of miscellaneous investments.

The following tables present the changes in Level 3 nuclear decommissioning fund investments:

	Three Months Ended Sept. 30,
	2011						2010
	Mortgage-			Asset-			Mortgage-			Asset-
	Backed			Backed			Backed			Backed
(Thousands of Dollars)	Securities			Securities			Securities			Securities
Balance at July 1	$	62,271		$	21,004		$	65,059		$	40,067
Purchases		1,972			9,496			-			-
Settlements		(8,978	)		(19,443	)		(1,949	)		(5,744	)
(Losses) gains recognized as regulatory assets and liabilities		(450	)		(811	)		1,286			171
Balance at Sept. 30	$	54,815		$	10,246		$	64,396		$	34,494

	Nine Months Ended Sept. 30,
	2011						2010
	Mortgage-			Asset-			Mortgage-			Asset-
	Backed			Backed			Backed			Backed
(Thousands of Dollars)	Securities			Securities			Securities			Securities
Balance at Jan. 1	$	72,589		$	33,174		$	81,189		$	11,918
Purchases		101,037			10,252			46,477			36,042
Settlements		(117,435	)		(32,559	)		(68,124	)		(13,853	)
(Losses) gains recognized as regulatory assets and liabilities		(1,376	)		(621	)		4,854			387
Balance at Sept. 30	$	54,815		$	10,246		$	64,396		$	34,494

18

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class at Sept. 30, 2011:

	Final Contractual Maturity
(Thousands of Dollars)	Due in 1 Year or Less		Due in 1 to 5 Years		Due in 5 to 10 Years		Due after 10 Years		Total
Government securities	$	8,232	$	105,016	$	35,623	$	19,927	$	168,798
U.S. corporate bonds		345		42,949		114,639		18,517		176,450
Foreign securities		-		16,569		18,032		957		35,558
Municipal bonds		-		-		33,282		12,947		46,229
Asset-backed securities		-		5,836		4,410		-		10,246
Mortgage-backed securities		-		-		1,171		53,644		54,815
Debt securities	$	8,577	$	170,370	$	207,157	$	105,992	$	492,096

Derivative Instruments Fair Value Measurements

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

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

At Sept. 30, 2011, accumulated OCI related to interest rate derivatives included $0.1 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

At Sept. 30, 2011, NSP-Minnesota had unsettled interest rate swaps outstanding with a total notional amount of $225 million. These interest rate swaps were designated as hedges, and as such, changes in fair value are recorded to OCI.

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

Commodity Derivatives — NSP-Minnesota enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, gas for resale, and vehicle fuel.

At Sept. 30, 2011, NSP-Minnesota had vehicle fuel contracts designated as cash flow hedges extending through December 2014. NSP-Minnesota also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in OCI or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. NSP-Minnesota recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three and nine months ended Sept. 30, 2011 and 2010.

At Sept. 30, 2011, accumulated OCI related to commodity derivative cash flow hedges included $0.1 million of net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

Additionally, NSP-Minnesota enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenue, net of amounts credited to customers under margin-sharing mechanisms.

19

The following table details the gross notional amounts of commodity forwards, options, and FTRs at Sept. 30, 2011 and Dec. 31, 2010:

(Amounts in Thousands) (a)(b)	Sept. 30, 2011		Dec. 31, 2010
Megawatt hours (MWh) of electricity		53,709		44,376
MMBtu of natural gas		14,620		14,100
Gallons of vehicle fuel		358		440

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

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

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

	Three Months Ended Sept. 30,
(Thousands of Dollars)	2011			2010
Accumulated other comprehensive income related to cash flow hedges at July 1	$	5,021		$	4,368
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges		(13,112	)		25
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(34	)		306
Accumulated other comprehensive (loss) income related to cash flow hedges at Sept. 30	$	(8,125	)	$	4,699

	Nine Months Ended Sept. 30,
(Thousands of Dollars)	2011			2010
Accumulated other comprehensive income related to cash flow hedges at Jan. 1	$	4,977		$	3,941
After-tax net unrealized losses related to derivatives accounted for as hedges		(13,007	)		(108	)
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(95	)		866
Accumulated other comprehensive (loss) income related to cash flow hedges at Sept. 30	$	(8,125	)	$	4,699

NSP-Minnesota had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 2011 and 2010. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

The following tables detail the impact of derivative activity during the three and nine months ended Sept. 30, 2011 and 2010, on OCI, regulatory assets and liabilities, and income:

	Three Months Ended Sept. 30, 2011
	Fair Value Changes Recognized During the Period in:						Pre-Tax Amounts Reclassified into Income During the Period from:						Pre-Tax Gains
(Thousands of Dollars)	Other Comprehensive Loss			Regulatory Assets and Liabilities			Other Comprehensive Loss			Regulatory Assets and Liabilities			Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	(22,032	)	$	-		$	(27	) (a)	$	-		$	-
Vehicle fuel and other commodity		(116	)		-			(30	) (e)		-			-
Total	$	(22,148	)	$	-		$	(57	)	$	-		$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-		$	-		$	338	(b)
Electric commodity		-			10,392			-			(11,050	) (c)		-
Natural gas commodity		-			(8,106	)		-			-			-
Total	$	-		$	2,286		$	-		$	(11,050	)	$	338

