UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2010

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. x Yes o No

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). o Yes o No

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

Large accelerated filer o		Accelerated filer o

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes x No

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

Class		Outstanding at May 3, 2010
Common Stock, $0.01 par value		1,000,000 shares

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

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PART 1. — FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands of dollars)

	Three Months Ended March 31,
	2010			2009
Operating revenues
Electric	$	850,232		$	869,082
Natural gas	272,393			329,267
Other	4,482			5,034
Total operating revenues	1,127,107			1,203,383

Operating expenses
Electric fuel and purchased power	373,080			382,146
Cost of natural gas sold and transported	204,326			261,197
Cost of sales — other	2,701			2,468
Other operating and maintenance expenses	249,012			243,096
Conservation program expenses	19,486			14,661
Depreciation and amortization	96,282			104,009
Taxes (other than income taxes)	40,220			36,822
Total operating expenses	985,107			1,044,399

Operating income	142,000			158,984

Other expense, net	(378		)	(18		)
Allowance for funds used during construction — equity	9,445			6,706

Interest charges and financing costs
Interest charges — includes other financing costs of $1,398 and $1,467, respectively	50,181			50,085
Allowance for funds used during construction — debt	(5,342		)	(4,342		)
Total interest charges and financing costs	44,839			45,743

Income before income taxes	106,228			119,929
Income taxes	42,089			43,730
Net income	$	64,139		$	76,199

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands of dollars)

	Three Months Ended March 31,
	2010			2009
Operating activities
Net income	$	64,139		$	76,199
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	97,573			106,534
Nuclear fuel amortization	25,980			19,290
Deferred income taxes	23,066			13,451
Amortization of investment tax credits	(779		)	(876		)
Allowance for equity funds used during construction	(9,445		)	(6,706		)
Net realized and unrealized hedging and derivative transactions	(5,641		)	5,507
Changes in operating assets and liabilities:
Accounts receivable	10,695			26,905
Accrued unbilled revenues	56,276			53,414
Inventories	50,030			125,739
Recoverable purchased natural gas and electric energy costs	20,270			20,444
Other current assets	(2,726		)	(7,283		)
Accounts payable	(88,089		)	(12,980		)
Net regulatory assets and liabilities	17,825			12,031
Other current liabilities	9,449			19,827
Change in other noncurrent assets	144			(21		)
Change in other noncurrent liabilities	(1,030		)	(9,146		)
Net cash provided by operating activities	267,737			442,329

Investing activities
Utility capital/construction expenditures	(288,336		)	(278,003		)
Allowance for equity funds used during construction	9,445			6,706
Purchase of investments in external decommissioning fund	(910,889		)	(396,528		)
Proceeds from sale of investments in external decommissioning fund	916,541			395,815
Investments in utility money pool arrangement	(41,500		)	—
Repayments from utility money pool arrangement	48,500			—
Advances to affiliate	(131,400		)	(21,700		)
Advances from affiliate	129,300			21,700
Other investments	1,453			(1,551		)
Net cash used in investing activities	(266,886		)	(273,561		)

Financing activities
(Repayment of) proceeds from short-term borrowings, net	—			(65,000		)
Borrowings under utility money pool arrangement	83,500			100,300
Repayments under utility money pool arrangement	(83,500		)	(163,800		)
Repayment of long-term debt, including reacquisition premiums	(85		)	(3		)
Capital contributions from parent	50,000			120,000
Dividends paid to parent	(58,415		)	(58,415		)
Net cash used in financing activities	(8,500		)	(66,918		)

Net (decrease) increase in cash and cash equivalents	(7,649		)	101,850
Cash and cash equivalents at beginning of period	46,303			12,343
Cash and cash equivalents at end of period	$	38,654		$	114,193

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(72,944	)	$	(76,753	)
Cash received for income taxes, net	4,303			24,809
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	8,698		$	9,860

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in thousands of dollars)

	March 31, 2010		Dec. 31, 2009
Assets
Current assets
Cash and cash equivalents	$	38,654	$	46,303
Notes receivable from affiliates	17,600		15,500
Investments in utility money pool arrangement	—		7,000
Accounts receivable, net	298,155		300,103
Accounts receivable from affiliates	22,498		31,245
Accrued unbilled revenues	173,062		229,338
Inventories	205,889		255,919
Recoverable purchased natural gas and electric energy costs	10,158		30,428
Derivative instruments valuation	33,262		59,482
Prepayments and other	76,051		81,688
Total current assets	875,329		1,057,006

Property, plant and equipment, net	7,122,643		6,958,656

Other assets
Nuclear decommissioning fund and other investments	1,301,643		1,264,687
Regulatory assets	768,884		797,663
Derivative instruments valuation	118,292		117,216
Other	23,079		23,581
Total other assets	2,211,898		2,203,147
Total assets	$	10,209,870	$	10,218,809

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	175,023	$	175,037
Accounts payable	324,281		407,500
Accounts payable to affiliates	53,413		83,759
Taxes accrued	167,800		125,650
Accrued interest	38,480		62,780
Dividends payable to parent	57,675		58,415
Derivative instruments valuation	21,792		24,661
Other	50,159		59,353
Total current liabilities	888,623		997,155

Deferred credits and other liabilities
Deferred income taxes	1,262,010		1,234,366
Deferred investment tax credits	36,355		37,134
Asset retirement obligations	810,367		797,476
Regulatory liabilities	453,258		469,769
Pension and employee benefit obligations	310,815		310,066
Derivative instruments valuation	211,836		209,528
Other	100,218		83,965
Total deferred credits and other liabilities	3,184,859		3,142,304

Commitments and contingent liabilities
Capitalization
Long-term debt	2,838,369		2,838,141
Common stock – authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares	10		10
Additional paid-in capital	2,078,592		2,028,593
Retained earnings	1,217,358		1,210,894
Accumulated other comprehensive income	2,059		1,712
Total common stockholder’s equity	3,298,019		3,241,209
Total liabilities and equity	$	10,209,870	$	10,218,809

See Notes to Consolidated Financial Statements

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3. Selected Balance Sheet Data

(Thousands of Dollars)	March 31, 2010			Dec. 31, 2009
Accounts receivable, net
Accounts receivable	$	318,807		$	322,778
Less allowance for bad debts	(20,652		)	(22,675		)
	$	298,155		$	300,103
Inventories
Materials and supplies	$	110,502		$	105,508
Fuel	76,797			99,705
Natural gas	18,590			50,706
	$	205,889		$	255,919
Property, plant and equipment, net
Electric plant	$	9,727,419		$	9,679,288
Natural gas plant	955,140			948,708
Common and other property	479,348			472,624
Construction work in progress	756,618			587,080
Total property, plant and equipment	11,918,525			11,687,700
Less accumulated depreciation	(5,087,762		)	(5,030,836		)
Nuclear fuel	1,753,537			1,737,469
Less accumulated amortization	(1,461,657		)	(1,435,677		)
	$	7,122,643		$	6,958,656

4. Income Taxes

Medicare Part D Subsidy Reimbursements — In March 2010, the Patient Protection and Affordable Care Act was signed into law. The law includes provisions to generate tax revenue to help offset the cost of the new legislation. One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013. Based on this provision, NSP-Minnesota is subject to additional taxes and is required to reverse previously recorded tax benefits in the period of enactment.

