Northern States Power 10-Q 2006 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended Sept. 30, 2006

or

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

For the transition period from                        to

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

Registrant’s telephone number, including area code (612) 330-5500

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.  Yes ý  No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act).  o Large accelerated filer        o Accelerated filer        ý Non-accelerated filer

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

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. 30, 2006
Common Stock, $0.01 par value	1,000,000 shares

Northern States Power Co. (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
Item 2.	Management’s Discussion and Analysis
Item 4.	Controls and Procedures
	PART II - OTHER INFORMATION
Item 1.	Legal Proceedings
Item 1A.	Risk Factors
Item 6.	Exhibits

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

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PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

NSP-MINNESOTA
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(Thousands of dollars)

	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2006			2005			2006			2005
Operating revenues
Electric utility	$	1,001,789		$	898,411		$	2,454,916		$	2,258,293
Natural gas utility	74,792			73,397			528,935			500,722
Other	3,622			5,127			13,410			15,956
Total operating revenues	1,080,203			976,935			2,997,261			2,774,971
Operating expenses
Electric fuel and purchased power	454,201			398,160			1,058,897			976,036
Cost of natural gas sold and transported	50,698			49,780			419,421			389,516
Cost of sales — nonregulated and other	2,008			1,961			5,669			5,495
Other operating and maintenance expenses	208,161			205,145			673,446			663,082
Depreciation and amortization	108,686			90,194			317,885			280,418
Taxes (other than income taxes)	34,524			32,528			101,970			99,845
Total operating expenses	858,278			777,768			2,577,288			2,414,392
Operating income	221,925			199,167			419,973			360,579
Interest and other income — net (see Note 6)	4,633			436			8,340			1,923
Allowance for funds used during construction — equity	6,605			3,305			14,029			11,515
Interest charges and financing costs
Interest charges — includes other financing costs of $1,556, $1,769, $5,036 and $5,484, respectively	43,418			38,846			122,470			111,601
Allowance for funds used during construction — debt	(3,480		)	(3,512		)	(9,970		)	(9,541		)
Total interest charges and financing costs	39,938			35,334			112,500			102,060
Income before income taxes	193,225			167,574			329,842			271,957
Income taxes	62,520			51,683			110,075			84,706
Net income	$	130,705		$	115,891		$	219,767		$	187,251

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(Thousands of Dollars)

	Nine Months Ended
	Sept. 30,
	2006			2005
Operating activities
Net income	$	219,767		$	187,251
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	321,217			283,190
Nuclear fuel amortization	35,359			32,308
Deferred income taxes	(155,300		)	6,356
Amortization of investment tax credits	(3,634		)	(4,959		)
Allowance for equity funds used during construction	(14,029		)	(11,515		)
Write-down of assets	¾			2,887
Settlement of interest rate swap	16,359			¾
Unrealized gain on derivative instruments	(2,179		)	(1,113		)
Change in accounts receivable	61,426			(43,880		)
Change in accounts receivable from affiliates	37,759			(22,331		)
Change in inventories	(19,502		)	(26,392		)
Change in other current assets	103,865			8,917
Change in accounts payable	(65,301		)	18,152
Change in other current liabilities	96,967			(58,914		)
Change in other noncurrent assets	(42,913		)	(24,608		)
Change in other noncurrent liabilities	53,945			47,667
Net cash provided by operating activities	643,806			393,016
Investing activities
Utility capital/construction expenditures	(637,425		)	(470,897		)
Allowance for equity funds used during construction	14,029			11,515
Purchase of investments in external decommissioning fund	(699,593		)	(94,452		)
Proceeeds from sale of investments in external decommissioning fund	665,814			34,422
Investments in utility money pool	(1,025,900		)	¾
Repayments from utility money pool	1,015,200			¾
Investments in and advances to affiliates	59,700			7,700
Other investments	3,660			(7,322		)
Net cash used in investing activities	(604,515		)	(519,034		)
Financing activities
Short-term borrowings — net	¾			(90,000		)
Proceeds from issuance of long-term debt	393,726			250,211
Repayment of long-term debt, including reacquisition premiums	(200,078		)	(7,609		)
Borrowings under 5-year unsecured credit facility	194,000			¾
Repayments under 5-year unsecured credit facility	(444,000		)	¾
Capital contribution from parent	155,857			209,686
Dividends paid to parent	(164,572		)	(160,673		)
Net cash provided (used) by financing activities	(65,067		)	201,615
Net increase (decrease) in cash and cash equivalents	(25,776		)	75,597
Cash and cash equivalents at beginning of year	38,542			6,234
Cash and cash equivalents at end of quarter	$	12,766		$	81,831
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	125,549		$	114,252
Cash paid for income taxes (net of refunds received)	$	157,451		$	121,129
Supplemental disclosure of non-cash flow investing transactions:
Property, plant and equipment additions in accounts payable	$	31,818		$	17,446

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(Thousands of Dollars)

	Sept. 30, 2006			Dec. 31, 2005
ASSETS
Current assets:
Cash and cash equivalents	$	12,766		$	38,542
Investments in utility money pool, weighted average yield of 5.26% at Sept. 30, 2006	10,700			¾
Notes receivable from affiliates	4,300			64,000
Accounts receivable — net of allowance for bad debts: $8,865 and $10,128, respectively	337,253			398,678
Accounts receivable from affiliates	15,655			53,414
Accrued unbilled revenues	162,505			258,028
Materials and supplies inventories — at average cost	95,340			94,395
Fuel inventory — at average cost	40,044			33,609
Natural gas inventory — at average cost	96,098			83,977
Derivative instruments valuation	97,050			107,786
Prepayments and other	34,240			34,602
Total current assets	905,951			1,167,031
Property, plant and equipment, at cost:
Electric utility plant	8,193,910			8,018,167
Natural gas utility plant	849,180			829,522
Construction work in progress	824,595			496,884
Other	473,752			467,215
Total property, plant and equipment	10,341,437			9,811,788
Less accumulated depreciation	(4,657,403		)	(4,454,408		)
Nuclear fuel — net of accumulated amortization: $1,225,745 and $1,190,386, respectively	135,390			102,409
Net property, plant and equipment	5,819,424			5,459,789
Other assets:
Nuclear decommissioning fund investments	1,145,967			1,047,592
Prepaid pension asset	388,338			379,808
Regulatory assets	350,556			593,596
Derivative instruments valuation	188,360			198,044
Other investments	34,088			37,331
Other	54,620			51,589
Total other assets	2,161,929			2,307,960
Total assets	$	8,887,304		$	8,934,780
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	4,827		$	204,833
Accounts payable	370,465			379,950
Accounts payable to affiliates	39,985			60,419
Taxes accrued	231,626			123,384
Accrued interest	32,029			49,122
Dividends payable to parent	55,025			54,613
Derivative instruments valuation	49,569			93,544
Other	44,729			57,852
Total current liabilities	828,255			1,023,717
Deferred credits and other liabilities:
Deferred income taxes	619,696			821,417
Deferred investment tax credits	48,866			52,500
Asset retirement obligations	1,298,553			1,242,919
Regulatory liabilities	891,926			989,591
Derivative instruments valuation	252,901			246,951
Benefit obligations and other	169,750			149,749
Total deferred credits and other liabilities	3,281,692			3,503,127
Commitments and contingent liabilities (see Note 3)
Capitalization:
Long-term debt	2,304,760			2,155,540
Common stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares	10			10
Additional paid in capital	1,403,482			1,247,624
Retained earnings	1,059,544			1,004,762
Accumulated other comprehensive income	9,561			¾
Total common stockholder’s equity	2,472,597			2,252,396
Total liabilities and equity	$	8,887,304		$	8,934,780

See Notes to Consolidated Financial Statements

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly the financial position of NSP-Minnesota and its subsidiaries as of Sept. 30, 2006, and Dec. 31, 2005; the results of its operations for the three and nine months ended Sept. 30, 2006 and 2005; and its cash flows for the nine months ended Sept. 30, 2006 and 2005. Due to the seasonality of electric and natural gas sales of NSP-Minnesota, quarterly results are not necessarily an appropriate base from which to project annual results.

