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 March 31, 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)

 

 

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

 

 

 

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). Xcel Energy is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). 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 March 31,
		2005			2004
Operating revenues:
Electric utility		$	125,447		$	123,125
Natural gas utility		62,537			58,200
Other		168			163
Total operating revenues		188,152			181,488
Operating expenses:
Electric fuel and purchased power		64,943			53,900
Cost of natural gas sold and transported		49,766			45,762
Other operating and maintenance expenses		29,506			29,380
Depreciation and amortization		12,513			11,362
Taxes (other than income taxes)		4,412			4,316
Total operating expenses		161,140			144,720
Operating income		27,012			36,768
Other income:
Interest and other income, net of nonoperating expenses (see Note 5)		40			77
Allowance for funds used during construction - equity		(55		)	468
Total other income (expense)		(15		)	545
Interest charges and financing costs:
Interest charges — net of amounts capitalized; includes other financing costs of $301 and $303, respectively		5,559			5,444
Allowance for funds used during construction - debt		156			(164		)
Total interest charges and financing costs		5,715			5,280
Income before income taxes		21,282			32,033
Income taxes		8,227			12,819
Net income		$	13,055		$	19,214

 

See Notes to Consolidated Financial Statements

 

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NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(Thousands of Dollars)

 

		Three Months Ended March 31
		2005			2004
Operating activities:
Net income		$	13,055		$	19,214
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		12,800			11,800
Deferred income taxes		(1,159		)	1,039
Amortization of investment tax credits		(196		)	(197		)
Allowance for equity funds used during construction		55			(468		)
Undistributed equity in earnings of unconsolidated affiliates		—			7
Change in accounts receivable		(4,416		)	(5,849		)
Change in inventories		10,280			5,745
Change in other current assets		66			10,142
Change in accounts payable		4,722			(7,212		)
Change in other current liabilities		12,470			17,845
Change in other assets		259			(2,885		)
Change in other liabilities		422			(865		)
Net cash provided by operating activities		48,358			48,316
Investing activities:
Capital/construction expenditures		(12,699		)	(10,010		)
Allowance for equity funds used during construction		(55		)	468
Other investments — net		(5		)	(183		)
Net cash used in investing activities		(12,759		)	(9,725		)
Financing activities:
Short-term borrowings from affiliate — net		(23,700		)	(23,710		)
Dividends paid to parent		(11,961		)	(12,563		)
Net cash used in financing activities		(35,661		)	(36,273		)
Net (decrease) increase in cash and cash equivalents		(62		)	2,318
Net increase in cash and cash equivalents — consolidation of subsidiaries		510			—
Net increase in cash and cash equivalents — adoption of FIN No. 46		—			683
Cash and cash equivalents at beginning of period		231			137
Cash and cash equivalents at end of period		$	679		$	3,138

 

See Notes to Consolidated Financial Statements

 

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NSP-WISCONSIN AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)

		March 31, 2005			Dec. 31, 2004
ASSETS
Current assets:
Cash and cash equivalents		$	679		$	231
Accounts receivable — net of allowance for bad debts: $1,578 and $1,258, respectively		56,737			51,380
Accounts receivable from affiliates		229			1,154
Accrued unbilled revenues		32,986			27,665
Materials and supplies inventories — at average cost		4,703			4,709
Fuel inventory — at average cost		5,230			6,295
Natural gas inventory — at average cost		37			9,246
Current deferred income taxes		3,876			2,678
Prepaid taxes		10,114			13,471
Derivative instruments valuation — at market		—			1,405
Prepayments and other		2,404			3,029
Total current assets		116,995			121,263
Property, plant and equipment, at cost:
Electric utility plant		1,238,918			1,232,525
Natural gas utility plant		147,425			146,749
Common and other plant		108,176			96,346
Construction work in progress		14,126			20,153
Total property, plant and equipment		1,508,645			1,495,773
Less accumulated depreciation		(585,584		)	(575,099		)
Net property, plant and equipment		923,061			920,674
Other assets:
Other investments		6,680			7,800
Regulatory assets		49,572			50,760
Prepaid pension asset		52,709			52,272
Other		7,801			7,660
Total other assets		116,762			118,492
Total assets		$	1,156,818		$	1,160,429
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt		$	34		$	34
Notes payable to affiliate		8,500			32,200
Accounts payable		21,642			26,993
Accounts payable to affiliates		19,643			9,568
Taxes accrued		8,921			550
Accrued interest		9,083			4,265
Accrued payroll and benefits		5,227			5,318
Dividends payable to parent		11,783			11,961
Derivative instruments valuation — at market		—			1,060
Other		9,523			9,090
Total current liabilities		94,356			101,039
Deferred credits and other liabilities:
Deferred income taxes		166,895			166,765
Deferred investment tax credits		13,040			13,237
Regulatory liabilities		92,737			91,403
Customer advances for construction		17,129			16,912
Benefit obligations and other		22,940			22,952
Total deferred credits and other liabilities		312,741			311,269
Minority interest in subsidiaries		437			100
Long-term debt		315,370			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		65,277			65,277
Retained earnings		276,364			275,092
Accumulated other comprehensive income (loss)		(1,027		)	(1,046		)
Total common stockholder’s equity		433,914			432,623
Commitments and contingent liabilities (see Note 3)
Total liabilities and equity		$	1,156,818		$	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 March 31, 2005, and Dec. 31, 2004; the results of operations for the three months ended March 31, 2005 and 2004; and cash flows for the three months ended March 31, 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 of NSP-Wisconsin are set forth in Note 1 to its 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 Form 10-K.