NSP-Minnesota expensed approximately $3.3 million of previously recognized tax benefits relating to Medicare Part D subsidies during the first quarter of 2010. NSP-Minnesota does not expect the $3.3 million of additional tax expense to recur in future periods. However, the 2010 effective tax rate will increase due to additional tax expense of approximately $0.8 million associated with current year retiree health care accruals.

Federal Audit — NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. In the first quarter of 2010, the IRS completed an examination of Xcel Energy’s federal income tax returns of tax years 2006 and 2007. The IRS did not propose any material adjustments for those tax years. The statute of limitations applicable to Xcel Energy’s 2006 federal income tax return expires on Aug. 28, 2010.

State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of March 31, 2010, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2004. In 2009, Xcel Energy received a request for information from the state of Minnesota relating to tax years 2002 through 2007 in order to determine whether to undertake an audit of those years. As of March 31, 2010, the state of Minnesota had not informed Xcel Energy of its intentions. There currently are 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.

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

(Millions of Dollars)	March 31, 2010		Dec. 31, 2009
Unrecognized tax benefit - Permanent tax positions	$	2.6	$	2.7
Unrecognized tax benefit - Temporary tax positions	10.8		9.8
Unrecognized tax benefit balance	$	13.4	$	12.5

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 were as follows:

(Millions of Dollars)	March 31, 2010			Dec. 31, 2009
Tax benefits associated with NOL and tax credit carryforward	$	(2.9	)	$	(2.8	)

The increase in the unrecognized tax benefit balance of $0.9 million from Dec. 31, 2009 to March 31, 2010 was due to the addition of similar uncertain tax positions related to ongoing activity. NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months when the IRS and state audits resume. At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.

A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits is as follows:

(Millions of Dollars)	2010			2009
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(0.3	)	$	(1.3	)
Interest expense related to unrecognized tax benefits	(0.1		)	(0.2		)
Payable for interest related to unrecognized tax benefits at March 31	$	(0.4	)	$	(1.5	)

No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2010 or Dec. 31, 2009.

5. Rate Matters

Except to the extent noted below, the circumstances set forth in Note 13 to the consolidated financial statements included in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2009 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

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

Base Rate

NSP-Minnesota Gas Rate Case — In November 2009, NSP-Minnesota filed a request with the MPUC to increase Minnesota natural gas rates by $16.2 million for 2010, which represents a 2.8 percent overall increase in customer bills. The overall request seeks an additional $3.45 million, effective Jan. 1, 2011, for recovery of pension funding costs necessary to comply with federal law. In December 2009, the MPUC voted to approve an interim rate increase of $11.1 million, subject to refund. Interim rates went into effect on Jan. 11, 2010.

(Millions of Dollars)	Request
Rate increase	$	16.2
Additional recovery of pension funding costs	3.45
Return on equity	11.0		%
Equity ratio	52.46
Gas rate base	$	441

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The procedural schedule is listed below and a decision is expected in the fall of 2010.

· Intervenor direct testimony on May 3, 2010;

· NSP-Minnesota rebuttal testimony on June 2, 2010;

· Surrebuttal testimony on June 15, 2010;

· Evidentiary hearings on June 21 through 25, 2010;

· Initial briefs on July 27, 2010;

· Reply briefs and proposed findings on Aug. 19, 2010; and

· Administrative law judge (ALJ) report on Oct. 1, 2010.

Electric, Purchased Gas and Resource Adjustment Clauses

Transmission Cost Recovery (TCR) Rider — The MPUC has approved a TCR rider, which allows annual adjustments to retail electric rates to provide recovery of incremental transmission investments between rate cases. On April 1, 2010, the MPUC approved the 2010 TCR rider resulting in approximately $10.8 million in revenue, including initial costs associated with three of the four CapX 2020 transmission projects. The MPUC did not allow 2010 recovery of $1.2 million in costs associated with the Brookings, S.D. transmission line because of uncertainty in cost allocation among utilities as the result of Midwest Independent Transmission System Operator, Inc. (MISO) tariff changes currently under development for filing with the Federal Energy Regulatory Commission (FERC) in July 2010. The MPUC also expressed a desire to limit recovery based on initial project estimates and make adjustments in a rate case after a project is placed in service. This approach to rider administration will not impact the 2010 TCR request.

Renewable Energy Standard (RES) Rider — The MPUC has approved a rider to recover the costs for utility-owned projects implemented in compliance with the Minnesota RES. On April 1, 2010, the MPUC approved the 2010 RES rider that will result in $45.6 million in revenue. As noted with the TCR rider above, the MPUC also expressed a desire to limit recovery based on initial project estimates and make adjustments in a rate case after a project is placed in service. This approach to rider administration is not expected to have a material impact in 2010.

Annual Automatic Adjustment Report for 2007/2008 — In March 2010, the MPUC issued an order accepting the 2008 electric annual automatic adjustment report. The order completes the MPUC review of NSP-Minnesota recovery of approximately $896 million of fuel and purchased energy costs for the period July 1, 2007 to June 30, 2008. The MPUC had accepted the NSP-Minnesota 2008 natural gas report in 2009.

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 13, 14 and 15 to the consolidated financial statements in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2009 appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident and are incorporated herein by reference. The following include contingencies and unresolved contingencies that are material to NSP-Minnesota’s financial position.

Commitments

Variable Interest Entities — Effective Jan. 1, 2010, NSP-Minnesota adopted new guidance on consolidation of variable interest entities contained in ASC 810 Consolidation. The guidance 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 entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary.

Purchased Power Agreements — NSP-Minnesota has entered into agreements with other utilities and energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance or during outages, and meet operating reserve obligations.

NSP-Minnesota has various pay-for-performance contracts with expiration dates through the year 2034. In general, these contracts provide for energy payments based on actual power taken under the contracts as well as capacity payments. Capacity payments are typically contingent on the independent power producing entity meeting certain contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices; however, the effects of price adjustments are mitigated through purchased energy cost recovery mechanisms.

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NSP-Minnesota is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is in the future required to be provided other than contractual payments for energy and capacity set forth in purchased power agreements.