20

	Nine Months Ended Sept. 30, 2011
	Fair Value Changes Recognized During the Period in:						Pre-Tax Amounts Reclassified into Income During the Period from:						Pre-Tax Gains
(Thousands of Dollars)	Other Comprehensive (Loss) Income			Regulatory Assets and Liabilities			Other Comprehensive Loss			Regulatory Assets and Liabilities			Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	(22,032	)	$	-		$	(81	) (a)	$	-		$	-
Vehicle fuel and other commodity		61			-			(85	) (e)		-			-
Total	$	(21,971	)	$	-		$	(166	)	$	-		$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-		$	-		$	7,013	(b)
Electric commodity		-			29,537			-			(28,605	) (c)		-
Natural gas commodity		-			(11,658	)		-			10,928	(d)		-
Total	$	-		$	17,879		$	-		$	(17,677	)	$	7,013

	Three Months Ended Sept. 30, 2010
	Fair Value Changes Recognized During the Period in:					Pre-Tax Amounts Reclassified into Income During the Period from:						Pre-Tax Gains
(Thousands of Dollars)	Other Comprehensive Income		Regulatory Assets and Liabilities			Other Comprehensive (Loss) Income			Regulatory Assets and Liabilities			Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	-	$	-		$	(27	) (a)	$	-		$	-
Vehicle fuel and other commodity		42		-			548	(e)		-			-
Total	$	42	$	-		$	521		$	-		$	-
Other derivative instruments
Trading commodity	$	-	$	-		$	-		$	-		$	4,888	(b)
Electric commodity		-		6,569			-			(8,259	) (c)		-
Natural gas commodity		-		(11,794	)		-			-			-
Total	$	-	$	(5,225	)	$	-		$	(8,259	)	$	4,888

21

	Nine Months Ended Sept. 30, 2010
	Fair Value Changes Recognized During the Period in:						Pre-Tax Amounts Reclassified into Income During the Period from:						Pre-Tax Gains
(Thousands of Dollars)	Other Comprehensive Loss			Regulatory Assets and Liabilities			Other Comprehensive (Loss) Income			Regulatory Assets and Liabilities			Recognized During the Period in Income
Derivatives designated as cash flow hedges
Interest rate	$	-		$	-		$	(81	) (a)	$	-		$	-
Vehicle fuel and other commodity		(184	)		-			1,548	(e)		-			-
Total	$	(184	)	$	-		$	1,467		$	-		$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-		$	-		$	11,015	(b)
Electric commodity		-			(3,014	)		-			(13,097	) (c)		-
Natural gas commodity		-			(19,638	)		-			586	(d)		-
Total	$	-		$	(22,652	)	$	-		$	(12,511	)	$	11,015

(a) Recorded to interest charges.

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

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

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

(e) Recorded to O&M expenses.

Credit Related Contingent Features — Contract provisions of the derivative instruments that NSP-Minnesota enters into may require the posting of collateral or settlement of the contracts for various reasons, including if NSP-Minnesota is unable to maintain its credit ratings.If the credit ratings at NSP-Minnesota were downgraded below investment grade, no contracts underlying NSP-Minnesota’s derivative liabilities at Sept. 30, 2011 and Dec. 31, 2010 would have required the posting of collateral or contract settlement.

Certain of NSP-Minnesota’s derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that NSP-Minnesota’s ability to fulfill its contractual obligations is reasonably expected to be impaired. As of Sept. 30, 2011 and Dec. 31, 2010, NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts.

22

Recurring Fair Value Measurements — The following table presents, for each of the hierarchy levels, NSP-Minnesota’s derivative assets and liabilities that are measured at fair value on a recurring basis at Sept. 30, 2011:

	Sept. 30, 2011
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	79	$	-	$	79	$	-		$	79
Other derivative instruments:
Trading commodity		55		18,477		31		18,563		(8,465	)		10,098
Electric commodity		-		-		4,978		4,978		(1,653	)		3,325
Total current derivative assets	$	55	$	18,556	$	5,009	$	23,620	$	(10,118	)		13,502
Purchased power agreements (a)													23,109
Current derivative instruments												$	36,611
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	41	$	-	$	41	$	-		$	41
Other derivative instruments:
Trading commodity		-		25,267		-		25,267		(1,770	)		23,497
Total noncurrent derivative assets	$	-	$	25,308	$	-	$	25,308	$	(1,770	)		23,538
Purchased power agreements (a)													60,394
Noncurrent derivative instruments												$	83,932
Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate	$	-	$	22,032	$	-	$	22,032	$	-		$	22,032
Other derivative instruments:
Trading commodity		14		14,043		37		14,094		(8,101	)		5,993
Electric commodity		-		-		1,653		1,653		(1,653	)		-
Natural gas commodity		521		9,147		-		9,668		-			9,668
Total current derivative liabilities	$	535	$	45,222	$	1,690	$	47,447	$	(9,754	)		37,693
Purchased power agreements (a)													13,852
Current derivative instruments												$	51,545
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	9,106	$	-	$	9,106	$	(1,770	)		7,336
Total noncurrent derivative liabilities	$	-	$	9,106	$	-	$	9,106	$	(1,770	)		7,336
Purchased power agreements (a)													176,482
Noncurrent derivative instruments												$	183,818

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

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

23

NSP-Minnesota recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for the three and nine months ended Sept. 30, 2011. The following table presents the transfers that occurred between levels during the three and nine months ended Sept. 30, 2010.

