Northern States Power 10-Q 2005 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, 2005

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: 001-03140

Northern States Power Company

(Exact name of registrant as specified in its charter)

Wisconsin	39-0508315
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1414 W. Hamilton Avenue, Eau Claire, Wisconsin	54701
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code (715) 839-2625

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.  ý Yes   o No

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  o Yes   ý 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 October 27, 2005
Common Stock, $100 par value	933,000 shares

Northern States Power Co. (a Wisconsin 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 6.	Exhibits

This Form 10-Q is filed by Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin). NSP-Wisconsin 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 1. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(Thousands of Dollars)

	Three Months Ended September 30,							Nine Months Ended September 30,
	2005				2004			2005			2004
Operating revenues:
Electric utility	$	138,692			$	122,642		$	391,533		$		354,925
Natural gas utility	11,457				12,691			93,771			88,337
Other	172				162			515			479
Total operating revenues	150,321				135,495			485,819			443,741
Operating expenses:
Electric fuel and purchased power	83,009				48,706			226,770			157,842
Cost of natural gas sold and transported	7,681				8,673			71,920			66,845
Other operating and maintenance expenses	30,185				28,475			92,376			86,799
Depreciation and amortization	12,913				11,718			38,213			34,651
Taxes (other than income taxes)	4,229				4,158			12,688			12,635
Total operating expenses	138,017				101,730			441,967			358,772
Operating income	12,304				33,765			43,852			84,969
Other income:
Interest and other income, net of nonoperating expenses (see Note 7)	(136			)	64			3			209
Allowance for funds used during construction—equity	200				56			421			1,156
Total other income	64				120			424			1,365
Interest charges and financing costs:
Interest charges—net of amounts capitalized; includes other financing costs of $308, $308, $913 and $916, respectively	6,011				5,415			17,196			16,225
Allowance for funds used during construction—debt	(94			)	(185		)	(27		)	(585			)
Total interest charges and financing costs	5,917				5,230			17,169			15,640
Income before income taxes	6,451				28,655			27,107			70,694
Income tax	2,307				11,003			10,160			27,418
Net income	$		4,144		$	17,652		$	16,947		$	43,276

See Notes to Consolidated Financial Statements

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NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(Thousands of Dollars)

	Nine Months Ended September 30,
	2005			2004
Operating activities:
Net income	$	16,947		$	43,276
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	39,253			36,098
Deferred income taxes	2,761			5,479
Amortization of investment tax credits	(589		)	(591		)
Allowance for equity funds used during construction	(421		)	(1,156		)
Undistributed equity in earnings of unconsolidated affiliates	—			(21		)
Change in accounts receivable	2,613			(1,101		)
Change in inventories	(7,508		)	(3,933		)
Change in other current assets	10,509			11,645
Change in accounts payable	4,926			(12,047		)
Change in other current liabilities	762			11,694
Change in other assets	(9,217		)	(4,860		)
Change in other liabilities	2,806			1,941
Net cash provided by operating activities	62,842			86,424
Investing activities:
Capital/construction expenditures	(40,305		)	(36,696		)
Allowance for equity funds used during construction	421			1,156
Other investments—net	429			(423		)
Net cash used in investing activities	(39,455		)	(35,963		)
Financing activities:
Short-term borrowings from affiliate—net	(7,700		)	(13,980		)
Capital contributions from parent	19,185			687
Dividends paid to parent	(34,987		)	(37,207		)
Net cash used in financing activities	(23,502		)	(50,500		)
Net decrease in cash and cash equivalents	(115		)	(39		)
Net increase in cash and cash equivalents—consolidation of subsidiaries	510			—
Net increase in cash and cash equivalents—adoption of FIN No. 46	—			119
Cash and cash equivalents at beginning of period	231			137
Cash and cash equivalents at end of period	$	626		$	217
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	10,972		$	9,703
Cash paid for income taxes (net of refunds received)	$	14,366		$	13,384

See Notes to Consolidated Financial Statements

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NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)

	September 30, 2005				Dec. 31, 2004
ASSETS
Current assets:
Cash and cash equivalents	$		626		$	231
Accounts receivable—net of allowance for bad debts: $1,292 and $1,258, respectively	49,352				51,380
Accounts receivable from affiliates	585				1,154
Accrued unbilled revenues	20,591				27,665
Materials and supplies inventories—at average cost	4,850				4,709
Fuel inventory—at average cost	8,664				6,295
Natural gas inventory—at average cost	14,245				9,246
Current deferred income taxes	5,348				2,678
Prepaid taxes	10,206				13,471
Derivative instruments valuation—at market	15,688				1,405
Prepayments and other	1,324				3,029
Total current assets	131,479				121,263
Property, plant and equipment, at cost:
Electric utility plant	1,259,550				1,232,525
Natural gas utility plant	150,831				146,749
Common and other plant	113,472				96,346
Construction work in progress	8,309				20,153
Total property, plant and equipment	1,532,162				1,495,773
Less accumulated depreciation	(605,004			)	(575,099		)
Net property, plant and equipment	927,158				920,674
Other assets:
Other investments	6,246				7,800
Regulatory assets	57,344				50,760
Prepaid pension asset	54,143				52,272
Other	7,370				7,660
Total other assets	125,103				118,492
Total assets	$	1,183,740			$	1,160,429
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	34			$	34
Notes payable to affiliate	24,500				32,200
Accounts payable	21,357				26,993
Accounts payable to affiliates	20,131				9,568
Accrued interest	9,113				4,265
Accrued payroll and benefits	4,836				5,318
Dividends payable to parent	10,695				11,961
Derivative instruments valuation—at market	—				1,060
Other	7,099				9,640
Total current liabilities	97,765				101,039
Deferred credits and other liabilities:
Deferred income taxes	172,471				166,765
Deferred investment tax credits	12,647				13,237
Regulatory liabilities	107,465				91,403
Customer advances for construction	16,650				16,912
Benefit obligations and other	25,877				22,952
Total deferred credits and other liabilities	335,110				311,269
Minority interest in subsidiaries	379				100
Long-term debt	315,397				315,398
Common stock—authorized 1,000,000 shares of $100 par value; outstanding 933,000 shares	93,300				93,300
Premium on common stock	84,461				65,277
Retained earnings	258,317				275,092
Accumulated other comprehensive loss	(989			)	(1,046		)
Total common stockholder’s equity	435,089				432,623
Commitments and contingent liabilities (see Note 3)
Total liabilities and equity	$	1,183,740			$	1,160,429

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-Wisconsin and its subsidiaries as of September 30, 2005, and Dec. 31, 2004; the results of operations for the three and nine months ended September 30, 2005 and 2004; and its cash flows for the nine months ended September 30, 2005 and 2004. Due to the seasonality of electric and natural gas sales of NSP-Wisconsin, quarterly results are not necessarily an appropriate base from which to project annual results.