Certain natural gas and biomass fueled purchased power agreements that either reimburse the independent power producing entities for fuel costs, or contain tolling arrangements under which NSP-Minnesota procures the fuel required to produce the energy it purchases, have been determined to be variable interest entities.

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 operations and maintenance, historical and estimated future fuel and electricity prices, and financing activities; including the maintenance of debt to equity financing ratios. 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. As of March 31, 2010 and Dec. 31, 2009, NSP-Minnesota had approximately 1,064 megawatts (MW) of capacity under long-term purchased power agreements with entities that have been determined to be variable interest entities.

Environmental Contingencies

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

Site Remediation — NSP-Minnesota must pay all or a portion of the cost to remediate sites where past activities of NSP-Minnesota or other parties have caused environmental contamination. Environmental contingencies could arise from various situations including sites of former manufactured gas plants operated by NSP-Minnesota, its predecessors or other entities; and third party sites, such as landfills, for which NSP-Minnesota is alleged to be a PRP that sent hazardous materials and wastes. At March 31, 2010, the liability for the cost of remediating these sites was estimated to be $0.3 million, of which $0.1 million was considered to be a current liability.

Third Party and Other Environmental Site Remediation

Asbestos Removal — Some of NSP-Minnesota’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. NSP-Minnesota has recorded an estimate for final removal of the asbestos as an asset retirement obligation. See additional discussion of asset retirement obligations in Note 14 of the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2009. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Other Environmental Requirements

Environmental Protection Agency (EPA) Greenhouse Gas (GHG) Endangerment Finding — On Dec. 7, 2009, in response to the U. S. Supreme Court’s decision in Massachusetts v. EPA, 549 U. S. 497 (2007), the EPA issued its “endangerment” finding that GHG emissions endanger public health and welfare and that emissions from motor vehicles contribute to the GHGs in the atmosphere. This endangerment finding creates a mandatory duty for the EPA to regulate GHGs from light duty vehicles. On April 1, 2010, the EPA issued GHG efficiency standards for light duty vehicles, which will take effect on Jan. 2, 2011. The EPA takes the position that after Jan. 2, 2011, any permit issued for major stationary sources, such as power plants, must address GHG emissions through Best Available Control Technology review and emissions limits.

Clean Air Interstate Rule (CAIR) — In March 2005, the EPA issued the CAIR to further regulate sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions. The objective of CAIR is to cap emissions of SO2 and NOx in the eastern United States, including Minnesota. In response to the decisions by the U. S. Court of Appeals for the District of Columbia, which vacated but later reinstated CAIR while the EPA develops revised regulations, the EPA has indicated that a CAIR replacement rule will be proposed in May 2010 with finalization planned for 2011.

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

On Nov. 3, 2009, the EPA published a rule staying the effectiveness of CAIR in Minnesota effective Dec. 3, 2009. Cost estimates are therefore not included at this time for NSP-Minnesota.

Clean Air Mercury Rule (CAMR) — In March 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants. In February 2008, the U. S. Court of Appeals for the District of Columbia vacated CAMR, which impacts federal CAMR requirements, but not necessarily state-only mercury legislation and rules. The EPA has agreed to finalize Maximum Achievable Control Technology emission standards for all hazardous air pollutants from electric utility steam generating units by November 2011 to replace CAMR. Xcel Energy anticipates that the EPA will require affected facilities to demonstrate compliance within 18 to 36 months thereafter.

Minnesota Mercury Legislation — In May 2006, the Minnesota legislature enacted the Mercury Emissions Reduction Act of 2006 (Act) providing a process for plans, implementation and cost recovery for utility efforts to curb mercury emissions at certain power plants. For NSP-Minnesota, the Act covers units at the A. S. King and Sherco generating facilities. NSP-Minnesota installed and is operating and maintaining continuous mercury emission monitoring systems at these generating facilities.

In November 2008, the MPUC approved and ordered 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, with installation at A. S. King scheduled for December 2010. In an order dated Nov. 4, 2009, the MPUC authorized NSP-Minnesota to collect approximately $3.5 million from customers through a mercury rider in 2010.

On Dec. 21, 2009, NSP-Minnesota filed the plans for mercury control at Sherco Units 1 and 2 with the MPUC and the Minnesota Pollution Control Agency (MPCA). Assuming these plans are approved, NSP-Minnesota expects to file for recovery of the costs to implement these plans through the mercury cost recovery rider.

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

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

On Oct. 21, 2009, the U. S. Department of Interior certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to pollution emissions from NSP-Minnesota’s Sherco Units 1 and 2. The EPA currently administers the 1980 Visibility Protection Rules for the State of Minnesota through a Federal Implementation Plan. As such, EPA Region 5 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.

The MPCA determined that this certification does not alter the proposed SIP. The SIP proposes BART controls for Sherco 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. On Dec. 15, 2009, the MPCA Citizens Board approved the SIP, which has been submitted to the EPA for approval.

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

The MPCA exercised its authority under best professional judgment to require the Black Dog Generating Station in its recently renewed wastewater discharge permit to create and submit a plan by April 30, 2010 to reduce the plant intake’s impact on aquatic wildlife. NSP-Minnesota is discussing alternatives with the local community and regulatory agencies to address this concern.

Legal Contingencies

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

Environmental Litigation

Carbon Dioxide (CO2) Emissions Lawsuit — In 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U. S. District Court in the Southern District of New York against five utilities, including Xcel Energy, the parent company of NSP-Minnesota, to force reductions in CO2 emissions. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions. On Sept. 19, 2005, the court granted a motion to dismiss on constitutional grounds. Plaintiffs filed an appeal to the U. S. Court of Appeals for the Second Circuit. On Sept. 21, 2009, the Court of Appeals issued an opinion reversing the lower court decision. A subsequent petition for rehearing and en banc review was denied. Defendants anticipate filing a petition for review with the U. S. Supreme Court on or before June 2010.

Comer vs. Xcel Energy Inc. et al. — In 2006, Xcel Energy, the parent company of NSP-Minnesota, received notice of a purported class action lawsuit filed in U. S. District Court in the Southern District of Mississippi. The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ CO2 emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.” Plaintiffs allege in support of their claim, several legal theories, including negligence and public and private nuisance and seek damages related to the loss resulting from the hurricane. Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims. In August 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds. Plaintiffs filed a notice of appeal to the U. S. Court of Appeals for the Fifth Circuit. On Oct. 16, 2009, the U. S. Court of Appeals for the Fifth Circuit reversed the district court decision, in part, concluding that the plaintiffs pleaded sufficient facts to overcome the constitutional challenges that formed the basis for dismissal by the district court. A subsequent petition by defendants, including Xcel Energy, for en banc review was granted. Oral arguments are expected to be presented to the Fifth Circuit panel on May 24, 2010.