	From Level 3 to Level 2 (a) (b)
	Three Months Ended			Nine Months Ended
(Thousands of Dollars)	Sept. 30, 2010			Sept. 30, 2010
Trading commodity derivatives not designated as cash flow hedges:
Current assets	$	569		$	5,384
Noncurrent assets		12,313			21,450
Current liabilities		(776	)		(2,851	)
Noncurrent liabilities		(8,436	)		(12,345	)
Total	$	3,670		$	11,638

(a) The transfer of amounts from Level 3 to Level 2 is due to the valuation of certain long-term derivative contracts for which observable commodity pricing forecasts became a more significant input during the period.

(b) There were no transfers of amounts form Level 2 to Level 3.

The following tables present, for each of the hierarchy levels, NSP-Minnesota’s derivative assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2010:

	Dec. 31, 2010
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	70	$	-	$	70	$	-		$	70
Other derivative instruments:
Trading commodity		487		31,253		-		31,740		(18,719	)		13,021
Electric commodity		-		-		3,619		3,619		(1,226	)		2,393
Natural gas commodity		-		187		-		187		(187	)		-
Total current derivative assets	$	487	$	31,510	$	3,619	$	35,616	$	(20,132	)		15,484
Purchased power agreements (a)													24,408
Current derivative instruments												$	39,892
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	83	$	-	$	83	$	-		$	83
Other derivative instruments:
Trading commodity		-		25,850		-		25,850		(2,477	)		23,373
Natural gas commodity		-		125		-		125		(48	)		77
Total noncurrent derivative assets	$	-	$	26,058	$	-	$	26,058	$	(2,525	)		23,533
Purchased power agreements (a)													77,725
Noncurrent derivative instruments												$	101,258

24

	Dec. 31, 2010
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative liabilities
Other derivative instruments:
Trading commodity	$	392	$	25,416	$	-	$	25,808	$	(21,337	)	$	4,471
Electric commodity		-		-		1,227		1,227		(1,227	)		-
Natural gas commodity		20		9,156		-		9,176		(187	)		8,989
Total current derivative liabilities	$	412	$	34,572	$	1,227	$	36,211	$	(22,751	)		13,460
Purchased power agreements (a)													13,851
Current derivative instruments												$	27,311
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	13,351	$	-	$	13,351	$	(2,478	)	$	10,873
Natural gas commodity		-		75		-		75		(48	)		27
Total noncurrent derivative liabilities	$	-	$	13,426	$	-	$	13,426	$	(2,526	)		10,900
Purchased power agreements (a)													186,871
Noncurrent derivative instruments												$	197,771

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

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

The following table presents the changes in Level 3 commodity derivatives for the three and nine months ended Sept. 30, 2011 and 2010:

	Three Months Ended Sept. 30,
(Thousands of Dollars)	2011			2010
Balance at July 1	$	3,996		$	9,207
Purchases		-			957
Settlements		(12	)		72
Transfers out of Level 3		-			(3,670	)
Losses recognized in earnings (a)		(7	)		(1,646	)
Gains recorded as regulatory assets and liabilities		10,392			6,691
Gains reclassified from regulatory assets and liabilities to earnings		(11,050	)		(7,464	)
Balance at Sept. 30	$	3,319		$	4,147

	Nine Months Ended Sept. 30,
(Thousands of Dollars)	2011			2010
Balance at Jan. 1	$	2,392		$	27,237
Settlements		(72	)		133
Transfers out of Level 3		-			(11,638	)
Gains recognized in earnings (a)		64			4,526
Gains (losses) recorded as regulatory assets and liabilities		29,537			(3,221	)
Gains reclassified from regulatory assets and liabilities to earnings		(28,602	)		(12,890	)
Balance at Sept. 30	$	3,319		$	4,147

(a) These amounts relate to commodity derivatives held at the end of the period.

25

Fair Value of Long-Term Debt

The historical cost and fair value of NSP-Minnesota’s long-term debt are as follows:

	Sept. 30, 2011				Dec. 31, 2010
	Historical				Historical
(Thousands of Dollars)	Cost		Fair Value		Cost		Fair Value
Long-term debt, including current portion	$	3,338,648	$	4,054,427	$	3,337,912	$	3,673,214

The fair value of NSP-Minnesota’s long-term debt is estimated based on the quoted market prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality. The fair value estimates presented are based on information available to management as of Sept. 30, 2011 and Dec. 31, 2010. 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.

As of Sept. 30, 2011 and Dec. 31, 2010, the historical cost of cash and cash equivalents, restricted cash, notes and accounts receivable, and accounts payable are representative of fair value because of the short-term nature of these instruments.

9. Other Income, Net

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

	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
(Thousands of Dollars)	2011			2010			2011			2010
Interest income	$	691		$	3,291		$	3,644		$	4,485
Other nonoperating income		91			5			423			27
Insurance policy expense		(680	)		(1,516	)		(2,286	)		(3,068	)
Other nonoperating expense		-			(14	)		-			(35	)
Other income, net	$	102		$	1,766		$	1,781		$	1,409

10. Segment Information

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

· NSP-Minnesota’s regulated electric utility segment generates, transmits and distributes electricity in Minnesota, North Dakota and South Dakota. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the U.S. Regulated electric utility also includes NSP-Minnesota’s commodity trading operations.

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

· Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include appliance repair services, nonutility real estate activities and revenues associated with processing solid waste into refuse-derived fuel.

Operating results from the regulated electric utility and regulated natural gas utility serve as the primary basis for the chief operating decision maker to evaluate the dual performance of NSP-Minnesota. The accounting policies of the segments are the same as those described in Note 1 to the consolidated financial statements included in the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2010. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.