 

1.     Accounting Policies

 

The significant accounting policies set forth in Note 1 to the consolidated financial statements in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2004 appropriately represent, in all material respects, the current status of accounting policies, and are incorporated herein by reference.

 

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 months ended March 31, 2004 have been reclassified to conform to the 2005 presentation.  These reclassifications had no effect on net income.

 

2.     Regulation

 

Federal Regulation

 

Market-Based Rate Authority — The Federal Energy Regulatory Commission (FERC) regulates the wholesale sale of electricity.  In addition to the FERC’s traditional cost of service methodology for determining the rates allowed to be charged for wholesale electric sales, in the 1990’s the FERC began to allow utilities to make sales at market-based rates.  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 and all adjacent markets, but failed the market share analysis in its own control area, and in the case of NSP-Minnesota and NSP-

 

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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.  It is accordingly expected that the FERC will set the market-based rate authorizations for investigation and hearing under Section 206 of the Federal Power Act.  At that time, NSP-Wisconsin expects to submit a delivered-price test analysis to support the continuance of market-based rate authority in its control area.  NSP-Wisconsin also expects that following the April 1, 2005 commencement of the Midwest Independent Transmission System Operator, Inc. (MISO) energy market, referred to as the Day 2 market, NSP-Wisconsin and NSP-Minnesota will be analyzed as part of the larger MISO market, and that they will pass both of the FERC’s indicative screens in the larger MISO market.

 

Midwest Independent Transmission System Operator, Inc.

 

MISO Operations — In August 2000, NSP-Wisconsin and NSP-Minnesota joined the MISO. In December 2001, the FERC approved the MISO as the first regional transmission organization (RTO) in the United States under FERC Order No. 2000. On Feb. 1, 2002, the MISO began interim operations, including regional transmission tariff administration services for the NSP-Wisconsin and NSP-Minnesota electric transmission systems.  In 2002, NSP-Wisconsin and NSP-Minnesota received all required regulatory approvals to transfer functional control of their high voltage (100 kilovolts and above) transmission systems to the MISO. The MISO membership grants MISO functional control over the operations of these facilities and the facilities of certain neighboring electric utilities.

 

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.  To date, the information systems required to operate the market have performed satisfactorily.  However, during the initial days of operation, MISO centrally dispatched generation in a manner different than pre-market individual utility dispatch, with more dispatch of natural gas and oil fired peaking units for similar load and weather conditions.  MISO has stated that energy imports from coal and hydro generation located outside the MISO region were also substantially lower than in pre-market periods.  It is not known if these conditions are short-term implementation issues related to the complexity of centralized market operations and market participant inexperience.  In early April 2005, the FERC sent letters to several MISO market participants, including NSP-Wisconsin, with questions regarding generation price offers submitted to MISO in comparison to reference prices calculated by the MISO independent market monitor.  NSP-Wisconsin submitted a timely response to the FERC letter.  NSP-Wisconsin and other market participants are actively working with MISO, the independent market monitor and the FERC to resolve Day 2 market implementation issues.  NSP-Wisconsin is also considering its regulatory and other options if the initial market operation issues continue.

 

Implementation of a wholesale regional market using the locational marginal cost pricing and financial transmission rights is expected to provide a long-term benefit to NSP-Wisconsin through a reduction in overall wholesale power costs.  However, NSP-Wisconsin cannot at this early stage estimate the total financial impact of the new market structure on 2005 costs or revenues.