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, the parent company of NSP-Minnesota, and 23 other utilities, 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 believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss on June 30, 2008. On Oct. 15, 2009, the U. S. District Court dismissed the lawsuit on constitutional grounds. On Nov. 5, 2009, plaintiffs filed a notice of appeal to the U. S. Court of Appeals for the Ninth Circuit.

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Employment, Tort and Commercial Litigation

Siewert vs. Xcel Energy — In 2004, plaintiffs, the owners and operators of a Minnesota dairy farm, brought an action in Minnesota state court against NSP-Minnesota alleging negligence in the handling, supplying, distributing and selling of electrical power systems; negligence in the construction and maintenance of distribution systems; and failure to warn or adequately test such systems. Plaintiffs allege decreased milk production, injury, and damage to a dairy herd as a result of stray voltage resulting from NSP-Minnesota’s distribution system. Plaintiffs claim losses of approximately $7 million. NSP-Minnesota denies all allegations. In December 2008, the Court of Appeals issued a decision ordering dismissal of Plaintiffs’ claims for injunctive relief, but otherwise rejecting NSP-Minnesota’s contentions and ordering the matter remanded for trial. The Minnesota Supreme Court subsequently granted NSP-Minnesota’s petition for further review and heard oral arguments on Dec. 2, 2009. It is uncertain when the Minnesota Supreme Court will render a decision.

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

In August 2007, NSP-Minnesota filed a second complaint against the DOE in the U. S. Court of Federal Claims (NSP II), again claiming breach of contract damages for the DOE’s continuing failure to abide by the terms of the contract. This lawsuit will claim damages for the period Jan. 1, 2005 through Dec. 31, 2008, which includes costs associated with the storage of spent nuclear fuel at Prairie Island and Monticello, as well as the costs of complying with state regulation relating to the storage of spent nuclear fuel. Per the court’s scheduling order, NSP-Minnesota’s expert report on damages was submitted on April 15, 2009, and asserts damages in excess of $250 million. In November 2009, the Court ordered the DOE to submit its expert report by May 17, 2010. Trial is expected to take place in mid to late 2010.

EnviroTech Remediation Services, Inc. vs. Brandenburg Industrial Services Co., NSP- Minnesota, et al. — In 2009, a mechanic’s lien foreclosure lawsuit was served against NSP-Minnesota by EnviroTech Remediation Services, Inc. (EnviroTech), and other defendants. EnviroTech’s claims against NSP-Minnesota arise out of mechanics’ liens recorded by EnviroTech and its subcontractors against NSP-Minnesota’s High Bridge generating plant property in St. Paul, Minnesota, in the amount of approximately $7.0 million plus attorneys’ fees and interest. EnviroTech is a subcontractor to Brandenburg Industrial Services Co. (Brandenburg), a general construction company hired by NSP-Minnesota to perform demolition services and asbestos and lead abatement work at the old High Bridge generating plant. Brandenburg subcontracted part of its asbestos and lead abatement work to EnviroTech. EnviroTech claims it and its subcontractors furnished additional work and materials during performance of the Brandenburg/EnviroTech subcontract. EnviroTech seeks additional compensation from Brandenburg and NSP-Minnesota for the claimed extra work and materials. Further, EnviroTech notified NSP-Minnesota it intends to assert an additional $3.0 million claim in the lawsuit for destruction of business against Brandenburg and NSP-Minnesota.

At a hearing in February 2010, the court stayed the lawsuit to allow EnviroTech and Brandenburg to proceed to binding arbitration, as required by the Brandenburg/EnviroTech subcontract. NSP-Minnesota is not a party to the arbitration, which is expected to occur later this year. Further, the court ordered NSP-Minnesota to participate in a mediation with EnviroTech and Brandenburg. The mediation is scheduled for June 2010. NSP-Minnesota denies liability, believes the lawsuit and claims are without merit, and will vigorously defend itself in this matter.

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7. Short-Term Borrowings and Other Financing Instruments

Commercial Paper — NSP-Minnesota had no commercial paper outstanding at March 31, 2010 and Dec. 31, 2009. At March 31, 2010 and Dec. 31, 2009, NSP-Minnesota had approval by the Board of Directors to issue up to $500 million of commercial paper.

Money Pool — Xcel Energy and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings from the utility subsidiaries between each other. The holding company 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 the holding company.

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

(Millions of Dollars)	March 31, 2010			Dec. 31, 2009
Money pool outstanding	$	—		$	7.0
Weighted average interest rate	N/A		%	0.36		%
Money pool available for borrowing	$	250		$	250

8. Derivative Instruments and 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.

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 instruments. 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.

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

At March 31, 2010, accumulated other comprehensive income (OCI) related to interest rate derivatives included $0.2 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

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

At March 31, 2010, NSP-Minnesota had vehicle fuel related contracts designated as cash flow hedges extending through December 2012. NSP-Minnesota also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in OCI or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanism. NSP-Minnesota recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three months ended March 31, 2010 and 2009.

At March 31, 2010, accumulated OCI related to commodity derivative cash flow hedges included $1.2 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

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

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The following tables detail the impact of derivative activity during the three months ended March 31, 2010 and March 31, 2009, respectively, on OCI, regulatory assets and liabilities, and income:

	Three Months Ended March 31, 2010
	Fair Value Changes Recognized					Pre-Tax Amounts Reclassified into
	During the Period in:					Income During the Period from:						Pre-Tax Gains (Losses)
	Other		Regulatory			Other			Regulatory			Recognized
	Comprehensive		Assets and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Income (Loss)		Liabilities			Income (Loss)			Liabilities			in Income
Derivatives designated as cash flow hedges
Interest rate	$	—	$	—		$	(27	)(a)	$	—		$	—
Vehicle fuel and other commodity	18		—			536		(e)	—			—
Total	$	18	$	—		$	509		$	—		$	—

Other derivative instruments
Trading commodity	$	—	$	—		$	—		$	—		$	5,630	(b)
Electric commodity	—		(17,179		)	—			(2,727		)(c)	—
Natural gas commodity	—		(7,045		)	—			586		(d)	—
Total	$	—	$	(24,224	)	$	—		$	(2,141	)	$	5,630

	Three Months Ended March 31, 2009
	Fair Value Changes Recognized						Pre-Tax Amounts Reclassified into
	During the Period in:						Income During the Period from:						Pre-Tax Gains (Losses)
	Other			Regulatory			Other			Regulatory			Recognized
	Comprehensive			Assets and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Income (Loss)			Liabilities			Income (Loss)			Liabilities			in Income
Derivatives designated as cash flow hedges
Interest rate	$	—		$	—		$	(53	)(a)	$	—		$	—
Electric commodity	—			(19,556		)	—			(3,512		)(c)	—
Natural gas commodity	—			(811		)	—			8,915		(d)	(6,950		)(d)
Vehicle fuel and other commodity	(208		)	—			1,097		(e)	—			—
Total	$	(208	)	$	(20,367	)	$	1,044		$	5,403		$	(6,950	)

Other derivative instruments
Trading commodity	$	—		$	—		$	—		$	—		$	1,984	(b)
Electric commodity	—			(1,738		)	—			321		(c)	—
Total	$	—		$	(1,738	)	$	—		$	321		$	1,984

(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 other O&M expenses.