Except to the extent updated or described below, the footnotes set forth in the consolidated financial statements in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2005 appropriately represent, in all material respects, the current status of the footnotes and are incorporated herein by reference.

1.Significant Accounting Policies

Metro Emissions Reduction Project (MERP) Accounting - Allowance for funds used during construction (AFDC) is an amount capitalized as a part of construction costs representing the cost of financing the construction.  Generally these costs are recovered from customers as the related property is depreciated.  In December 2003, the Minnesota Public Utilities Commission (MPUC) voted to approve NSP-Minnesota’s MERP proposal to convert two coal-fueled electric generating plants to natural gas, and to install advanced pollution control equipment at a third coal-fired plant.  All three plants are located in the Minneapolis - St. Paul metropolitan area. These improvements are expected to significantly reduce air emissions from these facilities, while increasing the capacity at system peak by 300 MW. The projects are expected to come on line between 2007 and 2009, at a cumulative investment of approximately $1 billion.  The MPUC has approved a more current recovery of the financing costs related to the MERP.  The in-service plant costs, including the financing costs during construction, are recovered from customers through a MERP rider resulting in a lower recognition of AFDC.

FASB Interpretation No. 48 (FIN 48) — In July 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes —an interpretation of FASB Statement No. 109”.  FIN 48 prescribes a comprehensive financial statement model of how a company should recognize, measure, present, and disclose uncertain tax positions that the company has taken or expects to take in its income tax returns.  FIN 48 requires that only income tax benefits that meet the “more likely than not” recognition threshold be recognized or continue to be recognized on the effective date.  Initial derecognition amounts would be reported as a cumulative effect of a change in accounting principle.

FIN 48 is effective for fiscal years beginning after Dec. 15, 2006.  NSP-Minnesota is assessing the impact of the new guidance on all of its open tax positions.

Statement of Financial Accounting Standards No. 157 — “Fair Value Measurements” (SFAS No. 157) — In September 2006, the FASB issued SFAS No. 157, which enhances existing guidance for measuring assets and liabilities using fair value. SFAS No. 157 provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS No. 157 also emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Under SFAS No. 157, fair value measurements are disclosed by level within that hierarchy.  SFAS No. 157 is effective for financial statements issued for fiscal years beginning after Nov. 15, 2007.  NSP- Minnesota is evaluating the impact of SFAS No. 157 on its financial condition and results of operations.

Statement of Financial Accounting Standards No. 158 — “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS No. 158) — In September 2006, the FASB issued SFAS No. 158, which requires companies to fully recognize the funded status of each pension and other postretirement benefit plan as a liability or asset on their balance sheets with all unrecognized amounts to be recorded in other comprehensive income.  Although NSP-Minnesota continues to evaluate the impact of the new pronouncement, preliminary estimates indicate that assets could be decreased by approximately $27 million, other comprehensive income could be decreased by approximately $8 million and liabilities could be decreased by approximately $19 million.   NSP-Minnesota is evaluating regulatory accounting treatment, which would allow recognition of this item as a regulatory asset rather than as a charge to other comprehensive income.  These estimates reflect the expected deferral of these amounts as regulatory assets or liabilities.  The actual impact of the adoption of SFAS No. 158 could differ significantly from this estimate due to plan asset performance for the year and the discount rate in effect at the end of the year when the plans’ liabilities are measured.  The implementation of SFAS No.158 will have no impact on net income.  SFAS No. 158 is effective as of the end of the fiscal year ending after Dec. 15, 2006.

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Reclassifications — Certain items in the Consolidated Statements of Cash Flows related to nuclear decommissioning investments have been reclassified for the nine months ended Sept. 30, 2005 to conform to the 2006 gross investment activity presentation.

2.Rates and Regulation

Midwest Independent Transmission System Operator, Inc. (MISO) Operations —NSP-Minnesota and Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin), an affiliate of NSP-Minnesota, are members of the MISO. The MISO is a regional transmission organization (RTO) that provides transmission tariff administration services for electric transmission systems, including those of NSP-Minnesota and NSP-Wisconsin.  In 2002, NSP-Minnesota and NSP-Wisconsin received all required regulatory approvals to transfer functional control of their high voltage (100 kilovolts and greater) transmission systems to the MISO. The MISO exercises functional control over the operations of these facilities and the facilities of certain neighboring electric utilities. On April 1, 2005, MISO initiated a regional Day 2 wholesale energy market pursuant to its transmission and energy markets tariff (TEMT).

MISO Cost Recovery

While the Day 2 market is designed to provide efficiencies through region-wide generation dispatch and increased reliability, there are costs associated with the Day 2 market.  NSP-Minnesota has requested recovery of these costs within their respective jurisdictions as outlined below.

On Feb. 24, 2006, the MPUC ordered jurisdictional investor-owned utilities in the state, including NSP-Minnesota, to participate with the Minnesota Department of Commerce and other parties in a proceeding to evaluate suitability of recovery of some of the MISO Day 2 energy market costs in the variable fuel cost adjustment (FCA). The Minnesota utilities and other parties filed a joint report with the MPUC on June 22, 2006 recommending pass-through of MISO energy market costs in the FCA effective April 1, 2005, with the exception of two components which would be deferred and included in base retail electric rates in a future rate case upon a showing of MISO regional market benefits.  The two components are MISO Schedule 16, which recoups MISO costs for administration of financial transmission rights (FTRs); and Schedule 17, which recoups the cost of MISO’s market computer systems and staff.  The MPUC has scheduled a technical conference for Oct. 31, 2006, and a decision hearing for Nov. 9, 2006.  Final action by the MPUC in response to the recommendations in this report is anticipated later in 2006.  An adverse MPUC ruling on cost recovery of MISO Day 2 market costs could have a material financial impact on NSP-Minnesota.

In addition, on Sept. 1, 2006, NSP-Minnesota filed its annual electric automatic adjustment of charges (AAA) report to the MPUC.  In the AAA report process, the MPUC and other state agencies will review NSP-Minnesota’s recovery of fuel and purchased energy costs for the prior July to June period.  For the period from July 2005 to June 2006, total MISO Day 2 market charges incurred for collection in the FCA were $257 million for the State of Minnesota jurisdiction.  NSP-Minnesota expects the MPUC to issue its order in the 2006 AAA proceeding in 2007.

Revenue Sufficiency Guarantee Charges

On April 25, 2006, the Federal Energy Regulatory Commission (FERC) issued an order determining that MISO had incorrectly applied its energy markets tariff regarding the application of the revenue sufficiency guarantee (RSG) charge to certain transactions.  The FERC ordered MISO to resettle all affected transactions retroactive to April 1, 2005.  The RSG charges are collected from certain MISO customers and paid to others.  Based on the FERC order, NSP-Minnesota could be required to make net payments to MISO.  The FERC issued an order granting rehearing  in part on Oct. 26, 2006.  The impact of the new order on NSP-Minnesota is under review; the order is also subject to potential additional rehearing requests and/or appeals.  NSP-Minnesota reserved $5.9 million in response to the April 25, 2006 FERC order.