 

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 MISO.  Because it is difficult to predict or quantify the costs or benefits, the deferral order provides temporary protection to both utilities and customers, until a long-term solution regarding recovery of Day 2 costs can be designed and implemented.  Also, NSP-Wisconsin 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.

 

MISO Arbitration - In March 2005, an arbitrator issued a decision in the arbitration between American Transmission Company, LLC (ATC) and the MISO regarding the distribution of approximately $11.5 million of transmission service revenues related to certain transmission service reservations under the MISO open access transmission tariff.  This was the first arbitration conducted under the dispute resolution procedures of the MISO agreement.  NSP-Wisconsin participated in the proceeding in support of the MISO position that the revenue distribution to ATC was erroneous and the revenues should instead be shared among all MISO transmission owners retroactive to Feb. 1, 2002, when the error occurred.  The arbitrator ruled the revenue distribution should be corrected, but prospective from Aug. 1, 2004.  A refund retroactive to Aug. 1, 2004 results in a refund of approximately $0.8 million to NSP-Minnesota and NSP-Wisconsin.  The proceeds were received in March 2005.  MISO has indicated it does not plan to seek FERC review of the award.

 

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.  March 2005 actual fuel costs were approximately 13 percent higher than authorized recovery in current base rates, and the current forecast for

 

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the remainder of 2005 shows costs outside the annual range by 9.6 percent.  If approved as filed, NSP-Wisconsin is expected to recover approximately $6.2 million, subject to refund, in additional revenue in 2005, based on an implementation date of May 19, 2005 under provisions of the PSCW fuel cost recovery rules.  Final rates would be determined later in 2005 after a full audit and public hearing, and would remain in effect until new rates set in the 2006 rate case are implemented.

 

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 operating regime.  On March 30, 2005, the FERC staff denied Chippewa-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.

 

If Chippewa and Flambeau is ultimately required to obtain a FERC license, the costs are estimated at a minimum of $750,000.  In addition, Chippewa-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.

 

Clean Air Interstate and Mercury Rules - In March 2005, the Environmental Protection Agency (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.

 

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.

 

Currently, there are several uncertainties concerning implementation of both rules.  States are required to develop implementation plans within 18 months and have a significant amount of discretion in the implementation details.  Legal challenges to both rules are expected, which could alter their substance or schedule.  Due to these uncertainties, NSP-Wisconsin has not yet completed an analysis of the probable impact on operations of the CAIR and mercury rules.  However, NSP-Wisconsin’s emission reduction initiatives have reduced the potential impact of the rules on its operations.  Based on currently available information, NSP-Wisconsin expects that it will comply using a combination of additional capital investments in emission controls at various facilities and purchases of emissions allowances.  These new rules could have a material impact on future capital expenditures and operating and maintenance expenses.  NSP-Wisconsin expects that it may begin to make capital investments in 2007 or sooner and may begin to purchase allowances prior to the applicable compliance dates.  Although regulatory treatment may vary from state to state, the cost of any required capital investment or allowance purchase are expected to generally be recoverable in the same manner as other similar costs through the filing of rate cases.  In some circumstances, the costs may be recoverable through a rider or adjustment clause mechanism.  NSP-Wisconsin has not determined the applicable cost recovery strategy for each jurisdiction in which it operates.

 

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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Other Contingencies

 

The circumstances set forth in Note 9 to the financial statements in NSP-Wisconsin’s Annual Report on Form 10-K for the year ended Dec. 31, 2004 and Note 2 and 3 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.     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 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. Statement of Financial Accounting Standard No. 133 — “Accounting for Derivative Instruments and Hedging Activities,” as amended, (SFAS No. 133) requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.

 

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

 

		Three months ended
(Millions of dollars)		March 31, 2005			March 31, 2004
Balance 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 — March 31,		$	(1.0	)	$	(1.1	)

 

 

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 March 31, 2005, NSP-Wisconsin had net losses of $0.1 million accumulated in Other Comprehensive Income related to interest 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 electric energy are 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 first quarter of 2005.

 

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.