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Recurring Fair Value Measurements

The following table presents, for each of the hierarchy levels, NSP-Minnesota’s assets and liabilities that are measured at fair value on a recurring basis at March 31, 2010:

	March 31, 2010
	Fair Value						Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (c)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	11	$	—	$	11	$	(11	)	$	—
Other derivative instruments:
Trading commodity	—		25,203		1		25,204		(16,822		)	8,382
Electric commodity	—		—		754		754		(397		)	357
Total current derivative assets	$	—	$	25,214	$	755	$	25,969	$	(17,230	)	8,739
Purchased power agreements (b)												24,523
Current derivative instruments valuation												$	33,262

Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	76	$	—	$	76	$	—		$	76
Other derivative instruments:
Trading commodity	—		19,161		6,199		25,360		(3,655		)	21,705
Total noncurrent derivative assets	$	—	$	19,237	$	6,199	$	25,436	$	(3,655	)	21,781
Purchased power agreements (b)												96,511
Noncurrent derivative instruments valuation												$	118,292

Other recurring fair value assets
Nuclear decommissioning fund (a)
Cash equivalents	$	—	$	359,612	$	—	$	359,612	$	—		$	359,612
Debt securities :
Government securities	—		99,540		—		99,540		—			99,540
U.S. corporate bonds	—		234,462		—		234,462		—			234,462
Foreign securities	—		15,030		—		15,030		—			15,030
Municipal bonds	—		30,935		—		30,935		—			30,935
Asset-backed securities	—		—		44,125		44,125		—			44,125
Mortgage-backed securities	—		—		109,044		109,044		—			109,044
Equity securities (common stock)	394,400		—		—		394,400		—			394,400
Total	$	394,400	$	739,579	$	153,169	$	1,287,148	$	—		$	1,287,148

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	March 31, 2010
	Fair Value						Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (c)			Total
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	1,319	$	—	$	1,319	$	(11	)	$	1,308
Other derivative instruments:
Trading commodity	—		21,833		—		21,833		(21,263		)	570
Electric commodity	—		275		122		397		(397		)	—
Natural gas commodity	—		5,851		—		5,851		—			5,851
Total current derivative liabilities	$	—	$	29,278	$	122	$	29,400	$	(21,671	)	7,729
Purchased power agreements (b)												14,063
Current derivative instruments valuation												$	21,792

Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	—	$	11,891	$	3,218	$	15,109	$	(3,655	)	$	11,454
Total noncurrent derivative liabilities	$	—	$	11,891	$	3,218	$	15,109	$	(3,655	)	11,454
Purchased power agreements (b)												200,382
Noncurrent derivative instruments valuation												$	211,836

(a) Reported in other investments on the consolidated balance sheet, which also includes $14.0 million of miscellaneous investments.

(b) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting contained in ASC 815 Derivatives and Hedging, NSP-Minnesota began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory 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.

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

NSP-Minnesota recognizes transfers between levels as of the beginning of each period. The following table presents the transfers that occurred between Level 2 and Level 3 during the three months ended March 31, 2010:

	From Level 3 to Level 2 (a) (b)
(Thousands of Dollars)	Trading commodity
Derivatives not designated as cash flow hedges:
Current assets	$	4,815
Noncurrent assets	9,137
Current liabilities	(2,075		)
Noncurrent liabilities	(3,909		)
Total	$	7,968

(a) The transfer of amounts from Level 3 to Level 2 is primarily due to the passing of time and resulting increased availability of observable inputs to value certain long-term derivative contracts.

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

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The following table presents, for each of the hierarchy levels, NSP-Minnesota’s assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2009:

	Dec. 31, 2009
	Fair Value						Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (c)			Total
Current derivative assets
Other derivative instruments:
Trading commodity	$	—	$	13,748	$	6,253	$	20,001	$	(11,640	)	$	8,361
Electric commodity	—		—		23,540		23,540		1,425			24,965
Natural gas commodity	—		1,580		—		1,580		54			1,634
Total current derivative assets	$	—	$	15,328	$	29,793	$	45,121	$	(10,161	)	34,960
Purchased power agreements (b)												24,522
Current derivative instruments valuation												$	59,482

Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	85	$	—	$	85	$	—		$	85
Other derivative instruments:
Trading commodity	—		7,040		11,610		18,650		(4,193		)	14,457
Natural gas commodity	—		31		—		31		1			32
Total noncurrent derivative assets	$	—	$	7,156	$	11,610	$	18,766	$	(4,192	)	14,574
Purchased power agreements (b)												102,642
Noncurrent derivative instruments valuation												$	117,216

Other recurring fair value assets
Nuclear decommissioning fund (a)
Cash equivalents	$	—	$	28,134	$	—	$	28,134	$	—		$	28,134
Debt securities :
Government securities	—		74,126		—		74,126		—			74,126
U.S. corporate bonds	—		312,844		—		312,844		—			312,844
Foreign securities	—		9,445		—		9,445		—			9,445
Municipal bonds	—		149,088		—		149,088		—			149,088
Asset-backed securities	—		—		11,918		11,918		—			11,918
Mortgage-backed securities	—		—		81,189		81,189		—			81,189
Equity securities (common stock)	581,995		—		—		581,995		—			581,995
Total	$	581,995	$	573,637	$	93,107	$	1,248,739	$	—		$	1,248,739

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	Dec. 31, 2009
	Fair Value						Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (c)			Total
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	—	$	1,905	$	—	$	1,905	$	—		$	1,905
Other derivative instruments:
Trading commodity	—		14,248		3,731		17,979		(15,503		)	2,476
Electric commodity	—		—		3,276		3,276		1,425			4,701
Natural gas commodity	—		640		—		640		54			694
Other commodity	—		—		360		360		—			360
Total current derivative liabilities	$	—	$	16,793	$	7,367	$	24,160	$	(14,024	)	10,136
Purchased power agreements (b)												14,525
Current derivative instruments valuation												$	24,661

Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	—	$	4,895	$	6,799	$	11,694	$	(4,197	)	$	7,497
Natural gas commodity	—		364		—		364		1			365
Total noncurrent derivative liabilities	$	—	$	5,259	$	6,799	$	12,058	$	(4,196	)	7,862
Purchased power agreements (b)												201,666
Noncurrent derivative instruments valuation												$	209,528

(a) Reported in other investments on the consolidated balance sheet, which also includes $17.0 million of miscellaneous investments.