Ancillary Service Markets

MISO and its stakeholders are developing proposals to establish ancillary service markets within MISO’s footprint. The proposals would increase market efficiency by providing a reduced allocation of generation contingency reserves for market participants and by creating economic market opportunities to obtain alternative sources of generating reserves. The proposed implementation of these market design improvements is scheduled for phase-in over the course of 2007, subject to project actions by MISO. In July 2006, the Midwest contingency reserve sharing group agreement (CRSGA) was executed by numerous parties.   NSP-Minnesota and NSP-Wisconsin will participate through a collective of participants in the existing Mid-Continent Area Power Pool (MAPP) generation reserve sharing pool agreement, which would eventually be replaced by the MISO arrangement for contingency reserves.  MISO filed the CRSGA for FERC approval in Aug. 2006, to be effective Jan. 1, 2007.  The FERC approved the CRSGA on Oct. 24, 2006.

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In addition, MISO expects to file in late Nov. 2006 for FERC approval to establish wholesale markets for contingency reserves and regulation services to be effective in October 2007.  The ancillary services markets would be coordinated with the MISO Day 2 energy markets.  MISO’s costs to administer these markets would be collected through an increase in the Schedule 17 charge.

MISO Market Operations in Summer 2006

During July 2006, the MISO footprint experienced extremely hot weather, reaching a peak demand of more than 116,000 megawatts on July 31, 2006, after reaching a new peak of more than 113,000 megawatts on July 17, 2006.  The MISO Day 2 market generally functioned well, and no significant outages occurred, but the peak demand was approximately equal to the peak demand MISO previously predicted for 2009, and locational marginal prices for energy reflected constrained regions that limited regional efficiency during some hours.  The peak demands and regional constraints that cause congestion are expected to cause market participants and state regulatory commissions to review the need for additional generation, transmission and demand response programs.

Electric Rate Case — In November 2005, NSP-Minnesota requested an electric rate increase of $168 million or 8.05 percent. This increase was based on a requested 11 percent return on common equity, a projected common equity to total capitalization ratio of 51.7 percent and a projected electric rate base of $3.2 billion. On Dec. 15, 2005, the MPUC authorized an interim rate increase of $147 million, subject to refund, which became effective on Jan. 1, 2006. In March 2006, the MPUC approved a new depreciation order, which lowered decommissioning accruals for 2006 from anticipated levels.  Due to the seasonality of sales, the rate increase will not be recognized ratably throughout 2006.

On April 24, 2006, NSP-Minnesota reached a settlement agreement regarding the treatment of wholesale electric sales margins. The settlement is with five intervenor groups, including the Office of Attorney General and a large industrial customer group.

The settlement resolves recommendations of most parties regarding the treatment of wholesale electric sales margins. Significant components of the settlement agreement are as follows:

·No credit to base electric rates for wholesale electric sales margins;

·Wholesale electric sales margins derived from excess generation capacity will be flowed through the FCA as an offset to fuel and energy costs;

·80 percent of wholesale margins derived from the sales from NSP-Minnesota’s ancillary services obligations (e.g. spinning reserves) will be flowed through the FCA as an offset to fuel and energy costs and NSP-Minnesota will retain 20 percent; and

·25 percent of proprietary margins, sales that do not arise from the use of NSP-Minnesota generating assets, will be flowed through the FCA as an offset to fuel and energy costs, and 75 percent will be retained by NSP-Minnesota.

The settlement agreement was considered in the MPUC’s determination of NSP-Minnesota’s overall requested increase.

On Sept. 1, 2006, the MPUC issued a written order granting a electric revenue increase of approximately $131 million for 2006 based on an authorized return on equity of 10.54 percent.  The scheduled rate increase will be reduced in 2007 to $115 million to reflect the return of  Flint Hills, a large industrial customer, to the NSP-Minnesota system.  The MPUC rejected arguments by the Minnesota Office of the Attorney General regarding the recoverability of NSP-Minnesota’s income tax benefits associated with NRG. The MPUC approved the wholesale margin settlement.

On Sept. 21, 2006, NSP-Minnesota filed a petition for reconsideration of  the decision to reduce the rate increase to compensate for revenues associated with the return of Flint Hills and the recoverability of additional tree trimming expense.  Other parties filed petitions regarding income tax benefits associated with NRG and a clarification of certain order language.  The MPUC has scheduled a hearing on Nov. 2, 2006, to consider the petitions for reconsideration.

Excelsior Energy — In December 2005, Excelsior Energy Inc., an independent energy developer, filed for approval of a proposed power purchase agreement with NSP-Minnesota for its proposed integrated gas combined cycle (IGCC) plant to be located in northern Minnesota.  Excelsior Energy filed this petition pursuant to Minnesota law, which provides certain considerations for a qualifying Innovative Energy Project, subject to MPUC public interest determinations.

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The MPUC referred this matter to a contested case hearing to develop the facts and issues that must be resolved to act on Excelsior’s petition, including development of price information. The contested case proceeding is scheduled to consider a 603 megawatt unit in phase I of the proceedings, which are currently underway, and consider a second 603 megawatt unit in phase II of the proceedings, which are scheduled to begin in 2007. A report from the ALJs on phase I is expected in early 2007 and a report from the ALJs on phase II is expected in summer 2007.

On Sept. 5, 2006, NSP-Minnesota and other parties filed direct testimony in this proceeding.  No party recommended approval of Excelsior’s proposal.  NSP-Minnesota presented its assessment that the proposal is not consistent with the requirements of Minnesota law and would impose substantial risks and costs for both customers and NSP-Minnesota.  The Minnesota Department of Commerce presented testimony that the proposal did not meet a least-cost standard and that the public interest warrants consideration of other factors.  Hearings are scheduled to begin in November 2006.

Parties including Xcel Energy Industrial Intervenors and the sponsors of the Minnesota Coal Gasification Plant Informational Website  filed motions to dismiss Excelsior’s petition on the grounds that it cannot comply with statutory requirements.  Parties have the opportunity to reply to these motions.  The ALJ held a hearing on the dispositions motions on Oct. 11, 2006, but has not yet issued a decision.

NSP-Minnesota intends to request that all costs associated with the proposed power purchase agreement, if approved, will be recoverable in customer rates.

NSP 2004 Resource Plan — On Nov. 1, 2004, NSP-Minnesota filed its proposed resource plan for the period 2005 through 2019.  The proposed plan identified needed resources and proposed processes for acquiring resources to meet those needs, which included the need for base load capacity beginning 2013.  A series of comments and replies occurred on both the proposed plan and the proposed resource acquisition processes.  On July 28, 2006, the MPUC issued an order that, among other things:

·Approves NSP-Minnesota’s proposal to proceed with a request for proposal for 136 megawatts of peaking resources with an intended in service date of 2011;

·Identifies a base load resource need of 375 megawatts beginning in 2015 and requires NSP-Minnesota to file a certificate of need application for a proposed base load resource to begin the acquisition process by Nov. 1, 2006;

·Requires NSP-Minnesota to file for any mandatory MPUC review or approvals of proposed upgrades to existing base load and nuclear power plants (Sherco, Prairie Island, and Monticello) by Dec. 31, 2006;

·Approves an acquisition of 1,680 megawatts of wind generation resource over the planning period; and

·Accepts the proposed increases in demand-side management and energy-savings goals.