The significant accounting policies followed by NSP-Wisconsin are set forth in Note 1 to its consolidated financial statements in its Annual Report on Form 10-K for the year ended Dec. 31, 2004. The following notes should be read in conjunction with such policies and other disclosures in the Annual Report on Form 10-K.

1.  Significant Accounting Policies

FASB Interpretation No. 47 (FIN No. 47)—In April 2005, the Financial Accounting Standards Board (FASB) issued FIN No. 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations pursuant to Statement of Financial Accounting Standard (SFAS) No. 143—“Accounting for Asset Retirement Obligations”.  The interpretation requires that a liability be recorded for the fair value of an asset retirement obligation, if the fair value is estimable, even when the obligation is dependent on a future event.  FIN No. 47 further clarified that uncertainty surrounding the timing and method of settlement of the obligation should be factored into the measurement of the conditional asset retirement obligation rather than affect whether a liability should be recognized.  Implementation is required to be effective no later than the end of fiscal years ending after Dec. 15, 2005.  Additionally, FIN No. 47 will permit but not require restatement of interim financial information during any period of adoption.  Both recognition of a cumulative change in accounting and disclosure of the liability on a pro forma basis are required for transition purposes.  NSP-Wisconsin is evaluating the impact of FIN No. 47; however, it is not expected to have a material impact on results of operations or financial position due to the expected recovery of asset retirement costs in customer rates.

Reclassifications—Certain items in the statement of income for the three and nine months ended September 30, 2004 have been reclassified to conform to the 2005 presentation.  These reclassifications had no effect on net income.

2.  Regulation

Federal Regulation

Energy Legislation—On Aug. 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (Energy Act), significantly changing many federal energy statutes.  The Energy Act is expected to have a substantial long-term effect on energy markets, energy investment, and regulation of public utilities and holding company systems by the Federal Energy Regulatory Commission (FERC), the Securities and Exchange Commission (SEC) and the United States Department of Energy (DOE).  The FERC was directed by the Energy Act to address many areas previously regulated by other governmental entities under the statutes and determine whether changes to such previous regulations are warranted.  The issues that the FERC has been required to consider associated with the repeal of the Public Utility Holding Company Act of 1935, include the expansion of the FERC authority to review mergers and sales of public utility companies and the expansion of the FERC authority over the books and records of public utility companies previously governed by the SEC.  The FERC is in various stages of rulemaking on these and other issues.  NSP-Wisconsin cannot predict the impact the new rulemaking will have on its operations or financial results, if any.

Market-Based Rate Authority—The FERC regulates the wholesale sale of electricity.  In order to obtain market-based rate authorization from the FERC, utilities such as NSP-Wisconsin and Northern States Power Company, a Minnesota corporation (NSP-Minnesota), which is another wholly owned subsidiary of Xcel Energy, have been required to submit analyses demonstrating that they did not have market power in the relevant markets.  NSP-Wisconsin was previously granted market-based rate authority by the FERC.

In 2004, the FERC adopted two indicative screens (an uncommitted pivotal supplier analysis and an uncommitted market share analysis) as a revised test to assess market power.  Passage of the two screens creates a rebuttable presumption that an applicant does not have market power, while the failure creates a rebuttable presumption that the utility does have market power.  An applicant or intervenor can rebut the presumption by performing a more extensive delivered-price test analysis.  If an applicant is determined to have generation market power, the applicant has the opportunity to propose its own mitigation plan or may implement default mitigation established by the FERC.  The default mitigation limits prices for sales of power to cost-based rates within areas where an applicant is found to have market power.

Xcel Energy filed the required analysis applying the FERC’s two indicative screens on behalf of itself and NSP-Wisconsin with the FERC on Feb. 7, 2005.  This analysis demonstrated that NSP-Wisconsin passed the pivotal supplier analysis in its own control area

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and all adjacent markets, but failed the market share analysis in its own control area, and in the case of NSP-Minnesota and NSP-Wisconsin, which jointly operate a single control area and accordingly are analyzed as one company, in certain adjacent markets.  Numerous parties filed interventions and requested that FERC set the analysis for hearing.  Certain parties asked the FERC to revoke the market-based rate authority of NSP-Wisconsin.

On June 2, 2005, the FERC issued an order regarding the market-based rate authority application. Because of the commencement of the Midwest Independent Transmission System Operator, Inc. (MISO) Day 2 market, discussed below, and the FERC’s decision consistent with other precedent to analyze NSP-Minnesota and NSP-Wisconsin as part of that larger market, the FERC is not addressing NSP-Minnesota’s and NSP-Wisconsin’s market power in that investigation.  The FERC did require that Xcel Energy make a compliance filing providing information, including information regarding the FERC’s affiliate abuse component of its market power analysis and the allegations regarding that component made by an intervenor within 30 days of the date of issuance of its order.  The latter compliance filing was submitted on July 5, 2005.

Midwest Independent Transmission System Operator, Inc.

MISO Operations—MISO initiated the Day 2 wholesale market on April 1, 2005, including locational marginal pricing.  While it is anticipated that the Day 2 market will provide short-term efficiencies through a region-wide generation dispatch and increased reliability, as well as long-term benefits through dispatch of power from the most cost-effective sources of generation or transmission, there are costs associated with Day 2.  NSP-Minnesota and NSP-Wisconsin have requested recovery of these costs within their respective jurisdictions.

Within MISO, an independent market monitor reviews market bids and prices to identify any unusual activity.  This market monitor identified a number of such unusual items during the initial period of Day 2 operations.  These items were referred to the FERC, which investigated the issues.  These initial investigations were closed in July 2005.  While there has been no further action on these initial investigations, the FERC has notified Xcel Energy that it is investigating other pricing issues.  Xcel Energy and other market participants continue to work with MISO, the independent market monitor and the FERC to resolve Day 2 market implementation issues such as dispatch methods and settlement calculation details.  Xcel Energy also intends to work with these parties to resolve any identified pricing issues.