 

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

 

Interest and other income, net of nonoperating expenses, for the three months ended March 31 comprise of the following:

 

 

6.     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 March 31, 2005
Revenues from:
External customers		$	125,447		$	62,537		$	168		$	—		$	188,152
Internal customers		21			93			—			(114		)	—
Total revenue		125,468			62,630			168			(114		)	188,152
Segment net income		$	9,535		$	3,694		$	(174	)	$	—		$	13,055
Three months ended March 31, 2004
Revenues from:
External customers		$	123,125		$	58,200		$	163		$	—		$	181,488
Internal customers		39			1,331			—			(1,370		)	—
Total revenue		123,164			59,531			163			(1,370		)	181,488
Segment net income		$	16,101		$	3,408		$	(295	)	$	—		$	19,214

 

7.     Comprehensive Income

 

The components of total comprehensive income are shown below:

 

 

The accumulated comprehensive income in stockholder’s equity at March 31, 2005 and 2004, relates to valuation adjustments on NSP-Wisconsin’s derivative financial instruments and hedging activities and the mark-to-market components of NSP-Wisconsin’s marketable securities.

 

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8. Benefit Plans and Other Postretirement Benefits

 

Components of Net Periodic Benefit Cost

 

		Three months ended March 31,
		2005			2004			2005			2004
(Thousands of dollars)		Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost		$	17,250		$	16,350		$	1,743		$	1,625
Interest cost		40,996			38,175			13,867			12,900
Expected return on plan assets		(70,274		)	(72,225		)	(6,583		)	(5,275		)
Amortization of transition (asset) obligation		—			(2		)	3,645			3,700
Amortization of prior service cost (credit)		7,522			7,601			(545		)	(550		)
Amortization of net (gain) loss		3,449			(5,141		)	6,663			5,550
Net periodic benefit cost (credit)		(1,057		)	(15,242		)	$	18,790		$	17,950
Costs not recognized due to the effects of regulation		3,184			10,177			—			—
Additional cost recognized due to the effects of regulation		—			—			973			973
Net benefit cost (credit) recognized for financial reporting		$	2,127		$	(5,065	)	$	19,763		$	18,923
NSP-Wisconsin
Net benefit cost (credit) recognized for financial reporting		$	(437	)	$	(1,497	)	$	707		$	769

 

 

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 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-Wisconsin to obtain financing on favorable terms, inflation rates and monetary fluctuations;

•             Business conditions in the energy business;

•             Demand for electricity in the nonregulated marketplace;

•             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, 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, Xcel Energy or NSP-Wisconsin; 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 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;

•             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 gas markets; industry restructuring

 

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                   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;

•             Risks associated with implementation of new technologies; and

•             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.

 

Market Risks

 

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

 

RESULTS OF OPERATIONS

 

NSP-Wisconsin’s net income was $13.1 million for the first three months of 2005, compared with $19.2 million for the first three months of 2004.

 

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.

 

 

 

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

 

Base Electric Revenue

 

 

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Base Electric Margin

 

 

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.

 

 

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

 

Natural Gas Revenue

 

 

Natural Gas Margin

 

 

Non-Fuel Operating Expense and Other Items

 

The following summarizes the components of the changes in other utility operating and maintenance expense for the three months ended March 31:

 

 

Depreciation and amortization expense increased by approximately $1.2 million, or 10.1 percent, for the first three months of 2005 compared with the first three months of 2004.  The increase was primarily due to plant additions and increased software amortization.

 

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Allowance for funds used during construction, equity and debt, for the first three months of 2005, decreased by approximately $0.8 million, compared with the first three months of 2004, due mainly to a prior period adjustment.

 

Income tax expense decreased by approximately $4.6 million in the first three months of 2005 compared with the first three months of 2004. The decrease was primarily due to lower levels of pre-tax income.  The effective tax rate was 38.7 percent for the first three months of 2005, compared with 40.0 percent for the same period in 2004.  The decrease was primarily due to the decrease in pretax income and an increase in tax benefits related to SFAS No. 106.

 

Item 4. CONTROLS AND PROCEDURES

 

Disclosure Controls

 

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, its internal control over financial reporting.

 

Part II. OTHER INFORMATION

 

Item 1. LEGAL PROCEEDINGS

 

In the normal course of business, various lawsuits and claims have arisen against NSP-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 of the Financial Statements in this Quarterly Report on Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 and Note 9 of 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.

 

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 have filed a notice of appeal.

 

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

 

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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.

 

Manufactured Gas Plant 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.  Trial in the Minnesota action has been set for September 6, 2006.  A status conference in the Wisconsin action is scheduled for May 2, 2005.  Trial in the Wisconsin action has been set for January 22, 2007-April 12, 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.

 

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 May 2, 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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