NSP-Minnesota requested minor clarifications to the order, specifically asking that the Nov. 1, 2006 filing requirement be clarified  to allow for a purchased power agreement and that the filing requirement for the upgrades be extended until Sept. 1, 2007 to accommodate scheduling and legislative review of the MPUC’s decision in the Monticello certificate of need proceeding, pursuant to Minnesota law.  On October 12, 2006, the Commission reheard its decision and approved minor modifications to its order that clarify these matters.

Monticello Certificate of Need — In an October 23, 2006, Certificate of Need Order, the MPUC authorized an on-site, spent nuclear fuel, storage facility at the Monticello nuclear generating plant and up to 30 dry storage containers and storage vaults that will permit the plant to operate to 2030.  By state statute, the MPUC’s order becomes effective  June 1, 2007, thus allowing the Minnesota legislature the opportunity to review the MPUC’s decision.  On May 24, 2005, Nuclear Management Company (NMC), Xcel Energy’s nuclear plant operating affiliate, submitted an application to the Nuclear Regulatory Commission (NRC) to extend the operating license for the Monticello plant from 2010 to 2030.  To date, NRC staff have prepared a safety analysis and a Monticello plant specific supplement to the federal Environmental Impact Statement (EIS) concerning nuclear plant license renewals.  The safety analysis supports license extension.  The supplementary EIS finds no significant environmental impacts associated with extended operation of the Monticello plant.  The NRC is expected to act on the operating license extension request by year end.

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3.Commitments and Contingent Liabilities

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 is pursuing, or intends to pursue, insurance claims and believes it will recover some portion of these costs through such claims. Additionally, where applicable, NSP-Minnesota is pursuing, or intends to pursue, recovery from other potentially responsible parties 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 for such unrecoverable amounts in its Consolidated Financial Statements.

Regional Haze Rules in Minnesota - The U.S. Environmental Protection Agency (EPA) requires states to develop implementation plans to comply with regional haze rules that require emission controls, known as best available retrofit technology (BART), by December 2007.  NSP-Minnesota  submitted its BART alternatives analysis for Sherco units 1 and 2 on October 26, 2006.  The expected cost associated with the range of alternatives for additional emission controls for sulfur dioxide (SO₂) and nitrogen oxide (NOx) is a capital investment of $7 million to $617 million.  NSP- Minnesota supports the alternative with the associated cost estimate of $7 million; however, NSP-Minnesota has not yet received a response from the Minnesota Pollution Control Agency (MPCA) concerning its preferred alternative.  NSP-Minnesota expects that the costs of any required capital investment will be recoverable from customers.  Controls must be installed by 2013.

Clean Air Interstate Rule —  In March 2005, the EPA issued the Clean Air Interstate Rule (CAIR), which further regulates SO₂ and NOx emissions.  Under CAIR’s cap-and-trade structure, utilities can comply through capital investments in emission controls or purchase of emission “allowances” from other utilities making reductions on their systems.  There is uncertainty concerning implementation of CAIR. States are required to develop implementation plans within 18 months of the issuance of the new rules and have a significant amount of discretion in the implementation details. Legal challenges to CAIR rules could alter their requirements and/or schedule. The uncertainty associated with the final CAIR rules makes it difficult to predict the ultimate amount and timing of capital expenditures and operating expenses.

On June 13, 2006, the MPCA issued a draft rule for implementing the CAIR in Minnesota, which further regulates SO₂ and NOx emissions.  This proposal would require more stringent emission reductions than the federal CAIR program, resulting in additional implementation costs.  A stakeholder process is ongoing, and a proposed rule is expected in November 2006.

While NSP-Minnesota expects to comply with the new rules through a combination of additional capital investments in emission controls at various facilities and purchases of emission allowances, it is continuing to review the alternatives. NSP-Minnesota believes the cost of any required capital investment or allowance purchases will be recoverable from customers.

Clean Air Mercury Rule — In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR), which regulates mercury emissions from power plants for the first time. NSP-Minnesota continues to evaluate the strategy for complying with CAMR.  Compliance may be achieved by either adding mercury controls or purchasing allowances or a combination of both.  The capital cost is estimated to be $9.0 million for the mercury control equipment.

Minnesota Mercury Legislation —  On May 2, 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 Sherburne County generating facilities.  Under the Act, NSP-Minnesota must install, maintain and operate continuous mercury emission monitoring systems or other monitoring methods approved by the MPCA at these units by July 1, 2007.  The information obtained will be used to establish a baseline from which to measure mercury emission reductions.  Mercury emission reduction plans must be filed by utilities by Dec. 31, 2007 (dry scrubbed units) and Dec. 31, 2009 (wet scrubbed units) that propose to implement technologies most likely to reduce emissions by 90 percent.  Implementation would occur by December 31, 2010 for dry scrubbed units and December 31, 2014 for wet scrubbed units. The cost of controls will be determined as part of the engineering analysis portion of the mercury reduction plans and is not currently estimable. Utilities subject to the Act may also submit plans to address non-mercury pollutants subject to federal and state statutes and regulations, which became effective after Dec. 31, 2004. Cost recovery provisions of the Act also apply to these other environmental initiatives.   On Sept. 15, 2006, NSP-Minnesota filed a request with the MPUC for deferred accounting of up to $6.3 million of certain environmental improvement costs that are expected to be recoverable under the Act.  If approved, this petition would defer recovery of these 2006 and 2007 costs until such time as the new tariff and rate rider mechanism are developed and approved by the MPUC.

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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.

Metropolitan Airports Commission vs. Northern States Power Company — On Dec. 30, 2004, the Metropolitan Airports Commission (MAC) filed a complaint in Minnesota state district court in Hennepin County asserting that NSP-Minnesota is required to relocate facilities on MAC property at the expense of NSP-Minnesota.  MAC claims that approximately $7.1 million charged by NSP-Minnesota over the past five years for relocation costs should be repaid. Both parties asserted cross motions for partial summary judgment on a separate and less significant claim concerning legal obligations associated with rent payments allegedly due and owing by NSP-Minnesota to MAC for the use of its property for a substation that serves MAC. A hearing regarding these cross motions was held in January 2006. In February 2006, the court granted MAC’s motion on this issue, finding that there was a valid lease and that the past course of action between the parties required NSP-Minnesota to continue making rent payments. NSP-Minnesota had made rent payments for 45 years. Depositions of key witnesses took place in February, March and April of 2006. The parties entered into meaningful settlement negotiations in May 2006, and in August 2006 reached an oral settlement of the dispute.  Formal written settlement documents are expected to be executed and the action formally dismissed in the near future.

Hoffman vs. Northern States Power Company — On March 15, 2006, a purported class action complaint was filed in Minnesota state district court in Hennepin County, on behalf of NSP-Minnesota’s residential customers in Minnesota, North Dakota and South Dakota for alleged breach of a contractual obligation to maintain and inspect the points of connection between NSP-Minnesota’s wires and customers’ homes within the meter box. Plaintiffs claim NSP-Minnesota’s alleged breach results in an increased risk of fire and is in violation of tariffs on file with the MPUC. Plaintiffs seek injunctive relief and damages in an amount equal to the value of inspections plaintiffs claim NSP-Minnesota was required to perform over the past six years. NSP-Minnesota has filed a motion for dismissal on the pleadings, which was heard on Aug. 16, 2006.