On Sept. 2, 2005, MISO notified market participants that it had corrected the method of calculating Over Collected Losses.   This change will be applied retroactively to the market start date.  This change will also impact other charge calculations.  MISO completed the resettlement and rebilling effort associated with this issue in October.  Settlements are expected in the fourth quarter of 2005.  Xcel Energy has accrued an estimated impact of this issue and has sought recovery where appropriate.  The ultimate effect of the rebilling and re-settlement effort is not completely known at this time, but based on the cost recovery mechanisms in place in the operating utility jurisdictions, it may have a material impact on the results of operations at NSP-Wisconsin.

New business processes, systems and internal controls over financial reporting were planned and implemented by Xcel Energy and MISO during the second quarter of 2005 to conduct business within the MISO Day 2 market.  Xcel Energy continues to validate these changes and to review the energy costs and revenues determined by MISO.  In August 2005, the MISO released an independent audit opinion concluding that the design and operating effectiveness of its internal controls related to the market settlement processes and information systems were suitably designed and operated with sufficient effectiveness during the period April 1, 2005 through May 31, 2005.  Supplementing this report, the MISO released an Internal Controls Disclosure Certificate dated Oct. 12, 2005 internally certifying the continuing effectiveness of its controls.  While neither the design nor operating effectiveness of the MISO control environment have been disputed, Xcel Energy and other market participants have disputed certain transactions.

MISO Cost Recovery—On March 29, 2005, NSP-Wisconsin received an order from the Public Service Commission of Wisconsin (PSCW) granting its requests to defer the costs and benefits attributable to the start-up of the MISO Day 2 energy market.  NSP-Wisconsin also received an order granting its request to record energy market transactions on a net basis. The netting of transactions is consistent with the approach envisioned by the FERC in approving the transmission and energy markets tariff and is consistent with generally accepted accounting principles.  On Sept. 22, 2005 the PSCW opened an investigation to obtain information from interested persons related to MISO policy development that is beneficial to ratepayers and that protects the public interest.  On Oct. 18, 2005 the PSCW solicited comments on the PSCW Staff proposal regarding rate and accounting treatment of MISO revenues and costs, as well as a request to escrow MISO Day 2 energy market costs until 2008.   NSP-Wisconsin will continue to work with the PSCW and the other Wisconsin’s utilities to address the longer-term issue related to MISO policies.

Wisconsin Public Service Corp. Complaints—In December 2004, Wisconsin Public Service Corp. (WPS) filed a complaint against MISO at FERC alleging that MISO improperly awarded NSP-Minnesota certain financial transmission rights under the MISO Day 2 market for certain partial path transmission services.  Xcel Energy intervened and protested the complaint.  The partial path

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transmission rights had also been the subject of a prior complaint by WPS in 2003 that FERC denied, a decision WPS appealed.  In late April 2005, FERC dismissed the 2004 WPS complaint, but the D.C. Circuit Court of Appeals vacated and remanded the 2003 complaint order to FERC.  In June 2005, WPS, MISO and Xcel Energy reached a settlement of the disputed matters.  On July 22, 2005, the FERC issued an order approving the settlement.  The settlement resolves the uncertainty related to the regulatory litigation.

MISO Long Term Transmission Pricing—On October 7, 2005, MISO filed proposed tariff revisions that would allow MISO to regionalize the cost of certain future high voltage transmission lines owned by individual transmission owners but constructed pursuant to the MISO transmission expansion plan.  The proposed tariffs reflect the stakeholder input to MISO through the Regional Expansion Capacity Benefits task force.  MISO proposes the tariff revisions be effective on Feb. 4. 2006.  Xcel Energy generally supports the proposed tariff revisions, which should encourage transmission construction by regionalizing a share of the cost of projects providing regional benefits.  Comments on or protests to the proposed tariff revisions will be filed at FERC later in 2005 and no final FERC decision is expected in 2005.

Other Regulatory Matters

2005 Fuel Cost Recovery—On April 22, 2005, NSP-Wisconsin filed an application with the PSCW to increase electric rates by $10 million, or 2.7 percent, annually to provide for recovery of forecasted increased costs of fuel and purchased power over the balance of 2005.  The March 2005 actual fuel costs were approximately 13 percent higher than authorized recovery in current base rates, and the forecast for the remainder of 2005 showed costs outside the annual range by 9.6 percent.  On May 18, 2005, the PSCW issued an order approving interim rates at the level requested, effective May 19, 2005.  At this level, the rate increase will generate an estimated $6.2 million in additional revenue for NSP-Wisconsin in 2005.  Under the provisions of the Wisconsin fuel rules, any difference between interim rates and final rates is subject to refund.  A public hearing was held on Aug. 23, 2005, and on Sept. 28, 2005, the PSCW issued a final order approving an increase of $11.6 million, or 3.1 percent annually.  Because the final rates are slightly higher than interim rates authorized in May 2005, no refund is necessary.  With an effective date of Oct. 1, 2005, final rates will collect approximately $400,000 in incremental revenue, as compared to interim rates, over the last three months of 2005.  Final rates set in this proceeding will remain in effect until new rates are set in the 2006 rate case proceeding.

On Oct. 14, 2005, NSP-Wisconsin filed an application with the PSCW to increase the amount of the currently authorized surcharge by $8.9 million or 2.3 percent on an annual basis.  This additional request was due to dramatic increases in the cost of natural gas and purchased power since the surcharge amount was set in mid-August.  September 2005 actual fuel costs were approximately 38 percent higher than authorized recovery in current rates, and the forecast for the remainder of 2005 showed costs outside the annual range by 7.5 percent.  A PSCW order was requested on an expedited basis.  If approved as requested, effective Nov. 10, 2005, NSP-Wisconsin would collect approximately $1.2 million in additional revenue over the remainder of 2005.

 2006 General Rate Case—NSP-Wisconsin filed with the PSCW an electric and natural gas rate case, as amended on Sept. 28, 2005, to reflect higher energy costs.  The amended filing requested an electric revenue increase of $53.1 million, or 13.4 percent, and a natural gas revenue increase of $7.7 million, or 4.8 percent, based on an 11.9 percent return on equity and a 56.32 percent common equity to total capitalization ratio.