The following table present the changes in Level 3 recurring fair value measurements for the three months ended March 31, 2010 and 2009:

	Three Months Ended March 31,
	2010							2009
				Nuclear Decommissioning Fund							Nuclear Decommissioning Fund
(Thousands of Dollars)	Commodity Derivatives, Net			Mortgage- Backed Securities		Asset-Backed Securities		Commodity Derivatives, Net			Mortgage- Backed Securities			Asset-Backed Securities
Balance at Jan. 1	$	27,237		$	81,189	$	11,918	$	23,247		$	98,461		$	10,962
Purchases and settlements, net	(1,283		)	25,631		32,152		(7		)	(8,598		)	3,786
Transfers out of Level 3	(7,968		)	—		—		—			—			—
Gains (losses) recognized in earnings	2,532			—		—		(2,193		)	—			—
(Losses) gains recognized as regulatory assets and liabilities	(16,904		)	2,224		55		(19,503		)	394			547
Balance at March 31	$	3,614		$	109,044	$	44,125	$	1,544		$	90,257		$	15,295

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Gains on Level 3 commodity derivatives recognized in earnings for the three months ended March 31, 2010 include $5.3 million of net unrealized gains relating to commodity derivatives held at March 31, 2010. Losses on Level 3 commodity derivatives recognized in earnings for the three months ended March 31, 2009 include $1.3 million of net unrealized gains relating to commodity derivatives held at March 31, 2009. Realized and unrealized gains and losses on commodity trading activities are included in electric revenues. Realized and unrealized gains and losses on non-trading derivative instruments are recorded in OCI or deferred as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on the commission approved regulatory recovery mechanisms. Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a component of a nuclear decommissioning regulatory asset.

9. Financial Instruments

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

	March 31, 2010				Dec. 31, 2009
	Carrying				Carrying
(Thousands of Dollars)	Amount		Fair Value		Amount		Fair Value
Nuclear decommissioning fund	$	1,287,148	$	1,287,148	$	1,248,739	$	1,248,739
Other investments	50		50		695		695
Long-term debt, including current portion	3,013,392		3,226,495		3,013,178		3,238,854

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

The fair value estimates presented are based on information available to management as of March 31, 2010 and Dec. 31, 2009. These fair value estimates have not been comprehensively revalued for purposes of these consolidated financial statements since that date, and current estimates of fair values may differ significantly.

Letters of Credit — NSP-Minnesota uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At March 31, 2010 and Dec. 31, 2009, there were $6.8 million and $6.9 million of letters of credit outstanding, respectively. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

10. Other Expense, Net

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

	Three Months Ended March 31,
(Thousands of Dollars)	2010			2009
Interest income	$	805		$	1,176
Other nonoperating income	20			13
Insurance policy expenses	(1,201		)	(1,183		)
Other nonoperating expense	(2		)	(24		)
Other expense, net	$	(378	)	$	(18	)

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11. Segment Information

NSP-Minnesota has two reportable segments: regulated electric utility and regulated natural gas utility. Commodity trading operations are not a reportable segment and are included in the regulated electric segment. All other revenues primarily include appliance repair services, nonutility real estate activities and revenues associated with processing solid waste into refuse-derived fuel.

	Regulated		Regulated		All		Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other		Eliminations			Total
Three Months Ended March 31, 2010
Operating revenues from external customers	$	850,232	$	272,393	$	4,482	$	—		$	1,127,107
Intersegment revenues	38		1,361		—		(1,399		)	—
Total revenues	$	850,270	$	273,754	$	4,482	$	(1,399	)	$	1,127,107
Net income	$	40,443	$	20,098	$	3,598	$	—		$	64,139

Three Months Ended March 31, 2009
Operating revenues from external customers	$	869,082	$	329,267	$	5,034	$	—		$	1,203,383
Intersegment revenues	130		710		—		(840		)	—
Total revenues	$	869,212	$	329,977	$	5,034	$	(840	)	$	1,203,383
Net income	$	52,883	$	21,040	$	2,276	$	—		$	76,199

12. Comprehensive Income

The components of total comprehensive income are shown below:

	Three Months Ended March 31,
(Thousands of Dollars)	2010		2009
Net income	$	64,139	$	76,199
Other comprehensive income (loss):
Unrealized gains (losses) — marketable securities	11		(95		)
Changes in unrecognized amounts of pension and retiree medical benefits	23		37
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges	11		(123		)
After-tax net realized losses on derivative transactions reclassified into earnings	302		618
Other comprehensive income	347		437
Comprehensive income	$	64,486	$	76,636

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13. Benefit Plans and Other Postretirement Benefits

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

Components of Net Periodic Benefit Cost

	Three Months Ended March 31,
	2010			2009			2010			2009
							Postretirement Health
(Thousands of Dollars)	Pension Benefits						Care Benefits
Xcel Energy Inc.
Service cost	$	17,618		$	15,986		$	1,038		$	1,276
Interest cost	40,652			41,849			10,529			12,156
Expected return on plan assets	(58,124		)	(63,360		)	(7,134		)	(5,394		)
Amortization of transition obligation	—			—			3,611			3,496
Amortization of prior service cost (credit)	5,164			6,155			(1,233		)	(652		)
Amortization of net loss	11,024			2,929			2,709			4,885
Net periodic benefit cost	16,334			3,559			9,520			15,767
Costs not recognized and additional cost recognized due to the effects of regulation	(7,326		)	(487		)	973			973
Net benefit cost recognized for financial reporting	$	9,008		$	3,072		$	10,493		$	16,740

NSP-Minnesota
Net periodic benefit cost	$	7,326		$	487		$	2,489		$	3,739
Credits not recognized due to the effects of regulation	(7,326		)	(487		)	—			—
Net benefit cost recognized for financial reporting	$	—		$	—		$	2,489		$	3,739

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

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

Forward-Looking Statements

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

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of Xcel Energy and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by NSP-Minnesota; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; environmental laws and regulations; actions of accounting regulatory bodies; the items described under Factors Affecting Results of

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Continuing Operations; and the other risk factors listed from time to time by NSP-Minnesota in reports filed with the SEC, including “Risk Factors” in Item 1A of NSP-Minnesota’s Form 10-K for the year ended Dec. 31, 2009, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended March 31, 2010.