Comer vs. Xcel Energy Inc. et al. — On April 25, 2006, Xcel Energy received notice of a purported class action lawsuit filed in U.S. District Court for the Southern District of Mississippi.  Although NSP-Minnesota is not named as a party to this litigation, if the litigation ultimately results in an unfavorable outcome for Xcel Energy, it could have a material adverse effect on NSP-Minnesota.  The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ carbon dioxide 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.  On July 19, 2006, Xcel Energy filed a motion to dismiss the lawsuit in its entirety.

Carbon Dioxide Emissions Lawsuit — On July 21, 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 five utilities, including Xcel Energy, to force reductions in carbon dioxide (CO2) emissions.  Although NSP-Minnesota is not named as a party to this litigation, the requested relief that Xcel Energy cap and reduce its CO2 emissions could have a material adverse effect on NSP-Minnesota.  The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority.  CO2 is emitted whenever fossil fuel is combusted, such as in automobiles, industrial operations and coal- or gas-fired power plants.  The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming.  The lawsuits do not demand monetary damages.  Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions.  In October 2004, Xcel Energy and four other utility companies filed a motion to dismiss the lawsuit, contending, among other reasons, that the lawsuit is an attempt to usurp the policy-setting role of the U.S. Congress and the president.  On Sept. 19, 2005, the judge granted the defendants’ motion to dismiss on constitutional grounds.  Plaintiffs filed an appeal to the Second Circuit Court of Appeals.  Oral arguments were presented on June 7, 2006 and a decision on the appeal is pending.

AmeriPride Services vs. NSP - In August 2006, a complaint was served on NSP-Minnesota, alleging that on or about Sept. 2, 2004, fires occurred on the premises of AmeriPride, a linen and apparel service facility in Minneapolis, and that the cause of the fire was NSP-Minnesota’s failure to properly repair a primary underground cable after two prior failures in the same cable.  AmeriPride claims damages slightly in excess of $2 million, and asserts claims of negligence, gross negligence, negligent inspection and maintenance, negligent design, negligent failure to install equipment to discontinue power, negligent continuation of power, and negligent misrepresentation.  NSP-Minnesota denies these allegations and will vigorously defend against them.

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Other Contingencies

The circumstances in Notes 10, 11 and 12 to the consolidated financial statements in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2005 and Notes 2 and 3 to the consolidated financial statements in this Quarterly Report on Form 10-Q appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident and are incorporated herein by reference.

4.Long-term Debt

On May 25, 2006, NSP-Minnesota issued $400 million of 6.25 percent first mortgage bonds, series due June 1, 2036. NSP-Minnesota added the net proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of the proceeds to the repayment at maturity of $200 million aggregate principal amount of its 2.875 percent first mortgage bonds, Series due Aug. 1, 2006.  It plans to apply additional proceeds to the repayment at maturity of $2,420,000 aggregate principal amount of the Ramsey County, Minnesota and the County of Washington, Minnesota 4.10 percent Resource Recovery Refunding Revenue Bonds (Northern States Power Company Project), Collateralized Series 1999 due Dec. 1, 2006 issued for NSP-Minnesota’s benefit and secured by a series of its first mortgage bonds; and $2,365,000 aggregate principal amount of the County of Anoka, Minnesota 5.0 percent Resource Recovery Refunding Revenue Bonds (Northern States Power Company Project), Collateralized Series 1999 due Dec. 1, 2006 issued for NSP-Minnesota’s benefit and secured by a series of its first mortgage bonds.

5.Derivative Valuation and Financial Impacts

NSP-Minnesota uses a number of different derivative instruments in connection with its utility operations, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. These derivatives instruments are utilized in connection with  various commodity prices, certain energy related products, including emission allowances and renewable energy credits, and interest rates.  All derivative instruments not qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133-”Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS No. 133), are recorded at fair value. The presentation of these derivative instruments is dependent on the designation of a qualifying hedging relationship.  The adjustment to fair value of derivative instruments not designated in a qualifying hedging relationship is reflected in current earnings or as a regulatory balance.  This classification is dependent on the applicability of specific regulation. This includes certain instruments used to mitigate market risk for NSP-Minnesota and all instruments related to the commodity trading operations.  The designation of a cash flow hedge permits the classification of fair value to be recorded within Other Comprehensive Income, to the extent effective.  The designation of a fair value hedge permits a derivative instrument’s gains or losses to offset the related results of the hedged item in the Consolidated Statements of Income.

NSP-Minnesota records the fair value of its derivative instruments in its Consolidated Balance Sheets as separate line items identified as Derivative Instruments Valuation in both current and noncurrent assets and liabilities.

The fair value of all interest rate swaps is determined through counterparty valuations, internal valuations and broker quotes. There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented.

Qualifying hedging relationships are designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), or a hedge of a recognized asset, liability or firm commitment (fair value hedge).  The types of qualifying hedging transactions in which NSP-Minnesota is currently engaged in are discussed below.

Cash Flow Hedges

NSP-Minnesota enters into derivative instruments to manage variability of future cash flows from changes in commodity prices and interest rates. These derivative instruments are designated as cash flow hedges for accounting purposes, and the changes in the fair value of these instruments are recorded as a component of Other Comprehensive Income or deferred as a regulatory asset or liability.

At Sept. 30, 2006, NSP-Minnesota had various commodity-related contracts designated as cash flow hedges extending through November 2007.  The fair value of these cash flow hedges is recorded in either Other Comprehensive Income or deferred as a regulatory asset or liability. This classification is based on the regulatory recovery mechanisms in place. Amounts deferred in these accounts are recorded in earnings as the hedged purchase or sales transaction is settled. This could include the purchase or sale of energy or energy-related products, the use of natural gas to generate electric energy or gas purchased for resale. As of Sept. 30, 2006, NSP-Minnesota had no amounts in Accumulated Other Comprehensive Income related to commodity cash flow hedge contracts that are expected to be recognized in earnings during the next 12 months as the hedged transactions settle.

NSP-Minnesota enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for a specific period.  These derivative instruments are designated as cash flow hedges for accounting purposes and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. As of Sept. 30, 2006, NSP-Minnesota had net gains of $0.3 million in Accumulated Other Comprehensive Income related to interest rate cash flow hedge contracts that it expects to recognize in earnings during the next 12 months.

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Gains or losses on hedging transactions for the sales of energy or energy-related products are primarily recorded as a component of revenue, hedging transactions for fuel used in energy generation are recorded as a component of fuel costs, hedging transactions for gas purchased for resale are recorded as a component of gas costs and interest rate hedging transactions are recorded as a component of interest expense. NSP-Minnesota is allowed to recover in electric and natural gas rates the costs of certain financial instruments acquired to reduce commodity cost volatility. There was an immaterial amount of ineffectiveness in the third quarter of 2006.

The impact of the qualifying cash flow hedges on NSP-Minnesota’s Other Comprehensive Income, included as a component of stockholder’s equity, are detailed in the following table:

	Nine months ended Sept. 30,
(Millions of dollars)	2006		2005
Accumulated other comprehensive income related to cash flow hedges at Dec. 31	$	—	$	—
After-tax net unrealized gains related to derivatives accounted for as hedges	9.6		—
After-tax net realized gains (losses) on derivative transactions reclassified into earnings	—		—
Accumulated other comprehensive income related to cash flow hedges at Sept. 30	$	9.6	$	—

Fair Value Hedges

The effective portion of the change in the fair value of a derivative instrument qualifying as a fair value hedge is offset against the change in the fair value of the underlying asset, liability or firm commitment being hedged. That is, fair value hedge accounting allows the gains or losses of the derivative instrument to offset, in the same period, the gains and losses of the hedged item.