On Oct. 12, 2005, the staff of the PSCW filed testimony recommending that NSP-Wisconsin has a 2006 test year electric revenue deficiency of $45.4 million, or 11.4 percent, and a natural gas revenue deficiency of $5.8 million, or 3.5 percent, based on an 11.0 percent return on equity and a 56.43 percent common equity to total capitalization ratio.

Intervenor testimony was also filed on Oct. 12, 2005.  Consultants representing the industrial intervenor group advocated a return on equity of 10.5 percent and a common equity to total capitalization ratio of 51 percent, as well as modifications to NSP-Wisconsin’s class cost of service study and rate design that would benefit their clients.  Testimony submitted on behalf of the U.S. Department of Defense and other federal executive agencies advocated a 10.25 percent return on equity and a common equity to total capitalization ratio of 56.3 percent, as well as cost allocations and rate design to benefit the Fort McCoy military installation.

Both the staff of the PSCW and the industrial intervenor group suggested that the PSCW consider whether it should continue to authorize a common equity to total capitalization ratio and return on equity comparable to other A or AA rated Wisconsin utilities or use metrics appropriate to a BBB+ credit rating.

Hearings are scheduled to begin on Nov. 1, 2005, with a decision expected near the end of 2005.

Chippewa and Flambeau Improvement Co. Reservoir Licensing—On April 18, 2003, the United States Court of Appeals for the District of Columbia upheld a ruling by the FERC that the Turtle-Flambeau storage reservoir owned by Chippewa and Flambeau Improvement Co. (Chippewa and Flambeau), a subsidiary of NSP-Wisconsin, is subject to licensure by the FERC under the Federal Power Act.  As an alternative to licensing, Chippewa and Flambeau on Nov. 17, 2003 proposed a modified operating regime and sought a declaratory order from the FERC disclaiming jurisdiction over Turtle-Flambeau, as a result of the proposed modified

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operating regime.  On March 30, 2005, the FERC staff denied Chippewa and Flambeau’s petition.  On April 29, 2005, Chippewa and Flambeau filed a petition for rehearing with regard to the FERC staff’s denial of Chippewa and Flambeau’s Nov. 17, 2003 petition for declaratory order.  On July 21, 2005, the FERC denied Chippewa and Flambeau’s petition for hearing.

On September 27, 2005, Chippewa and Flambeau advised the FERC that it would not contest further the FERC’s assertion of licensing jurisdiction over Turtle-Flambeau and provided the FERC with its compliance plan.  In lieu of obtaining a separate FERC license for Turtle-Flambeau, Chippewa and Flambeau intends to comply with the FERC licensing requirement by adding Turtle-Flambeau to the existing license of its majority shareholder, NSP-Wisconsin, for NSP-Wisconsin’s Big Falls Hydroelectric Project No. 2390.    Specifically, NSP-Wisconsin will file a non-capacity license amendment application for Big Falls to add Turtle-Flambeau as a project work of the Big Falls license.  Chippewa and Flambeau has proposed a filing date of September 30, 2006.  The costs associated with the non-capacity license amendment process are estimated at a minimum of $500,000.  In addition, Chippewa and Flambeau would expect to incur future costs related to complying with license conditions. These costs are not estimable at this time. Generally, NSP-Wisconsin has been responsible for approximately 70 percent of Chippewa and Flambeau’s operating expenses for the Turtle-Flambeau storage reservoir through tolls charged by Chippewa and Flambeau to NSP-Wisconsin.

3.  Commitments and Contingent Liabilities

Environmental Contingencies

NSP-Wisconsin has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, NSP-Wisconsin 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-Wisconsin is pursuing, or intends to pursue, recovery from other potentially responsible parties and through the rate regulatory process. To the extent any costs are not recovered through the options listed above, NSP-Wisconsin would be required to recognize an expense for such unrecoverable amounts in its consolidated financial statements.

Ashland Manufactured Gas Plant (MGP) Site—As previously disclosed in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2004, NSP-Wisconsin was named a potentially responsible party for creosote and coal tar contamination at a site in Ashland, Wis.  The Ashland site includes property owned by NSP-Wisconsin, which was previously an MGP facility, and two other properties:  an adjacent city lakeshore park area, on which an unaffiliated third party previously operated a sawmill, and an area of Lake Superior’s Chequamegon Bay adjoining the park.

On Sept. 5, 2002, the Ashland site was placed on the National Priorities List (NPL).  The NPL is intended primarily to guide the United States Environmental Protection Agency (EPA) in determining which sites require further investigation.  On Dec. 7, 2004, the EPA approved, with minor contingencies, NSP-Wisconsin’s proposed work plan to complete the remedial investigation and feasibility study.  The estimated cost of carrying out the work plan is $1.8 million in 2005.  NSP-Wisconsin has recorded a liability of  $18.0 million for its potential liability for remediating the Ashland site.  Since NSP-Wisconsin cannot currently estimate the cost of remediating the Ashland site, the recorded liability is based upon the minimum of the estimated range of remediation costs, using information available to date and reasonably effective remedial methods.  NSP-Wisconsin has deferred, as a regulatory asset, the costs accrued for the Ashland site based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers.  The PSCW has consistently authorized recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site, and has authorized recovery of similar remediation costs for other Wisconsin utilities.  External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin biennial retail rate case process.  Once approved by the PSCW, deferred MGP remediation costs, less carrying costs, are historically amortized over four or six years.  Carrying costs vary directly with the balance in the deferred account and for the period 1995-2002, totaled approximately $800,000.

The Wisconsin Department of Natural Resources (WDNR) and NSP-Wisconsin have each developed several estimates of the ultimate cost to remediate the Ashland site.  The estimates vary significantly, between $4 million and $93 million, because different methods of remediation and different results are assumed in each.  The EPA and WDNR have not yet selected the method of remediation to use at the site.  Until the EPA and the WDNR select a remediation strategy for the entire site and determine NSP-Wisconsin’s level of responsibility, NSP-Wisconsin’s liability for the cost of remediating the Ashland site is not determinable.