Asset and capital expenditure information is not provided for NSP-Minnesota’s reportable segments because as an integrated electric and natural gas utility, NSP-Minnesota operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.

26

To report income from continuing operations for regulated electric utility and regulated natural gas utility segments the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

	Regulated		Regulated			All			Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas			Other			Eliminations			Total
Three Months Ended Sept. 30, 2011
Operating revenues from external customers	$	1,103,875	$	58,914		$	5,349		$	-		$	1,168,138
Intersegment revenues		157		100			-			(257	)		-
Total revenues	$	1,104,032	$	59,014		$	5,349		$	(257	)	$	1,168,138
Net income (loss)	$	140,383	$	(4,967	)	$	6,486		$	-		$	141,902
Three Months Ended Sept. 30, 2010
Operating revenues from external customers	$	1,068,416	$	57,211		$	5,286		$	-		$	1,130,913
Intersegment revenues		160		4,030			-			(4,190	)		-
Total revenues	$	1,068,576	$	61,241		$	5,286		$	(4,190	)	$	1,130,913
Net income (loss)	$	119,385	$	(8,674	)	$	(924	)	$	-		$	109,787

	Regulated		Regulated		All		Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other		Eliminations			Total
Nine Months Ended Sept. 30, 2011
Operating revenues from external customers	$	2,916,082	$	439,562	$	15,912	$	-		$	3,371,556
Intersegment revenues		453		439		-		(892	)		-
Total revenues	$	2,916,535	$	440,001	$	15,912	$	(892	)	$	3,371,556
Net income	$	270,557	$	16,182	$	12,561	$	-		$	299,300
Nine Months Ended Sept. 30, 2010
Operating revenues from external customers	$	2,761,268	$	397,831	$	15,211	$	-		$	3,174,310
Intersegment revenues		308		7,797		-		(8,105	)		-
Total revenues	$	2,761,576	$	405,628	$	15,211	$	(8,105	)	$	3,174,310
Net income	$	205,762	$	7,535	$	4,669	$	-		$	217,966

11. Comprehensive Income

The components of total comprehensive income are shown below:

	Three Months Ended Sept. 30,					Nine Months Ended Sept. 30,
(Thousands of Dollars)	2011			2010		2011			2010
Net income	$	141,902		$	109,787	$	299,300		$	217,966
Other comprehensive income (loss):
Unrealized gains (losses) — marketable securities		59			54		109			(43	)
Changes in unrecognized amounts of pension and retiree medical benefits		34			26		102			76
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges		(13,112	)		25		(13,007	)		(108	)
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(34	)		306		(95	)		866
Other comprehensive (loss) income		(13,053	)		411		(12,891	)		791
Comprehensive income	$	128,849		$	110,198	$	286,409		$	218,757

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12. 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

	Three Months Ended Sept. 30,
	2011			2010			2011			2010
							Postretirement Health
(Thousands of Dollars)	Pension Benefits						Care Benefits
Xcel Energy
Service cost	$	19,330		$	18,286		$	1,206		$	1,002
Interest cost		40,353			41,253			10,522			10,695
Expected return on plan assets		(55,400	)		(58,080	)		(7,991	)		(7,132	)
Amortization of transition obligation		-			-			3,611			3,611
Amortization of prior service cost (credit)		5,633			5,165			(1,233	)		(1,233	)
Amortization of net loss		19,627			12,078			3,324			2,910
Net periodic benefit cost		29,543			18,702			9,439			9,853
Costs not recognized and additional cost recognized due to the effects of regulation		(9,299	)		(6,630	)		972			972
Net benefit cost recognized for financial reporting	$	20,244		$	12,072		$	10,411		$	10,825
NSP-Minnesota
Net periodic benefit cost	$	11,907		$	8,377		$	2,615		$	2,660
Costs not recognized due to the effects of regulation		(8,724	)		(6,630	)		-			-
Net benefit cost recognized for financial reporting	$	3,183		$	1,747		$	2,615		$	2,660

	Nine Months Ended Sept. 30,
	2011			2010			2011			2010
							Postretirement Health
(Thousands of Dollars)	Pension Benefits						Care Benefits
Xcel Energy
Service cost	$	57,990		$	54,860		$	3,618		$	3,005
Interest cost		121,059			123,758			31,565			32,085
Expected return on plan assets		(166,200	)		(174,239	)		(23,972	)		(21,397	)
Amortization of transition obligation		-			-			10,833			10,833
Amortization of prior service cost (credit)		16,899			15,493			(3,699	)		(3,699	)
Amortization of net loss		58,883			36,236			9,971			8,732
Net periodic benefit cost		88,631			56,108			28,316			29,559
Costs not recognized and additional cost recognized due to the effects of regulation		(27,899	)		(20,270	)		2,918			2,918
Net benefit cost recognized for financial reporting	$	60,732		$	35,838		$	31,234		$	32,477
NSP-Minnesota
Net periodic benefit cost	$	35,720		$	25,131		$	7,845		$	7,982
Costs not recognized due to the effects of regulation		(26,174	)		(20,270	)		-			-
Net benefit cost recognized for financial reporting	$	9,546		$	4,861		$	7,845		$	7,982

Voluntary contributions of $134 million were made to three of Xcel Energy’s pension plans in January 2011, including $41.4 million related to NSP-Minnesota.Based on updated valuation results received in March 2011 for the New Century Energies, Inc. (NCE) Non-Bargaining Pension Plan, Xcel Energy made a required contribution of $3.3 million to the NCE Non-Bargaining Pension Plan in July 2011. Xcel Energy does not expect additionalpension contributions during 2011.