Derivatives Not Qualifying for Hedge Accounting

NSP-Minnesota has commodity trading operations that enter into derivative instruments. These derivative instruments are accounted for on a mark-to-market basis in the Consolidated Statements of Income. The results of these transactions are recorded on a net basis within Operating Revenues on the Consolidated Statements of Income.

NSP-Minnesota may also enter into certain commodity-based derivative transactions, not included in trading operations, which do not qualify for hedge accounting treatment.  These derivative instruments are accounted for on a mark-to-market basis in accordance with SFAS No. 133.

Normal Purchases or Normal Sales Contracts

NSP-Minnesota enters into contracts for the purchase and sale of various commodities for use in its business operations.  SFAS No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives.  Certain contracts that literally meet the definition of a derivative may be exempted from SFAS No. 133 as normal purchases or normal sales.  Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business.  In addition, normal purchases and normal sales contracts must have a price based on an underlying that is clearly and closely related to the asset being purchased or sold.  An underlying is a specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event, such as a scheduled payment under a contract.

NSP-Minnesota evaluates all of its contracts when such contracts are entered to determine if they are derivatives and, if so, if they qualify to meet the normal designation requirements under SFAS No. 133.  None of the contracts entered into within the commodity trading operations qualify for a normal designation.

In 2003, as a result of FASB Statement 133 Implementation Issue No. C20, NSP-Minnesota began recording several long-term power purchase 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 the first quarter of 2006, NSP-Minnesota qualified these contracts under the normal purchase exception.  Based on this qualification, the contracts will no longer be 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 balances.

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Normal purchases and normal sales contracts are accounted for as executory contracts as required under other generally accepted accounting principles.

6.Detail of Interest and Other Income — Net

Interest and other income, net of nonoperating expenses, for the three and nine months ended Sept. 30 consisted of the following:

	Three months ended Sept. 30,								Nine months ended Sept. 30,
(Thousands of dollars)	2006				2005				2006				2005
Interest income	$	4, 348			$	1,717			$	10,156			$		5,120
Equity income in unconsolidated affiliates	372				15				931				179
Other nonoperating income	1,328				496				1,474				1,090
Gain (loss) on the sale of investments	78				—				(140			)	—
Employee-related insurance policy expenses	(1,493			)	(1,792			)	(4,081			)	(4,466			)
Total interest and other income — net	$		4,633		$		436		$		8,340		$	1,923

7.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 Utility segment.

(Thousands of dollars)	Regulated  Electric Utility			Regulated  Natural Gas  Utility			All Other		Reconciling  Eliminations			Consolidated Total
Three months ended Sept. 30, 2006
Revenues from:
External customers	$	1,001,789		$	74,792		$	3,622	$	—		$	1,080,203
Internal customers	115			4,807			—		(4,922		)	—
Total revenue	$	1,001,904		$	79,599		$	3,622	$	(4,922	)	$	1,080,203
Segment net income (loss)	$	129,696		$	(6,853	)	$	7,862	$	—		$	130,705
Three months ended Sept. 30, 2005
Revenues from:
External customers	$	898,411		$	73,397		$	5,127	$	—		$	976,935
Internal customers	(4		)	8,355			—		(8,351		)	—
Total revenue	$	898,407		$	81,752		$	5,127	$	(8,351	)	$	976,935
Segment net income (loss)	$	113,381		$	(3,225	)	$	5,735	$	—		$	115,891

(Thousands of dollars)	Regulated  Electric Utility		Regulated  Natural Gas  Utility		All Other		Reconciling  Eliminations			Consolidated Total
Nine months ended Sept. 30, 2006
Revenues from:
External customers	$	2,454,916	$	528,935	$	13,410	$	—		$	2,997,261
Internal customers	321		6,359		—		(6,680		)	—
Total revenue	$	2,455,237	$	535,294	$	13,410	$	(6,680	)	$	2,997,261
Segment net income (loss)	$	203,961	$	4,133	$	11,673	$	—		$	219,767
Nine months ended Sept. 30, 2005
Revenues from:
External customers	$	2,258,293	$	500,722	$	15,956	$	—		$	2,774,971
Internal customers	171		12,862		—		(13,033		)	—
Total revenue	$	2,258,464	$	513,584	$	15,956	$	(13,033	)	$	2,774,971
Segment net income (loss)	$	161,757	$	17,304	$	8,190	$	—		$	187,251

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8.Comprehensive Income

The components of total comprehensive income are shown below:

	Three months ended Sept. 30,						Nine months ended Sept. 30,
(Millions of dollars)	2006			2005			2006			2005
Net income	$	130.7		$	115.9		$	219.8		$	187.3
Other comprehensive income (loss):
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges (see Note 5)	(0.1		)	—			9.6			—
Other comprehensive (loss) income	(0.1		)	—			9.6			—
Comprehensive income	$	130.6		$		115.9	$		229.4	$	187.3

The accumulated comprehensive income in stockholder’s equity at Sept. 30, 2006 and Dec. 31, 2005, relates to valuation adjustments on NSP-Minnesota’s derivative financial instruments and hedging activities.

9.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,
	2006			2005			2006				2005
(Thousands of dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost	$	15,406		$	15,115		$		1,659		$	1,671
Interest cost	38,854			40,246			13,234				13,765
Expected return on plan assets	(67,017		)	(70,290		)	(6,690			)	(6,425			)
Amortization of transition obligation	—			—			3,611				3,645
Amortization of prior service cost (credit)	7,424			7,509			(544			)	(545			)
Amortization of net loss	4,339			1,705			6,200				6,562
Net periodic benefit cost (credit)	(994		)	(5,715		)	17,470				18,673
Credits not recognized due to the effects of regulation	3,159			4,842			—				—
Additional cost recognized due to the effects of regulation	—			—			972				972
Net benefit cost (credit) recognized for financial reporting	$	2,165		$	(873	)	$		18,442		$	19,645
NSP-Minnesota
Net periodic benefit cost (credit)	$	(2,843	)	$	(4,590	)	$		4,289		$	4,392
Credits not recognized due to the effects of regulation	3,159			4,842			—				—
Net benefit cost recognized for financial reporting	$	316		$	252		$	4,289			$		4,392

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	Nine months ended Sept. 30,
	2006			2005			2006			2005
(Thousands of dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost	$	46,220		$	45,345		$	4,975		$	5,013
Interest cost	116,560			120,738			39,704			41,295
Expected return on plan assets	(201,049		)	(210,048		)	(20,068		)	(19,275		)
Amortization of transition obligation	—			—			10,833			10,934
Amortization of prior service cost (credit)	22,272			22,527			(1,634		)	(1,634		)
Amortization of net loss	13,015			5,115			18,598			19,685
Net periodic benefit cost (credit)	(2,982		)	(16,323		)	52,408			56,018
Credits not recognized due to the effects of regulation	9,477			14,526			—			—
Additional cost recognized due to the effects of regulation	—			—			2,918			2,918
Net benefit cost (credit) recognized for financial reporting	$	6,495		$	(1,797	)	$	55,326		$	58,936
NSP-Minnesota
Net periodic benefit cost (credit)	$	(8,530	)	$	(13,771	)	$	12,866		$	13,177
Credits not recognized due to the effects of regulation	9,477			14,526			—			—
Net benefit cost recognized for financial reporting	$	947		$	755		$	12,866		$	13,177

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

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

Forward-Looking Information

The following discussion and analysis by management focuses on those factors that had a material effect on the financial condition and results of operations of NSP-Minnesota 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 notes.