Market Risks

NSP-Minnesota is exposed to market risks, including changes in commodity prices and interest rates, as disclosed in Item 7A, Quantitative and Qualitative Disclosures About Market Risk in its Annual Report on Form 10-K for the year ended Dec. 31, 2009. Commodity price and interest rate risks for NSP- Minnesota are mitigated in most jurisdictions due to cost-based rate regulation.

NSP-Minnesota maintains trust funds, as required by the Nuclear Regulatory Commission (NRC), to fund certain costs of nuclear decommissioning. Those investments are exposed to price fluctuations in equity markets and changes in interest rates. However, because the costs of nuclear decommissioning are recovered through NSP-Minnesota rates, fluctuations in investment fair value do not affect NSP-Minnesota’s consolidated results of operations. Distress in the financial markets may impact the fair value of the debt and equity securities in the nuclear decommissioning trust funds, and pension and postretirement health care plan trusts, as well as NSP-Minnesota’s ability to earn a return on short-term investments of excess cash. As of March 31, 2010, there have been no material changes to market risks from that set forth in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2009.

Results of Operations

NSP-Minnesota’s net income was approximately $64.1 million for the first three months of 2010, compared with approximately $76.2 million for the first three months of 2009.

Electric Revenues and Margins

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

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

	Three Months Ended March 31,
(Millions of Dollars)	2010			2009
Electric revenues	$	850		$	869
Electric fuel and purchased power	(373		)	(382		)
Electric margin	$	477		$	487

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

Electric Revenues

(Millions of Dollars)	2010 vs. 2009
NSP-Minnesota rate case provision for refund (largely offset in depreciation expense)	$	(10	)
Firm wholesale	(6		)
Estimated impact of weather	(3		)
Conservation revenue and incentive (generally offset by expenses)	9
Other, net	(9		)
Total decrease in electric revenues	$	(19	)

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Electric Margin

(Millions of Dollars)	2010 vs. 2009
NSP-Minnesota rate case provision for refund (largely offset in depreciation expense)	$	(10	)
Estimated impact of weather	(3		)
Firm wholesale	(3		)
Conservation revenue and incentive (generally offset by expenses)	9
Other, net	(3		)
Total decrease in electric margin	$	(10	)

Natural Gas Revenues and Margins

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

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

	Three Months Ended March 31,
(Millions of Dollars)	2010			2009
Natural gas revenues	$	272		$	329
Cost of natural gas sold and transported	(204		)	(261		)
Natural gas margin	$	68		$	68

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

Natural Gas Revenues

(Millions of Dollars)	2010 vs. 2009
Purchased natural gas adjustment clause recovery	$	(52	)
Estimated impact of weather	(4		)
Rate increase (Minnesota)	3
Retail sales increase (excluding weather impact)	1
Other, net	(5		)
Total decrease in natural gas revenues	$	(57	)

Natural Gas Margin

(Millions of Dollars)	2010 vs. 2009
Estimated impact of weather	$	(4	)
Rate increase (Minnesota)	3
Retail sales increase (excluding weather impact)	1
Total change in natural gas margin	$	—

Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expenses — Other operating and maintenance expenses for the first three months of 2010 increased $5.9 million, or 2.4 percent, compared with the first three months of 2009. The following summarizes the components of the changes for the three months ended March 31:

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(Millions of Dollars)	2010 vs. 2009
Higher plant generation costs	$	9
Nuclear outage costs, net of deferral	2
Higher labor costs	2
Lower employee benefit costs	(4		)
Lower uncollectible receivable costs	(2		)
Other, net	(1		)
Total increase in other operating and maintenance expenses	$	6

· Higher plant generation costs are primarily attributable to the timing of scheduled maintenance in the first quarter of 2010.

· Lower benefits costs are primarily the result of lower active and retiree health care costs and lower annual and long-term incentive costs.

Conservation Program Expenses — Conservation program expenses increased $4.8 million, or 32.9 percent, for the first three months of 2010, compared with the first three months of 2009. The increase was primarily attributable to the expansion of programs and regulatory commitments. Conservation program expenses are generally recovered in NSP-Minnesota concurrently through riders and base rates.

Depreciation and Amortization — Depreciation and amortization expense decreased by approximately $7.7 million, or 7.4 percent, for the first three months of 2010, compared with the first three months of 2009. The lower depreciation expense is primarily due to MPUC decisions that reduced depreciation and decommissioning expense in June and October 2009. These decreases were partially offset by normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased by approximately $3.4 million, or 9.2 percent, for the first three months of 2010, compared with the first three months of 2009. The increase was primarily due to increased property taxes.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC increased by approximately $3.7 million, or 33.8 percent, for the first three months of 2010 compared with the same period in 2009. NSP-Minnesota’s overall increase was primarily due to a slightly higher AFUDC equity rate.

Income Taxes — Income tax expense decreased by $1.6 million for the first three months of 2010, compared with the first three months of 2009. The decrease in income tax expense was primarily due to a decrease in pretax income, partially offset by a write-off of tax benefits previously recorded related to Medicare Part D subsidies. The effective tax rate was 39.6 percent for the first three months of 2010, compared with 36.5 percent for the same period in 2009. The higher effective tax rate for the first three months of 2010 was primarily due to a higher forecasted annual effective tax rate and the write-off of tax benefits related to Medicare Part D subsidies.

Factors Affecting Results of Continuing Operations

Public Utility Regulation

Aggregators of Retail Customers (ARCs) — In 2009, the FERC adopted rules requiring MISO to allow ARCs to offer demand response aggregation services to end-use customers in the states served by NSP-Minnesota. ARCs would operate in competition with the state-regulated retail demand response programs offered by NSP-Minnesota. The MISO ARC tariff provisions are effective in June 2010. The MPUC has opened an investigation regarding possible operation of ARCs in Minnesota. NSP-Minnesota requested the MPUC to prohibit ARCs in its response to an MPUC notice seeking comments. NSP-Minnesota also filed requests with the North Dakota Public Service Commission (NDPSC) and South Dakota Public Utilities Commission (SDPUC) in March 2010 asking the regulatory agencies to prohibit operations of ARCs in their respective states, and to take action prior to June 2010. The investigation and requests are pending MPUC, NDPSC and SDPUC action.

Nuclear Power Operations and Waste Disposal — NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant, which has two units. See additional discussion regarding the nuclear generating plants at Note 15 to the Xcel Energy Annual Report on Form 10-K for the year ended Dec. 31, 2009.