In addition to potential liability for remediation and WDNR oversight costs, NSP-Wisconsin may have liability for natural resource damages, including the assessment thereof (collectively NRDA) at the Ashland site.  Section 107 of the Comprehensive Environmental Response, Compensation and Liability Act, as amended, provides that a natural resource damages trustee may recover for injury to, destruction or loss of natural resources, including the reasonable costs of assessment, resulting from releases of hazardous substances.  Similarly, Section 311 of the Federal Water Pollution Control Act (or Clean Water Act) provides the federal and state governments with the ability to recover costs incurred in the restoration or replacement of natural resources damaged or

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destroyed as a result of a hazardous substance discharge.  In addition to liability for injuries to or loss of services caused by a release from the Ashland site, NSP-Wisconsin could face exposure for additional indirect injuries that could result from the implementation of various remedial technologies during the cleanup phase of the project.  NSP-Wisconsin has indicated to the relevant natural resource trustees its intent to pursue a cooperative assessment approach to the NRDA for the Ashland site whereby the question of natural resource damages is assessed and resolved in parallel with the performance of the studies required for selection of a cleanup remedy or remedies.  NSP-Wisconsin believes the trustees are interested in discussing such an approach.  It is, however, unknown at this time whether a cooperative assessment NRDA approach will be adopted at the Ashland site.  Therefore, NSP-Wisconsin is not able to estimate its potential exposure for natural resource damages at the site, but has recorded an estimate of its potential liability based upon the minimum of its estimated range of potential exposure.

Clean Air Interstate and Mercury Rules—In March 2005, the EPA issued two significant new air quality rules.  The Clean Air Interstate Rule (CAIR) further regulates sulfur dioxide (SO₂) and nitrogen oxide (NOx) emissions, and the Clean Air Mercury Rule regulates mercury emissions from power plants for the first time.

The objective of the CAIR is to cap emissions of SO₂ and NOx in the eastern United States, including Wisconsin.  When fully implemented, CAIR will reduce SO₂ emissions in 28 eastern states and the District of Columbia by over 70 percent and NOx emissions by over 60 percent from 2003 levels. It is designed to address the transportation of fine particulates, ozone and emission precursors to non-attainment downwind states.  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 NO_X 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.

In addition, Minnesota and Wisconsin will be included in CAIR, and Xcel Energy has generating facilities that will be impacted in these states.  Preliminary estimates of capital expenditures associated with compliance with CAIR for the NSP System range from $30 million to $40 million, which would be a cost sharable through the Interchange Agreement.  Xcel Energy is not challenging CAIR in these states.

There is uncertainty concerning implementation of CAIR.  States are required to develop implementation plans within 18 months 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 project the ultimate amount and timing of capital expenditure and operating expenses.

While NSP-Wisconsin 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-Wisconsin believes the cost of any required capital investment or allowance purchases will be recoverable from customers.

The EPA’s Clean Air Mercury Rule also uses a national cap-and-trade system and is designed to achieve a 70 percent reduction in mercury emissions.  It affects all coal- and oil-fired generating units across the country greater than 25 megawatts.  Compliance with this rule also occurs in two phases, with the first phase beginning in 2010 and the second phase in 2018.  States will be allocated mercury allowances based on their baseline heat input relative to other states and by coal type.  Each electric generating unit will be allocated mercury allowances based on its percentage of total coal heat input for the state.  NSP-Wisconsin is evaluating the impact of the Clean Air Mercury Rule and is currently unable to estimate the cost.

Federal Clean Water Act—The federal Clean Water Act addresses the environmental impacts of cooling water intakes. In July 2004, the EPA published phase II of the rule that applies to existing cooling water intakes at steam-electric power plants. The rule will require NSP-Wisconsin to perform additional environmental studies at two power plants in Wisconsin to determine the impact the facilities may be having on aquatic organisms vulnerable to injury.  If the studies determine the plants are not meeting the new performance standards established by the phase II rule, physical and/or operational changes may be required at these plants.  It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the many uncertainties involved. Based on the limited information available, total capital costs to the NSP System are estimated at approximately $31 million. After  costs are shared through the Interchange Agreement, NSP-Wisconsin’s estimated cost is $5 million. Actual costs may be significantly higher or lower depending on issues such as the resolution of outstanding third-party legal challenges to the rule.

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-Wisconsin’s financial position and results of operations.

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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-Wisconsin 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-Wisconsin.  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 should be dismissed because it 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 have filed a notice of appeal.

Other Contingencies

The circumstances set forth in Note 9 to the consolidated financial statements in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2004 and Note 2 of this Quarterly Report on Form 10-Q appropriately represent, in all material respects, the current status of commitments and contingent liabilities are incorporated herein by reference.

4.  Fuel and Supply Costs

Coal Deliverability

Delivery of coal from the Powder River Basin region in Wyoming has been disrupted by train derailments and other operational problems purportedly caused by deteriorated rail track beds of approximately 100 miles in length in Wyoming. The BNSF Railway Co. (BNSF) and the Union Pacific Railroad (UPRR) jointly own the rail line.  The BNSF operates and maintains the rail line.  BNSF and UPRR have indicated that repair and reconstruction of the deteriorated sections of rail track beds may take the balance of the year.

While operations at NSP-Minnesota and NSP-Wisconsin have not been significantly impacted by the reduced deliveries of coal from the Powder River Basin in Wyoming, NSP-Minnesota and NSP-Wisconsin have implemented a mitigation plan to conserve existing coal supplies for the NSP System, which includes NSP-Minnesota and NSP-Wisconsin. This plan includes increased power purchases from third parties and, where practicable, an increased use of natural gas for electric generation to replace the coal-fired electric generation.  Production costs for the NSP System increased as a result of implementation of the mitigation plan.

In Wisconsin, NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers.  NSP-Wisconsin has been granted authority by the PSCW to defer costs related to the coal deliverability issues.  Whether NSP-Wisconsin is ultimately authorized to recover deferred costs will be determined in a subsequent PSCW proceeding.

Natural Gas Cost

A variety of market factors have contributed to higher natural gas prices and are expected to continue to do so over the course of the coming months.  The fuel and purchased power cost recovery mechanism of the Wisconsin electric utility jurisdiction may not allow for complete recovery of all expenses and, therefore dramatic changes in costs can impact earnings.  In addition, the higher fuel costs could reduce customer demand or increase bad debt expense, which could also have a material impact on NSP-Wisconsin’s results of operations.  Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases could have a material impact on the cash flows of NSP-Wisconsin.  NSP-Wisconsin is unable to predict the extent to which the prices will increase or the ultimate impact of such increases on its results of operations or cash flows.