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,” “estimate,” “expect,” “objective,” “outlook,” “possible,” “potential” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to:

·Economic conditions, including their impact on capital expenditures and the ability of NSP-Minnesota to obtain financing on favorable terms, inflation rates and monetary fluctuations;

·Business conditions in the energy business;

·Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where NSP-Minnesota has a financial interest;

·Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services;

·Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the Securities and Exchange Commission, the Federal Energy Regulatory Commission and similar entities with regulatory oversight;

·Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, NSP-Minnesota, Xcel Energy or any of its other subsidiaries; or security ratings;

·Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel, nuclear fuel or natural gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; nuclear or environmental incidents; or electric transmission or natural gas pipeline constraints;

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·Employee workforce factors, including loss or retirement of key executives, collective bargaining agreements with union employees, or work stoppages;

·Increased competition in the utility industry;

·State and federal legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and natural gas markets; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

·Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;

·Nuclear regulatory policies and procedures, including operating regulations and spent nuclear fuel storage;

·Social attitudes regarding the utility and power industries;

·Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;

·Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;

·Significant slowdown in growth or decline in the U.S. economy, delay in growth or recovery of the U.S. economy or increased cost for insurance premiums, security and other items;

·Other business or investment considerations that may be disclosed from time to time in NSP-Minnesota’s SEC filings, including “Risk Factors” in Item 1A of NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2005 and Exhibit 99.01 to this report on Form 10-Q for the quarter ended Sept. 30, 2006.

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, 2005. Commodity price and interest rate risks for NSP-Minnesota are mitigated in most jurisdictions due to cost-based rate regulation. At Sept. 30, 2006, there were no material changes to the financial market risks that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2005.

NSP-Minnesota maintains trust funds, as required by the Nuclear Regulatory Commission, 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.

RESULTS OF OPERATIONS

NSP-Minnesota’s net income was approximately $219.8 million for the first nine months of 2006, compared with approximately $187.3 million for the first nine months of 2005.

Electric Utility, Short-term Wholesale and Commodity Trading Margins — Electric fuel and purchased power expense tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power.  Due to fuel cost recovery mechanisms for customers, most fluctuations in energy costs do not significantly affect electric utility margin.

NSP-Minnesota has two distinct forms of wholesale sales: short-term wholesale and commodity trading.  Short-term wholesale refers to energy related purchase and sales activity, and the use of certain financial instruments associated with the fuel required for, and energy produced from, NSP-Minnesota’s generation assets and energy and capacity purchased to serve native load.  Commodity trading is not associated with NSP-Minnesota’s generation assets or the energy or capacity purchased to serve native load.  Short-term wholesale and commodity trading activities are considered part of the electric utility segment.

Margins from commodity trading activity conducted at NSP-Minnesota are partially redistributed to Public Service Company of Colorado and Southwestern Public Service Company, both wholly owned subsidiaries of Xcel Energy, pursuant to the joint operating agreement (JOA) approved by the FERC.  Margins received pursuant to the JOA are reflected as part of Base Electric Utility Revenue.  Trading revenues are reported net of related costs in the Consolidated Statements of Income.  Commodity trading costs include purchased power, transmission, broker fees and other related costs.  Short-term wholesale and commodity trading margins reflect the estimated impact of regulatory sharing of margins, if applicable.

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The following table details base electric utility, short-term wholesale and commodity trading revenue and margin:

(Millions of dollars)	Base Electric Utility			Short-term Wholesale			Commodity Trading			Consolidated Total
Nine Months Ended Sept. 30, 2006
Electric utility revenue (excluding commodity trading)	$	2,341		$	111		$	—		$		2,452
Electric fuel and purchased power	(960		)	(99		)	—			(1,059			)
Commodity trading revenue	—			—			109			109
Commodity trading costs	—			—			(106		)	(106			)
Gross margin before operating expenses	$	1,381		$	12		$	3		$		1,396
Margin as a percentage of revenue	59.0		%	10.8		%	2.8		%	54.5			%
Nine Months Ended Sept. 30, 2005
Electric utility revenue (excluding commodity trading)	$	2,114		$	139		$	—		$	2,253
Electric fuel and purchased power	(894		)	(82		)	—			(976			)
Commodity trading revenue	—			—			125			125
Commodity trading costs	—			—			(120		)	(120			)
Gross margin before operating expenses	$	1,220		$	57		$	5		$	1,282
Margin as a percentage of revenue	57.7		%	41.0		%	4.0		%	53.9			%

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

Base Electric Revenue

(Millions of dollars)	2006 vs. 2005
Interim base rate changes	$	98
MERP rider	29
Sales growth (excluding weather impact)	24
Interchange agreement billing with NSP-Wisconsin	18
Firm wholesale	14
Fuel and purchased power cost recovery	13
Conservation and non-fuel rider revenues	9
Transmission revenue	4
Other	18
Total base electric revenue increase	$	227

Base Electric Margin

(Millions of dollars)	2006 vs. 2005
Interim base rate changes	$	98
MERP rider	29
Sales growth (excluding weather impact)	18
Interchange agreement billing with NSP-Wisconsin	16
Transmission expense classification change	(16		)
Conservation and non-fuel rider revenues	9
Firm wholesale	6
Interchange agreement billing — obligation load true-up	(5		)
Other	6
Total base electric margin increase	$	161

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On Jan. 1, 2006, an interim rate increase for NSP-Minnesota of $147 million, subject to refund, went into effect in Minnesota.  In March 2006, the MPUC approved a new depreciation order, which lowered decommissioning accruals for 2006 from anticipated levels.  Due to the seasonality of sales, the rate increase will not be recognized ratably throughout 2006.  Certain transmission expenses related to purchase power are reported as a component of base electric margin in 2006, compared with the 2005 presentation as a component of operating and maintenance expense, which served to lower electric margin by $16 million for the quarter, with no impact on operating or net income.

Short-term wholesale margins decreased approximately $47 million for the first nine months of 2006, compared with the same period in 2005.  As expected, short-term margins declined due to retail sales growth, which reduced surplus generation available for sale in the wholesale market, and decreased opportunities to sell due to the MISO centralized dispatch market.

In addition, NSP-Minnesota entered into a wholesale electric sales margin settlement agreement in the second quarter of 2006 as part of the Minnesota rate case proceeding. The agreement was approved by the MPUC in its order in the electric rate case.  The approved settlement agreement provides for a sharing of certain short-term wholesale and commodity trading margins with retail electric customers beginning Jan. 1, 2006.  The financial impact of this agreement is reflected in the financial statements as of and for the period ended Sept. 30, 2006.

Natural Gas Utility Margins — The following table details the change in natural gas revenue and margin. 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.