High-Level Radioactive Waste Disposal — The federal government has the responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. In

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2002, the U. S. Congress designated Yucca Mountain, Nevada as the first deep geologic repository over the objections of the Governor of Nevada. In 2008, the DOE submitted an application to construct a deep geologic repository at Yucca Mountain to the Nuclear Regulatory Commission (NRC). In 2010, the DOE announced its intention to stop the Yucca Mountain project and requested the NRC to approve the withdrawal of the application. In parallel with the action to stop the Yucca Mountain project, the Secretary of Energy has convened a Blue Ribbon Commission to recommend alternatives to Yucca Mountain for disposing of used nuclear fuel. The final report containing recommendations from the Blue Ribbon Commission is expected in early 2012. A number of parties have challenged the DOE’s authority to stop the Yucca Mountain project and to withdraw the application from the NRC. The utility industry, including Xcel Energy, is represented in the challenges by the Nuclear Energy Institute. In light of the DOE’s plan to stop the Yucca Mountain project and to withdraw its application from the NRC, Xcel Energy in a separate action has requested the Secretary of Energy to set the fee collection rate for the Nuclear Waste Fund to zero until a definitive program is in place. To date, the DOE has not accepted any of NSP-Minnesota’s spent nuclear fuel. NSP-Minnesota has on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. As of March 31, 2010, there were 26 casks loaded and stored at the Prairie Island plant and 10 casks loaded and stored at the Monticello plant. See Note 6 to the consolidated financial statements for a discussion of the legal proceedings against the DOE related to the nuclear waste disposal matter.

Nuclear Plant Power Uprates and Life Extension — In April 2008, NSP-Minnesota filed an application with the NRC to renew the operating license of its two nuclear reactors at Prairie Island for an additional 20 years, until 2033 and 2034, respectively. The Prairie Island Indian Community (PIIC) filed contentions in the NRC’s license renewal proceeding in August 2008, which was referred to an Atomic Safety and Licensing Board (ASLB) for review. The ASLB granted the PIIC hearing request and has admitted seven of the 11 contentions filed. To date, all seven contentions that were originally admitted have been resolved and removed from the ASLB docket. Subsequent to the NRC issuance of the final Safety Evaluation Report and the draft supplemental environmental impact statement, the PIIC filed four additional contentions. The ASLB has admitted one of the contentions and has issued a decision denying the other three. NSP-Minnesota is challenging the admitted contention with the ASLB and has filed an interlocutory appeal with the NRC. If the contention is not resolved, the resulting adjudicatory process is expected to add approximately eight months onto the NRC’s standard 22 month review schedule, resulting in a decision on the Prairie Island license renewal in late 2010.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of Xcel Energy’s utility subsidiaries, including enforcement of North American Electric Reliability Corporation (NERC) mandatory electric reliability standards. State and local agencies have jurisdiction over many of Xcel Energy’s utility activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the NSP-Minnesota Annual Report on Form 10-K for the year ended Dec. 31, 2009. In addition to the matters discussed below, see Note 5 to the consolidated financial statements for a discussion of other regulatory matters.

FERC Penalty Guideline Policy Statement — On March 18, 2010, the FERC issued a Penalty Guideline Policy Statement based on the U. S. Federal Sentencing Guidelines. The penalty guidelines propose substantial financial penalties for violations of NERC reliability standards and other FERC rules. On April 15, 2010, the FERC issued an order suspending the policy statement and requested written comments within 60 days.

Electric Reliability Standards Compliance

Compliance Audits

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

In March 2010, the MRO conducted a compliance spot check to evaluate compliance with the NERC Critical Energy Infrastructure (CIP) standards, which were effective July 1, 2008. The preliminary report found that the Xcel Energy utility subsidiaries may not be in compliance with several of the CIP standards. Xcel Energy will respond to the report indicating where it disagrees with the conclusions. To what extent NERC may seek to impose penalties for potential violations is unknown at this time.

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NERC Compliance Investigations

On Sept. 18, 2007, portions of the NSP System and transmission systems west and north of the NSP System briefly islanded from the rest of the Eastern Interconnection, as a result of a series of transmission line outages. In addition, service to approximately 790 MW of load was temporarily interrupted, primarily in Saskatchewan, Canada. The initial transmission line outages occurred on the NSP System. In March 2008, NSP-Minnesota received notice that the MRO was commencing a compliance investigation of the September 2007 event. Because the event affected more than one region, the NERC took over the investigation. In January 2010, the NERC issued a preliminary report alleging the NSP System violated certain NERC reliability standards. The report represents the preliminary conclusions of the NERC and is subject to additional procedures at NERC, and ultimately FERC review. Xcel Energy disagrees with the many aspects of the preliminary report and filed its response with NERC in February 2010. The final outcome of the NERC compliance investigation, and whether and to what extent penalties for violations may be assessed, is unknown at this time.

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. NSP-Minnesota is fully cooperating with the investigation. The final outcome of the NERC compliance investigation, and whether and to what extent NERC may seek to impose penalties for violations, is unknown at this time.

MISO Generation Interconnection Cost Allocation Tariff — In October 2009, the FERC approved a proposal by MISO and its transmission owners, including NSP-Minnesota and NSP-Wisconsin, to change the cost allocation procedures in the MISO tariff associated with interconnection of new generation. The changes approved require the interconnecting generator to fund 90 percent of the costs on an interim basis until MISO and its stakeholders develop a replacement tariff to be filed with FERC in July 2010. While it remains unclear what the cost allocation provisions of the replacement tariff will be, the replacement tariff may significantly impact how new transmission investment in the MISO is funded.

MISO vs. PJM Interconnection, L.L.C. (PJM) Complaint Proceedings — In March 2010, MISO filed two complaints against PJM at the FERC alleging that PJM violated generation redispatch requirements under the Joint Operating Agreement between the two RTOs, and alleging that incorrect modeling of certain generators by PJM resulted in underpayments by PJM of up to $130 million to generators in MISO (including the NSP System) for redispatch provided from 2002 to 2009. MISO asked the FERC to direct PJM to pay the underpaid amount, plus interest. Xcel Energy intervened in the complaint proceedings in support of MISO. If the FERC directs PJM to make payments to MISO, the NSP System would receive a portion of the payments to MISO. The outcome of the complaint proceedings is uncertain.

Item 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of March 31, 2010, 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 in this Quarterly Report on Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference.

PART I — FINANCIAL INFORMATION

Item l.	Financial Statements (Unaudited)	3
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 4.	Controls and Procedures	29

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	29
Item 1A.	Risk Factors	30
Item 6.	Exhibits	30

SIGNATURES		31

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

(Amounts in Thousands) (a)(b)	March 31, 2010	Dec. 31, 2009
Megawatt hours (MWh) of electricity	22,426	34,374
MMBtu of natural gas	3,775	9,777
Gallons of vehicle fuel	1,571	2,021

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.

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

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