5.  Short-Term Borrowings

NSP-Wisconsin has approval from the PSCW to borrow up to $50 million in short-term debt from either external financial institutions or NSP-Minnesota.  On August 15, 2005, NSP-Wisconsin filed with the PSCW to increase the limit from $50 million to $75 million.  At September 30, 2005, NSP-Wisconsin had $24.5 million in short-term borrowings at a weighted average interest rate of 3.63 percent.

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6.  Derivative Valuation and Financial Impacts

NSP-Wisconsin records all derivative instruments on the balance sheet at fair value unless exempted as a normal purchase or sale. Changes in a non-exempt derivative instrument’s fair value are recognized currently in earnings unless the derivative has been designated in a qualifying hedging relationship. The application of hedge accounting allows a derivative instrument’s gains and losses to be reflected in Other Comprehensive Income or to offset related results of the hedged item in the statement of income, to the extent effective. SFAS No. 133—“Accounting for Derivative Instruments and Hedging Activities,” as amended, requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.

NSP-Wisconsin records the fair value of its derivative instruments in its Consolidated Balance Sheet as a separate line item identified as Derivative Instruments Valuation for assets and liabilities.

Cash Flow Hedges

NSP-Wisconsin 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, 2005, NSP-Wisconsin had net losses of approximately $0.1 million accumulated in Other Comprehensive Income related to interest rate cash flow hedge contracts that are expected to be recognized in earnings during the next 12 months.

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, and interest rate hedging transactions are recorded as a component of interest expense. NSP-Wisconsin is allowed to recover in natural gas rates the costs of certain financial instruments acquired to reduce commodity cost volatility. There was no hedge ineffectiveness in the third quarter of 2005.

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

	Nine months ended September 30,
(Millions of dollars)	2005			2004
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(1.0	)	$	(1.1	)
After-tax net unrealized gains related to derivatives accounted for as hedges	—			—
After-tax net realized losses on derivative transactions reclassified into earnings	—			—
Accumulated other comprehensive loss related to cash flow hedges at September 30	$	(1.0	)	$	(1.1	)

Normal Purchases or Normal Sales Contracts

NSP-Wisconsin 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 instrument 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. Contracts that meet these requirements are documented and exempted from the accounting and reporting requirements of SFAS No. 133.

NSP-Wisconsin evaluates all of its contracts when such contracts are entered to determine if they are derivatives and, if so, if they qualify and meet the normal designation requirements under SFAS No. 133.

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

7.  Detail of Interest and Other Income, Net of Nonoperating Expenses

Interest and other income, net of nonoperating expenses, for the three and nine months ended September 30 consists of the following:

	Three months ended September 30,						Nine months ended September 30,
(Thousands of dollars)	2005			2004			2005			2004
Interest income	$	103		$	134		$	312		$	496
Equity income in unconsolidated affiliates	—			7			—			21
Gain on sale of assets	5			—			18			8
Other nonoperating income	—			5			19			82
Nonoperating expenses	(244		)	(82		)	(346		)	(398		)
Total interest and other income, net of nonoperating expenses	$	(136	)	$	64		$	3		$	209

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8.  Segment Information

NSP-Wisconsin has two reportable segments, Regulated Electric Utility and Regulated Natural Gas Utility.

(Thousands of dollars)	Regulated Electric Utility		Regulated Natural Gas Utility			All Other			Reconciling Eliminations				Consolidated Total
Three months ended September 30, 2005
Revenues from:
External customers	$	138,692	$	11,457		$	172		$	—			$	150,321
Internal customers	—		838			—			(838			)	—
Total revenue	138,692		12,295			172			(838			)	150,321
Segment net income (loss)	$	5,909	$	(1,406	)	$	(359	)	$		—		$	4,144
Three months ended September 30, 2004
Revenues from:
External customers	$	122,642	$	12,691		$	162		$		—		$	135,495
Internal customers	37		820			—			(857			)	—
Total revenue	122,679		13,511			162			(857			)	135,495
Segment net income (loss)	$	18,907	$	(1,347	)	$	92		$		—		$	17,652

(Thousands of dollars)	Regulated Electric Utility		Regulated Natural Gas Utility				All Other			Reconciling Eliminations			Consolidated Total
Nine months ended September 30, 2005
Revenues from:
External customers	$	391,533	$			93,771	$	515		$	—		$	485,819
Internal customers	21		1,383				—			(1,404		)	—
Total revenue	391,554		95,154				515			(1,404		)	485,819
Segment net income (loss)	$	16,261	$		1,375		$	(689	)	$	—		$	16,947
Nine months ended September 30, 2004
Revenues from:
External customers	$	354,925	$	88,337			$	479		$	—		$	443,741
Internal customers	103		2,525				—			(2,628		)	—
Total revenue	355,028		90,862				479			(2,628		)	443,741
Segment net income (loss)	$	41,857	$	1,535			$	(116	)	$	—		$	43,276

9.  Comprehensive Income

The components of total comprehensive income are shown below:

	Three months ended September 30,				Nine months ended September 30,
(Millions of dollars)	2005		2004		2005			2004
Net income (loss)	$	4.1	$	17.7	$	16.9		$	43.3
Other comprehensive income:
After-tax net unrealized gains related to derivatives accounted for as hedges (see Note 6)	—		—		—			—
After-tax net realized gains on derivative transactions reclassified into earnings (see Note 6)	—		—		(0.1		)	—
Other comprehensive loss	—		—		(0.1		)	—
Comprehensive income	$	4.1	$	17.7	$	16.8		$	43.3

The accumulated comprehensive income in stockholder’s equity at September 30, 2005 and 2004, relates to valuation adjustments on NSP-Wisconsin’s derivative financial instruments and hedging activities.