	Nine months ended Sept. 30,
(Millions of dollars)	2006			2005
Natural gas utility revenue	$	529		$	501
Cost of natural gas sold and transported	(419		)	(390		)
Natural gas utility margin	$	110		$	111

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

Natural Gas Revenue

(Millions of dollars)	2006 vs. 2005
Purchased gas adjustment clause recovery	$	50
Estimated impact of weather on firm sales volume	(22		)
Sales decline (excluding weather impact)	(8		)
Rate changes	6
Sales mix	5
Off-system sales	(5		)
Transportation and other	2
Total natural gas revenue increase	$	28

Natural Gas Margin

(Millions of dollars)	2006 vs. 2005
Sales decline (excluding weather impact)	$	(7	)
Base rate changes	6
Sales mix	5
Estimated impact of weather on firm sales volume	(3		)
Off-system sales	(1		)
Transportation and other	(1		)
Total natural gas margin decrease	$	(1	)

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Non-Fuel Operating Expense and Other Costs — The following summarizes the components of the changes in other utility operating and maintenance expense for the nine months ended Sept. 30:

(Millions of dollars)	2006 vs. 2005
Lower nuclear plant outage costs	$	(24	)
Higher nuclear plant operating costs	23
Transmission fees classification change	(17		)
Higher employee benefit costs, primarily performance-based	10
Higher combustion/hydro plant costs	8
Higher uncollectible receivable costs	4
Other, including conservation incentive program costs and information technology costs	6
Total other utility operating and maintenance expense increase	$	10

Depreciation and amortization expense increased by approximately $37.5 million, or 13.4 percent, for the first nine months of 2006, compared with the first nine months of 2005.  The increase was due to normal plant additions and an approved change in decommissioning accruals, which resulted in an additional depreciation expense of $15.0 million year-to-date.  In addition, regulatory amortizations were higher than 2005, due to increased renewable development fund amortization, resulting from higher eligible program funding and the implementation of the MERP amortization.

Interest charges increased by approximately $10.9 million, or 9.7%, for the first nine months of 2006 compared with the first nine months of 2005.  The increase was due to the issuance of new long term debt in January and May of 2006, partially offset by a November 2005 bond retirement.

Income tax expense increased by approximately $ 25.4 million for the first nine months of 2006 compared with the first nine months of 2005. The increase in tax expense was primarily due to an increase in pretax income.  Income tax expense was partially offset by the reversal of a $9.8 million regulatory reserve in 2006 and by recognition of research and experimentation credits and net operating loss carry back claims of $6.7 million in 2005. The effective tax rate was 33.4 percent for the first nine months of 2006, compared with 31.1 percent for the same period in 2005.  Without the additional tax benefits, the effective tax rate would have been 36.3 percent for the first nine months of 2006 and 33.6 percent for the same period in 2005.

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 Securities and Exchange Commission 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 the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of our disclosure controls and procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures are 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.

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Part II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

In the normal course of business, various lawsuits and claims have arisen against NSP-Minnesota. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters. See Notes 2 and 3 of the consolidated financial statements in this Quarterly Report on Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 of NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2005 and Note 11 of the consolidated financial statements in such Form 10-K for a description of certain legal proceedings presently pending.  Except as discussed in Notes 2 and 3 herein, there are no new significant cases to report against NSP-Minnesota, and there have been no notable changes in the previously reported proceedings.

Nuclear Waste Disposal Litigation — The federal government has the responsibility to dispose of domestic spent nuclear fuel and other high-level radioactive substances. The Nuclear Waste Policy Act (the Act) requires the Department of Energy (DOE) to implement this disposal program. This includes the siting, licensing, construction and operation of a permanent repository for domestically produced spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive substances.   The Act and contracts between DOE and domestic utilities obligated DOE to begin to dispose of these materials by Jan. 31, 1998.  The federal government has designated the site as Yucca Mountain in Nevada. The nuclear waste disposal program has resulted in extensive litigation.

On June 8, 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the United States requesting breach of contract damages, past and as projected into the future, in excess of $1 billion for the DOE’s failure to meet the 1998 deadline.  NSP-Minnesota has demanded damages consisting of the added costs of storage of spent nuclear fuel at the Prairie Island and Monticello nuclear generating plants, costs related to the Private Fuel Storage, LLC and certain costs relating to the 1994 and 2003 state legislation relating to the storage of spent nuclear fuel at Prairie Island.  On July 31, 2001, the Court granted NSP-Minnesota’s motion for partial summary judgment on liability.  A subsequent court decision determined that the utilities were precluded from making a claim for future damages, a utility could claim damages up to some point prior to the trial, and separate claims would have to be made in the future as damages accumulated.  In response to this decision, NSP-Minnesota filed an amended complaint seeking damages through Dec. 31, 2004.

NSP-Minnesota currently claims total damages in excess of $100 million through Dec. 31, 2004 (damages after 2004 will be claimed in subsequent proceedings).  A four week trial on the damages issue commenced on Oct. 24, 2006, the first two weeks of which will take place in Minneapolis, the final two weeks of which will take place in Washington, D.C.  A decision will ultimately be rendered by Senior Judge Wiese of the Court of Federal Claims.

On July 9, 2004, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision in consolidated cases challenging regulations and decisions on the federal nuclear waste program. The Court of Appeals rejected challenges by the state of Nevada and other intervenors with respect to most of the NRC’s challenged repository licensing regulations, the congressional resolution approving Yucca Mountain as the site of the permanent repository, and the DOE and presidential actions leading to the approval of the Yucca Mountain site. The Court of Appeals vacated the 10,000 year compliance period adopted by EPA regulations governing spent nuclear fuel disposal at Yucca Mountain and incorporated in the NRC regulations. Xcel Energy has not ascertained the impact of the decision on its nuclear operations and storage of spent nuclear fuel; however, the decision may result in additional delay and uncertainty around disposal of spent nuclear fuel. In July 2006 the Office of Civilian Radioactive Waste Management indicated that under the “best achievable repository construction schedule”, Yucca Mountain would be able to begin accepting spent nuclear fuel in March 2017.

NewMech vs. Northern States Power Company — On May 16, 2006, NewMech served and filed a complaint against NSP-Minnesota, Southern Minnesota Municipal Power Agency (SMMPA), and Benson Engineering in the Minnesota State District Court, Sherburne County, alleging entitlement to payment in the amount of approximately $4.2 million for unpaid costs allegedly associated with construction work done by NewMech at NSP-Minnesota and SMMPA’s jointly owned Sherco 3 generating plant in 2005.  NewMech had previously served a mechanic’s lien, and sought, through this action, foreclosure of the lien and sale of the property.  NewMech additionally sought claimed damages as a result of an alleged breach of contract by NSP-Minnesota.  NSP-Minnesota, SMMPA and Benson filed answers denying NewMech’s allegations.  Additionally, NSP-Minnesota and SMMPA counterclaimed for damages in excess of $7 million for breach of contract, delay in contract performance, misrepresentation and fraudulent inducement to enter into the contract and slander of title.  A confidential settlement of the dispute was reached on Sept. 29, 2006, and it did not have a material financial impact on NSP-Minnesota.

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Item 1A. RISK FACTORS

NSP-Minnesota’s risk factors are documented in Item 1A of Part I of its 2005 Annual Report on Form 10-K, which is incorporated herein by reference.  There have been no material changes to the risk factors.

Item 6. EXHIBITS

The following Exhibits are filed with this report:

31.01	Principal Executive Officer’s and Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on Oct. 30, 2006.

Northern States Power Co. (a Minnesota corporation)
(Registrant)

/s/ TERESA S. MADDEN

Teresa S. Madden

Vice President and Controller

/s/ BENJAMIN G.S. FOWKE III

Benjamin G.S. Fowke III

Vice President and Chief Financial Officer

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