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

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

Financial Review

The following discussion and analysis by management focuses on those factors that had a material effect on NSP-Minnesota’s financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes to the consolidated financial statements. Due to the seasonality of NSP-Minnesota’s electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results.

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of NSP-Minnesota and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where NSP-Minnesota has a financial interest; customer business conditions; competitive factors, including the extent and timing of the entry of additional competition in the markets served by NSP-Minnesota and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions by regulatory bodies impacting NSP-Minnesota’s nuclear operations, including those affecting costs, operations or the approval of requests pending before the NRC; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee workforce factors; the items described under Factors Affecting Results of Operations; and the other risk factors listed from time to time by NSP-Minnesota in reports filed with the SEC, including “Risk Factors” in Item 1A of NSP-Minnesota’s Form 10-K for the year ended Dec. 31, 2010, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 2011.

Results of Operations

NSP-Minnesota’s net income was approximately $299.3 million for the nine months ended Sept. 30, 2011, compared with approximately $218.0 million for the same period in 2010. The increase is primarily due to interim rate increases, subject to refund, in Minnesota and North Dakota, and conservation improvement program incentives. These factors were partially offset by higher O&M expenses, depreciation expense and property taxes.

Electric Revenues and Margins

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

	Nine Months Ended Sept. 30,
(Millions of Dollars)	2011			2010
Electric revenues	$	2,916		$	2,761
Electric fuel and purchased power		(1,181	)		(1,183	)
Electric margin	$	1,735		$	1,578

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

Electric Revenues

(Millions of Dollars)	2011 vs. 2010
Retail rate increases (Minnesota interim, North Dakota interim)	$	78
Conservation revenue (offset by expenses)		31
Fuel and purchased power cost recovery		30
Transmission revenue		14
Interchange agreement billing with NSP-Wisconsin		14
Conservation incentive		9
Trading		(16	)
Firm wholesale		(11	)
Other, net		6
Total increase in electric revenues	$	155

Electric Margin

(Millions of Dollars)	2011 vs. 2010
Retail rate increases (Minnesota interim, North Dakota interim)	$	78
Conservation revenue (offset by expenses)		31
2010 deferred fuel adjustments		20
Retail fuel recovery timing		10
Conservation incentive		9
Interchange agreement billing with NSP-Wisconsin		6
Firm wholesale		(6	)
Other, net		9
Total increase in electric margin	$	157

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:

	Nine Months Ended Sept. 30,
(Millions of Dollars)	2011			2010
Natural gas revenues	$	440		$	398
Cost of natural gas sold and transported		(287	)		(269	)
Natural gas margin	$	153		$	129

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

Natural Gas Revenues

(Millions of Dollars)	2011 vs. 2010
Purchased natural gas adjustment clause recovery	$	18
Conservation revenue (offset by expenses)		13
Estimated impact of weather		7
Other, net		4
Total increase in natural gas revenues	$	42

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Natural Gas Margin

(Millions of Dollars)	2011 vs. 2010
Conservation revenue (offset by expenses)	$	13
Estimated impact of weather		7
Other, net		4
Total increase in natural gas margin	$	24

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses for the nine months ended Sept. 30, 2011 increased $12.7 million compared with the same period in 2010. The following summarizes the components of the changes for the nine months ended Sept. 30:

(Millions of Dollars)	2011 vs. 2010
Higher interchange costs	$	7
Higher nuclear plant operation costs		2
Higher donations		1
Other, net		3
Total increase in O&M expenses	$	13

Conservation Program Expenses — Conservation program expenses increased $45.0 million for the nine months ended Sept. 30, 2011, compared with the same period in 2010. The higher expense is attributable to an increase in the rider rates used to recover the program expenses. NSP-Minnesota has established conservation incentive programs designed to encourage its retail customers to conserve energy or change energy usage patterns in order to reduce peak demand on the gas and/or electric system. This, in turn, reduces the need for additional plant capacity, reduces emissions, serves to achieve other environmental goals as well as reduces energy costs to participating customers. NSP-Minnesota recovers conservation program expenses concurrently through riders and base rates.

Depreciation and Amortization — Depreciation and amortization expense increased by $15.1 million, or 5.0 percent, for the nine months ended Sept. 30, 2011, compared with the same period in 2010. The increase is primarily due to the Nobles wind project commencing commercial operations in late 2010 and normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased by $8.7 million, or 7.4 percent, for the nine months ended Sept. 30, 2011, compared with the same period in 2010. The increase was due to increased property and payroll taxes.

Interest Charges — Interest charges increased by $6.1 million, or 4.0 percent, for the nine months ended Sept. 30, 2011, compared with the same period in 2010. The increase is due to higher long-term debt levels to fund investments in utility operations, partially offset by lower interest rates.

Income Taxes — Income tax expense increased by $16.7 million for the nine months ended Sept. 30 2011, compared with the same period in 2010. The increase in income tax expense was primarily due to an increase in pretax income, partially offset by an increase in wind production tax credits in 2011, a decrease in state income taxes in 2011, and a write-off of tax benefits previously recorded for Medicare Part D subsidies in 2010. The effective tax rate was 34.5 percent for the first nine months of 2011, compared with 39.3 percent for the same period in 2010. The lower effective tax rate for the first nine months of 2011, as compared to 2010, was primarily due to higher forecasted wind production tax credits and decreased state income taxes in 2011.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC increased $4.2 million, or 10.4 percent for the nine months ended Sept. 30, 2011, compared with the same period in 2010. The change is primarily due to higher average construction work in process due to construction projects related to the Monticello extended power uprate, partially offset by lower AFUDC rates.