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10.  Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

	Three months ended September 30,
	2005			2004			2005			2004
(Thousands of dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost	$	15,115		$	14,143		$	1,671		$	1,525
Interest cost	40,246			41,349			13,765			13,151
Expected return on plan assets	(70,290		)	(75,690		)	(6,425		)	(5,812		)
Amortization of transition (asset) obligation	—			(2		)	3,645			3,644
Amortization of prior service cost (credit)	7,509			7,503			(545		)	(544		)
Amortization of net (gain) loss	1,705			(3,688		)	6,562			5,412
Net periodic benefit cost (credit)	(5,715		)	(16,385		)	18,673			17,376
Settlements and curtailments	—			(223		)	—			—
Credits not recognized due to the effects of regulation	4,842			10,480			—			—
Additional cost recognized due to the effects of regulation	—			—			972			973
Net benefit cost (credit) recognized for financial reporting	$	(873	)	$	(6,128	)	$	19,645		$	18,349
NSP-Wisconsin
Net benefit cost (credit) recognized for financial reporting	$	(624	)	$	(1,306	)	$	686		$	599

	Nine months ended September 30,
	2005			2004			2005			2004
(Thousands of dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost	$	45,345		$	43,617		$	5,013		$	4,575
Interest cost	120,738			124,023			41,295			39,453
Expected return on plan assets	(210,048		)	(227,222		)	(19,275		)	(17,438		)
Amortization of transition (asset) obligation	—			(6		)	10,934			10,934
Amortization of prior service cost (credit)	22,527			22,509			(1,634		)	(1,634		)
Amortization of net (gain) loss	5,115			(11,406		)	19,685			16,238
Net periodic benefit cost (credit)	(16,323		)	(48,485		)	56,018			52,128
Settlements and curtailments	—			(926		)	—			—
Credits not recognized due to the effects of regulation	14,526			29,225			—			—
Additional cost recognized due to the effects of regulation	—			—			2,918			2,918
Net benefit cost (credit) recognized for financial reporting	$	(1,797	)	$	(20,186	)	$	58,936		$	55,046
NSP-Wisconsin
Net benefit cost (credit) recognized for financial reporting	$	(1,871	)	$	(4,349	)	$	2,059		$	1,796

Item 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS

Discussion of financial condition and liquidity for NSP-Wisconsin 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 and 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-Wisconsin 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:

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•        Economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures;

•        The risk of a significant slowdown in growth or decline in the U.S. economy, the risk of delay in growth recovery in the U.S. economy or the risk of increased cost for insurance premiums, security and other items;

•        Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where NSP-Wisconsin 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 (SEC), 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-Wisconsin or any of its subsidiaries; or security ratings;

•        Factors affecting utility and nonutility 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 gas pipeline constraints;

•        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 or additional competition in the markets served by NSP-Wisconsin and its subsidiaries;

•        State, federal and foreign 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;

•        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;

•        Risks associated with implementations of new technologies;

•        Other business or investment considerations that may be disclosed from time to time in NSP-Wisconsin’s SEC filings or in other publicly disseminated written documents; and

•        The other risk factors listed from time to time by NSP-Wisconsin in reports filed with the SEC, including Exhibit 99.01 to this report on Form 10-Q for the quarter ended Sept. 30, 2005.

Market Risks

NSP-Wisconsin and its subsidiaries are 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, 2004.  Commodity price and interest rate risks for NSP-Wisconsin are mitigated in most jurisdictions due to cost-based rate regulation.  At Sept. 30, 2005, there were no material changes to the financial market risks that affect the quantitative and qualitative disclosures presented at Dec. 31, 2004.

RESULTS OF OPERATIONS

NSP-Wisconsin’s net income was $16.9 million for the first nine months of 2005, compared with $43.3 million for the first nine months of 2004.

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Electric Utility Margins

The following table details the change in electric revenue and margin. Electric production expenses tend to vary with the quantity of electricity sold and changes in the unit costs of fuel and purchased power. The fuel and purchased power cost recovery mechanism of the Wisconsin jurisdiction may not allow for complete recovery of all expenses and, therefore, dramatic changes in costs or periods of extreme temperatures can impact earnings.

	Nine months ended September 30,
(Millions of dollars)	2005			2004
Total electric utility revenue	$	392		$	355
Electric fuel and purchased power	(227		)	(158		)
Total electric utility margin	$	165		$	197
Margin as a percentage of revenue	42.1		%	55.5		%

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

Base Electric Revenue

(Millions of dollars)	2005 vs. 2004
Sales growth (excluding weather impact)	$	6
Estimated impact of weather	6
Fuel and purchased power cost recovery	23
Interchange Agreement billing with NSP-Minnesota	5
Other	(3		)
Total base electric revenue increase	$	37

Base Electric Margin

(Millions of dollars)	2005 vs. 2004
Sales growth (excluding weather impact)	$	4
Estimated impact of weather	4
Fuel and purchased power cost recovery	(13		)
Interchange Agreement billing with NSP-Minnesota	(9		)
Interchange Agreement—prior period fixed charge adjustments	(14		)
Other	(4		)
Total base electric margin decrease	$	(32	)

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 purchase 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 September 30,
(Millions of dollars)	2005			2004
Natural gas revenue	$	94		$	88
Cost of natural gas purchased and transported	(72		)	(67		)
Natural gas margin	$	22		$	21

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

Natural Gas Revenue

(Millions of dollars)	2005 vs. 2004
Estimated impact of weather	$	1
Purchased gas adjustment clause recovery	5
Total natural gas revenue increase	$	6

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Natural Gas Margin

(Millions of dollars)	2005 vs. 2004
Estimated impact of weather	$	1
Total natural gas margin increase	$	1

Non-Fuel Operating Expense and Other Items

The following summarizes the components of the changes in other utility operating and maintenance expense for the nine months ended September 30:

(Millions of dollars)	2005 vs. 2004
Higher information technology network costs	$	2
Higher pension and medical costs	3
Higher Interchange expense from NSP-Minnesota	3
Lower bad debt costs	(1		)
Lower litigation costs	(1		)
Total other utility operating and maintenance expense increase	$	6

Depreciation and amortization expense increased by approximately $3.6 million, or 10.3 percent, for the first nine months of 2005 compared with the first nine months of 2004.  The increase was primarily due to plant additions and increased software amortization.

Allowance for funds used during construction, equity and debt, for the first nine months of 2005, decreased by approximately $1.3 million, compared with the first nine months of 2004, primarily due to a prior period adjustment, lower rates and lower amounts of construction work in progress.

Income tax expense decreased by approximately $17.3 million in the first nine months of 2005 compared with the first nine months of 2004. The decrease was primarily due to a decrease in pretax income.  The effective tax rate was 37.5 percent for the first nine months of 2005, compared with 38.8 percent for the same period in 2004.  The effective tax rate in 2005 was lower than 2004 due to a larger ratio of tax credits to lower pretax income levels in 2005.

Item 4.  CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

NSP-Wisconsin 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. 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-Wisconsin’s management, including the chief executive officer (CEO) and chief financial officer (CFO), of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that NSP-Wisconsin’s disclosure controls and procedures are effective.

Internal Control Over Financial Reporting

No change in NSP-Wisconsin’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-Wisconsin’s internal control over financial reporting.  NSP-Wisconsin has made certain changes in its internal control over financial reporting during the most recent fiscal quarter in order to make the control environment more effective and efficient.

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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-Wisconsin.  After consultation with legal counsel, NSP-Wisconsin has recorded an estimate of the probable cost of settlement or other disposition for such matters.  See Notes 2 and 3 to 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 and Note 9 to the consolidated financial statements in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2004 for a description of certain legal proceedings presently pending.  Except as discussed herein, there are no new significant cases to report against NSP-Wisconsin and there have been no notable changes in the previously reported proceedings.

Stray Voltage

As previously disclosed, on Nov. 13, 2001, Ralph and Karline Schmidt filed a complaint in Clark County, Wisconsin against NSP-Wisconsin. Plaintiffs alleged that electricity provided by NSP-Wisconsin harmed their dairy herd resulting in decreased milk production, lost profits and income, and property damage and sought compensatory, punitive and treble damages. Plaintiffs alleged compensatory damages of $1.0 million and pre-verdict interest of $1.2 million.  In addition, plaintiffs alleged an unspecified amount of damages related to nuisance.  NSP-Wisconsin has sought summary judgment on several bases; including statute of limitations; filed rate doctrine; public policy; and failure to state claims for strict products liability, nuisance, treble damages and pre-verdict interest.  On March 21, 2005, the trial court granted NSP-Wisconsin’s summary judgment motion on the bases of the statute of limitations and the filed rate doctrine.  Plaintiffs’ appeal is pending in District IV, Court of Appeals.

As previously disclosed, on Nov. 13, 2001, August C. Heeg Jr. and Joanne Heeg filed a complaint in Clark County, Wisconsin against NSP-Wisconsin. Plaintiffs alleged that electricity provided by NSP-Wisconsin harmed their dairy herd resulting in decreased milk production, lost profits and income, and property damage and sought compensatory, punitive and treble damages. Plaintiffs alleged compensatory damages of $1.9 million and pre-verdict interest of $6.1 million.  In addition, plaintiffs alleged an unspecified amount of damages related to nuisance.  On Feb. 7, 2005, the trial court granted NSP-Wisconsin’s motion for summary judgment based upon the statute of limitations. On reconsideration, the trial court on March 21, 2005, upheld its prior grant of summary judgment based upon the statute of limitations and also added the filed rate doctrine as a basis for summary judgment.   Plaintiffs’ appeal is pending in

District IV, Court of Appeals.

As previously disclosed, on March 1, 2002, NSP-Wisconsin was served with a lawsuit commenced by James and Grace Gumz and Michael and Susan Gumz in Marathon County Circuit Court, Wisconsin, alleging that electricity supplied by NSP-Wisconsin harmed their dairy herd and caused them personal injury.  In 2004, the trial court granted partial summary judgment to NSP-Wisconsin, dismissing plaintiff’s claims for strict products liability, trespass, pre-verdict interest, personal injury and treble damage claims.  As a result of these rulings and some modifications by the plaintiffs in their damage calculations, plaintiffs’ alleged compensatory damages were reduced to approximately $901,000 and an unspecified amount for nuisance.  On March 4, 2005, a verdict in the amount of approximately $533,000 was returned against NSP-Wisconsin.  On April 12, 2005, the trial court denied plaintiffs’ and NSP-Wisconsin’s motions after verdict and entered judgment on the verdict.  In May, 2005, NSPW appealed the trial court judgment.  Plaintiffs have filed a cross-appeal with respect to the trial court’s dismissal of the treble damages claim.

Manufactured Gas Plant (MGP) Insurance Coverage Litigation

In October 2003, NSP-Wisconsin initiated discussions with its insurers regarding the availability of insurance coverage for costs associated with the remediation of four former MGP sites located in Ashland, Chippewa Falls, Eau Claire, and LaCrosse, Wis. In lieu of participating in discussions, on Oct. 28, 2003, two of NSP-Wisconsin’s insurers, St. Paul Fire & Marine Insurance Co. and St. Paul Mercury Insurance Co., commenced litigation against NSP-Wisconsin in Minnesota state district court. On Nov. 12, 2003, NSP-Wisconsin commenced suit in Wisconsin state circuit court against St. Paul Fire & Marine Insurance Co. and its other insurers. Subsequently, the Wisconsin court denied the insurers’ motion to stay the Wisconsin case pending resolution of the Minnesota action.  On Jan. 6, 2005, the Minnesota court issued an injunction prohibiting NSP-Wisconsin from prosecuting the Wisconsin action.  On March 11, 2005, NSP-Wisconsin filed an appeal with the Minnesota Court of Appeals seeking reversal of the trial court’s issuance of the injunction.  On March 30, 2005, the Minnesota trial court granted NSP-Wisconsin’s motion and stayed enforcement of the injunction pending appeal.  Oral arguments with respect to NSP-Wisconsin’s appeal were heard on Oct. 5, 2005.  A decision on the appeal is expected in the first quarter of 2006.  A status conference in the Wisconsin action is scheduled for February 23, 2006.  Trial in the Wisconsin action is scheduled to begin in January 2007.

The PSCW has established a deferral process whereby clean-up costs associated with the remediation of former MGP sites are deferred and, if approved by the PSCW, recovered from ratepayers. Carrying charges associated with these clean-up costs are not subject to the deferral process and are not recoverable from ratepayers. Any insurance proceeds received by NSP-Wisconsin will operate as a credit to ratepayers, therefore, these lawsuits should not have an impact on shareholders, and no accruals have been made.

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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 October 31, 2005.

Northern States Power Co. (a Wisconsin 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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