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Factors Affecting Results of Operations

Public Utility Regulation

Wind Generation — NSP-Minnesota invested approximately $500 million in wind generation through 2010. The 201 MW Nobles wind project in southwestern Minnesota began commercial operations in 2010. The portion of the costs for the Nobles wind project assigned to Minnesota electric retail customers is currently being collected through the RES rider. NSP-Minnesota has included the costs for the Nobles wind project in its current pending rate case in Minnesota and if approved, the costs will be recovered in base rates when final rates are implemented.

On April 1, 2011, NSP-Minnesota terminated its agreement with enXco for the development of the 150 MW Merricourt wind project in North Dakota. NSP-Minnesota’s decision to terminate the agreement was based in large part on the adverse impact this project could have on endangered or threatened species protected by federal law and the uncertainty in cost and timing in mitigating this impact. NSP-Minnesota also terminated the agreement due to the nonperformance by enXco of certain other conditions, including failure to obtain a Certificate of Site Compatibility, and the failure to close on the contracts by an agreed upon date of March 31, 2011. The Merricourt wind project was projected to cost approximately $400 million and was expected to reach commercial operation in 2011.

On May 5, 2011, NSP-Minnesota filed a declaratory judgment action in U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreement. On that same day, enXco also filed a separate lawsuit in the same court seeking, among other things, in excess of $240 million for an alleged breach of contract. NSP-Minnesota believes enXco’s lawsuit is without merit and filed in response a motion to dismiss. On Sept. 16, 2011, the U.S. District Court denied the motion to dismiss. The trial is set to begin in late 2012 or early 2013.

NSP-Minnesota Transmission Certificate of Need (CON) — In May 2009, the MPUC granted a CON to construct three 345 kilovolt (KV) electric transmission lines as part of the CapX2020 project. The project to build the three lines includes construction of approximately 700 miles of new facilities at a cost of approximately $1.9 billion. NSP-Minnesota and NSP-Wisconsin are responsible for approximately $1.0 billion of the total cost. The remainder of the costs will be born by other utilities in the upper Midwest. These cost estimates will be revised after the regulatory process is completed.

NSP-Minnesota and Great River Energy filed four route permit applications with the MPUC in addition to a facility permit application with the SDPUC, a certificate of corridor compatibility application with the NDPSC and a Certificate of Public Convenience and Necessity application with the Public Service Commission of Wisconsin. The MPUC has issued route permits for the Monticello, Minn. to St. Cloud, Minn. project, the Minnesota portion of the Fargo, N.D. to St. Cloud, Minn. project and the Minnesota portion of the Brookings, S.D. to Hampton, Minn. project. The SDPUC granted the facility permit for the South Dakota portion of the Brookings, S.D. project in June 2011. The remaining required permit activities are on-going in North Dakota for the Fargo project and in Wisconsin and Minnesota for the Hampton, Minn. to La Crosse, Wis. project.

Also in June 2011, the Midwest Independent Transmission System Operator, Inc (MISO) granted approval of the Brookings line as a multi value line, subject to regional cost allocation contingent on approving the portfolio of projects with which it was evaluated. The projects studied create a net benefit to the region in aggregate and the MISO expects to take up approvals for the remainder of the portfolio by the end of 2011.

Bemidji to Grand Rapids Project

In July 2009, the MPUC approved the CON application for a 230 KV CapX2020 transmission line between Bemidji, Minn. and Grand Rapids, Minn. Route permit hearings were concluded in May 2010, and a route permit was approved by the MPUC in November 2010. This line is expected to entail construction of approximately 68 miles of new facilities at a cost of $100 million. Construction related activities began in January 2011 and are expected to be completed in 2012. The estimated project cost to NSP-Minnesota is approximately $26 million.

Hiawatha Transmission Project

In November 2010, NSP-Minnesota submitted a CON application to the MPUC for two 115 KV lines in Minneapolis, Minn. An MPUC decision on the CON and route permit is expected by early 2012.

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Glencoe to Waconia Project

In November 2010, NSP-Minnesota submitted a CON to the MPUC for 115 KV transmission line upgrades to the Glencoe, Minn. to Waconia, Minn. 69 KV line. This was followed by a route permit application filed in December 2010. An MPUC decision regarding both applications is expected by the end of 2011.

Bluff Creek to Westgate Project

In April 2011, NSP-Minnesota filed a notice plan in anticipation of filing a request for a CON for the upgrade of a 69 KV line to a 115 KV in or near the cities of Chanhassen, Shorewood, Excelsior, Deephaven, Greenwood, Minnetonka, and Eden Prairie, Minn.

Black Dog Repowering CON — In March 2011, NSP-Minnesota filed a request with Minnesota regulators to approve a CON for a project to retire its last two coal-burning units (Units 3 and 4) at the Black Dog plant in Burnsville, Minn. and replace them with combined-cycle natural gas burning units. Units 1 and 2 were converted to natural gas combined-cycle operation in 2002.

The proposed Black Dog Repowering project would replace the remaining 253 MW of coal-fired generating capacity at the site with about 700 MW of natural gas-fired generation. The Black Dog proposal requires review and approval by various state agencies, including the MPCA and MPUC.

The proposed natural gas powered facility is expected to cost approximately $600 million and is proposed to come on line in 2016. The proposed in-service date is subject to potential change depending on projected load requirements.

In October 2011, NSP-Minnesota requested to suspend the CON process to reevaluate the timing of the Black Dog Repowering project as part of a comprehensive review to update the NSP-Minnesota resource plan.

Nuclear Power Operations and Waste Disposal

NSP-Minnesota owns two nuclear generating plants: the Monticello plant, which has one unit, and the Prairie Island plant, which has two units. See Note 13 of NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2010 for further discussion regarding the nuclear generating plants. Nuclear power plant operation produces gaseous, liquid and solid radioactive wastes. The discharge and handling of such wastes are controlled by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level radioactive waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in the plant.

NRC Regulation — The NRC regulates the nuclear operations of NSP-Minnesota. Decisions by the NRC can significantly impact the operations of the nuclear plants. The event at the nuclear plant in Fukushima, Japan could impact the NRC’s deliberations on NSP-Minnesota’s power uprates discussed below. This event could also result in additional regulation by the NRC, which could require additional capital expenditures or operating expenses. The NRC has created an internal task force that will develop recommendations for NRC consideration on whether it should require immediate emergency preparedness and mitigating enhancements at U.S. reactors and any changes to NRC regulations, inspection procedures, and licensing processes. On July 12, 2011, the task force released its recommendations in a written report. The report confirms the safety of U.S. nuclear energy facilities and recommends actions to enhance U.S. nuclear plant readiness to safely manage severe events. If the NRC adopts the recommendations in the report, a schedule for implementation and compliance will be established that licensees must adhere to. To better coordinate response activities, the U.S. nuclear energy industry has created a steering committee made up of representatives from major electric sector organizations to integrate and coordinate the industry’s ongoing responses. In addition, the NRC has completed inspecting licensees’ preparedness to deal with power losses or damage to large areas of a reactor site following extreme events.

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Nuclear Plant Power Uprates and Life Extension

Monticello Nuclear Plant Extended Power Uprate— In 2008, NSP-Minnesota filed for both state and federal approvals of an extended power uprate of approximately 71 MW for NSP-Minnesota’s Monticello nuclear plant.  The MPUC approved the CON for the extended power uprate in 2008.  The filing was placed on hold by the NRC staff to address concerns raised by the Advisory Committee on Reactor Safeguards related to containment pressure associated with pump performance.  NSP-Minnesota has been working with the industry and regulatory agencies to address this issue and had expected to receive a regulatory decision on the license application in 2012.  In October 2011, the Advisory Committee issued additional recommendations to suspend the use of containment accident pressure credit in all new licenses until the causes and risks of Japan’s Fukushima incident are better understood.  NSP-Minnesota is evaluating the impact of this recommendation on the timing of the license decision which will likely result in a delay of the approval.  NSP-Minnesota is considering implementing the equipment changes needed to support the Monticello life extension and power uprate projects in the planned spring 2013 refueling outage.

Prairie Island Life Extension— In June 2011, the NRC issued renewed operating licenses for Prairie Island Units 1 and 2, allowing Unit 1 to operate until 2033 and Unit 2 until 2034.

Prairie Island Nuclear Extended Power Uprate — In 2008, NSP-Minnesota filed for an extended power uprate of approximately 164 MW for Prairie Island Units 1 and 2, which the MPUC approved in 2009. Analysis of recent extended power uprate submittals to the NRC concluded that significant additional design work beyond current schedule and cost plan estimates are now being required to submit a successful application. As a result, NSP Minnesota is completing an economic and new project design analysis to determine project impacts.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of NSP-Minnesota, including enforcement of North American Electric Reliability Corporation (NERC) mandatory electric reliability standards. State and local agencies have jurisdiction over many of NSP-Minnesota’s activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2010. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

Compliance Audits and Self Reports

In November 2010, the NSP System (the electric production and transmission system of NSP-Minnesota is managed as an integrated system with that of NSP-Wisconsin, jointly referred to as the NSP System) filed a self-report with the Midwest Reliability Organization (MRO) regarding potential violations of certain NERC critical infrastructure protection standards (CIPS). Additional self-reports of potential violations of CIPS were filed in January 2011. Based on the issues identified with CIPS compliance, the NSP System submitted a mitigation plan that provides for a comprehensive review of its CIPS compliance programs. Whether and to what extent penalties may be assessed against the NSP System for the issues identified and self-reported to date is unclear.

In February and March 2011, the NSP System was subject to a comprehensive triennial audit by the MRO regarding compliance with various NERC mandatory reliability standards, including CIPS. The MRO found potential violations of seven standards; five are related to CIPS. The written MRO audit reports have been issued and referred to MRO’s enforcement function for further action. None of the potential violations are expected to result in a material penalty.

NERC Compliance Investigations

In September 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. In addition, service to approximately 790 MW of load was temporarily interrupted, primarily in Saskatchewan, Canada. In late 2010, NERC transferred responsibility for completing the compliance investigation to the MRO. The final outcome of the compliance investigation, and whether and to what extent penalties for violations may be assessed, is unknown at this time.

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In February 2010, the NERC notified NSP-Minnesota that it was commencing a non-public investigation of NSP-Minnesota maintenance practices associated with insulating oil levels in bulk electric system substations, as the result of an anonymous complaint received by the NERC. In February 2011, NERC transferred responsibility for completing the compliance investigation to the MRO. The MRO reviewed the status of insulating oil levels during the triennial compliance audit in the first quarter 2011. In July 2011, the NERC issued a preliminary findings report with three potential violations of NERC reliability standards, which NSP-Minnesota responded to in September 2011. The outcomes of the compliance investigations, and whether and to what extent the NERC or the MRO may seek to impose penalties for alleged violations, are unknown at this time.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) —In July 2011, the FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation, and development. The impacts of Order 1000 on transmission planning and cost allocation for the NSP System are not expected to be significant as they already participate in regional planning and cost allocation processes. The impacts of the new requirements related to future transmission development and ownership under Order 1000 are uncertain. Compliance filings to address these new requirements are due in October 2012 and are effective prospectively. In August 2011, motions for rehearing were filed and are pending action by the FERC.

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of Sept. 30, 2011, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

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

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

In the normal course of business, various lawsuits and claims have arisen against NSP-Minnesota. 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 for further discussion of legal proceedings, including Rate Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 and Notes 11 and 12 of NSP-Minnesota’s consolidated financial statements in its Annual Report on Form 10-K for the year ended Dec. 31, 2010 for a description of certain legal proceedings presently pending.

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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, 2010, which is incorporated herein by reference.

Operational Risks

We are subject to the risks of nuclear generation.

Our two nuclear stations, Prairie Island and Monticello, subject us to the risks of nuclear generation, which include:

· The risks associated with use of radioactive material in the production of energy, the management, handling, storage and disposal of these radioactive materials and the current lack of a long-term disposal solution for radioactive materials;

· Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; and

· Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of licensed lives.

The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised NRC safety requirements could necessitate substantial capital expenditures or a substantial increase in operating expenses at our nuclear plants. In addition, the Institute for Nuclear Power Operations reviews our nuclear operations and nuclear generation facilities. Compliance with the Institute for Nuclear Power Operations’ recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.

If an incident did occur, it could have a material effect on our results of operations or financial condition. Furthermore, the non-compliance of other nuclear facilities operators with applicable regulations or the occurrence of a serious nuclear incident at other facilities could result in increased regulation of the industry as a whole, which could then increase our compliance costs and impact the results of operations of its facilities. The recent events at the nuclear facilities in Fukushima, Japan could result in increased regulation of the nuclear generation industry as a whole, and additional requirements with respect to emergency planning and demonstrated ability to operate nuclear facilities in the event of natural disasters or other events. This increased regulation could increase our compliance costs and impact the results of operations of our nuclear facilities. Furthermore, these events could cause increased regulatory review and scrutiny by the NRC which could lead to delays in the process for obtaining required regulatory reviews and approvals.

Public Policy Risks

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

Increased public awareness and concern regarding climate change may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. Numerous states have announced or adopted programs to stabilize and reduce GHGs, and federal legislation has been introduced in both houses of Congress. Internationally, other nations have already agreed to regulate emissions of GHGs pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” by 2012. In addition, in 2009, the U.S. submitted a non-binding GHG emission reduction target of 17 percent compared to 2005 levels pursuant to the Copenhagen Accord. Such legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk as our 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.

The EPA has taken steps to regulate GHGs under the CAA. In December 2009, the EPA issued a finding that GHG emissions endanger public health and welfare, and that motor vehicle emissions contribute to the GHGs in the atmosphere. This endangerment finding created a mandatory duty for the EPA to regulate GHGs from light duty motor vehicles. In January 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to construction of new power plants or power plant modifications that increase emissions above a certain threshold. The EPA has also announced that it will propose GHG regulations applicable to emissions from existing power plants, although the EPA announced in late September that this proposed rule will be delayed.

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We are also currently a party to climate change lawsuits and may be subject to additional climate change lawsuits, including lawsuits similar to those described in Note 6, Commitments and Contingent Liabilities, in the notes to the consolidated financial statements. An adverse outcome in any of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Many of the federal and state climate change legislative proposals 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 emission allowances for their own operations. Proponents of the cap and trade policy believe it will result in the most cost effective, flexible emission reductions. There are many uncertainties, however, regarding when and in what form climate change legislation or regulation will be enacted. The impact of legislation and regulations, including a cap and trade structure, on us and our 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. While we do not have operations outside of the U.S., any international treaties or accords could have an impact to the extent they lead to future federal or state regulations. Another important factor is our ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed. We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations.

We are also subject to a significant number of proposed and potential rules that will impact our coal-fired and other generation facilities. These include, but are not limited to, rules associated with mercury, regional haze, ozone, ash management and cooling water intake systems. The costs of investment to comply with these rules could be substantial. We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.

Item 6 — EXHIBITS

* Indicates incorporation by reference

t Furnished, herewith, not filed. Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

3.01* Articles of Incorporation and Amendments of Northern Power Corp. (renamed NSP-Minnesota on Aug. 21, 2000) (Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).

3.02* By-Laws (Exhibit 3.02 to Form 8-K (file no. 001-31387) dated June 3, 2008).

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.

101t The following materials from NSP-Minnesota’s Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 2011 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Cash Flow, (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Stockholder’s Equity and Comprehensive Income, (v) Notes to Condensed Consolidated Financial Statements, and (vi) document and entity information.

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SIGNATURES

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

		Northern States Power Company (a Minnesota corporation)
Oct. 28, 2011
	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Vice President and Controller
		/s/ TERESA S. MADDEN
		Teresa S. Madden
		Senior Vice President and Chief Financial Officer

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