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: 001-31387

 

Northern States Power Company

(Exact name of registrant as specified in its charter)

 

 

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

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 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 Minnesota corporation) meets the conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H (2) to such Form 10-Q.

 

 

Table of Contents

 

	PART I - FINANCIAL INFORMATION
Item l.	Financial Statements
Item 2.	Management’s Discussion and Analysis
Item 4	Controls and Procedures
	PART II - OTHER INFORMATION
Item 1.	Legal Proceedings
Item 5.	Other Information
Item 6.	Exhibits

 

This Form 10-Q is filed by Northern States Power Co., a Minnesota corporation (NSP-Minnesota).  NSP-Minnesota is a wholly owned subsidiary of Xcel Energy Inc. (Xcel Energy). 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-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(Thousands of Dollars)

 

		Three Months Ended
		March 31,
		2005			2004
Operating revenues:
Electric utility		$	622,795		$	609,667
Natural gas utility		321,482			312,132
Other		5,326			7,863
Total operating revenues		949,603			929,662
Operating expenses:
Electric fuel and purchased power		243,142			216,280
Cost of natural gas sold and transported		258,699			246,845
Other operating and maintenance expenses		220,742			207,495
Depreciation and amortization		94,401			82,166
Taxes (other than income taxes)		41,356			44,243
Total operating expenses		858,340			797,029
Operating income		91,263			132,633
Other income (expense):
Interest income and other income, net of nonoperating expenses (see Note 6)		137			(133		)
Allowance for funds used during construction - equity		4,270			3,715
Total other income		4,407			3,582
Interest charges and financing costs:     Interest charges — net of amounts capitalized, includes other financing costs of $321 and $2,305, respectively		36,024			35,596
Allowance for funds used during construction - debt		(3,110		)	(2,734		)
Total interest charges and financing costs		32,914			32,862
Income before income taxes		62,756			103,353
Income taxes		21,129			34,996
Net income		$	41,627		$	68,357

 

See Notes to Consolidated Financial Statements

 

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(Thousands of Dollars)

 

		Three Months Ended
		March 31,
		2005			2004
Operating activities:
Net income		$	41,627		$	68,357
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		97,451			85,461
Nuclear fuel amortization		10,066			11,596
Deferred income taxes		(3,991		)	3,165
Amortization of investment tax credits		(1,653		)	(1,787		)
Allowance for equity funds used during construction		(4,270		)	(3,715		)
Change in accounts receivable		(5,204		)	(24,714		)
Change in accounts receivable from affiliates		(7,422		)	44,887
Change in inventories		43,350			34,645
Change in other current assets		(20,005		)	26,502
Change in accounts payable		(9,752		)	(19,029		)
Change in other current liabilities		(6,885		)	32,275
Change in other noncurrent assets		7,394			13,685
Change in other noncurrent liabilities		20,239			16,397
Net cash provided by operating activities		160,945			287,725
Investing activities:
Capital/construction expenditures		(167,510		)	(121,502		)
Allowance for equity funds used during construction		4,270			3,715
Advances to affiliates		23,700			—
Investments in external decommissioning fund		(20,052		)	(20,145		)
Other investments — net		(83		)	(922		)
Net cash used in investing activities		(159,675		)	(138,854		)
Financing activities:
Short-term borrowings — net		30,000			(58,000		)
Repayment of long-term debt, including reacquisition premiums		(7,605		)	(54		)
Capital contribution from parent		50,000			50,000
Dividends paid to parent		(53,033		)	(53,852		)
Net cash provided by (used in) financing activities		19,362			(61,906		)
Net increase in cash and cash equivalents		20,632			86,965
Cash and cash equivalents at beginning of period		6,234			82,015
Cash and cash equivalents at end of period		$	26,866		$	168,980

 

See Notes to Consolidated Financial Statements

 

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NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)

 

		March 31, 2005			Dec. 31, 2004
ASSETS
Current assets:
Cash and cash equivalents		$	26,866		$	6,234
Notes receivable from affiliates		7,800			31,500
Accounts receivable — net of allowance for bad debts: $8,508 and $7,845, respectively		301,535			296,331
Accounts receivable from affiliates		15,772			8,350
Accrued unbilled revenues		190,501			172,512
Materials and supplies inventories at average cost		95,328			96,953
Fuel inventory — at average cost		28,291			31,483
Natural gas inventory — at average cost		17,157			55,689
Derivative instrument valuation - at market		34,959			62,272
Prepayments and other		44,527			32,719
Total current assets		762,736			794,043
Property, plant and equipment, at cost:
Electric utility plant		7,625,817			7,586,873
Natural gas utility plant		782,404			778,256
Construction work in progress		438,951			438,474
Other		482,660			406,229
Total property, plant and equipment		9,329,832			9,209,832
Less accumulated depreciation		(4,253,394		)	(4,175,557		)
Nuclear fuel — net of accumulated amortization: $1,155,294 and $1,145,228, respectively		106,124			74,308
Net property, plant and equipment		5,182,562			5,108,583
Other assets:
Nuclear decommissioning fund investments		957,460			918,442
Other investments		23,973			24,039
Regulatory assets		598,258			476,485
Prepaid pension asset		364,346			361,446
Derivative instrument valuation - at market		165,126			234,509
Other		50,923			47,968
Total other assets		2,160,086			2,062,889
Total assets		$	8,105,384		$	7,965,515
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt		$	74,684		$	82,185
Short-term debt		120,000			90,000
Accounts payable		247,859			287,531
Accounts payable to affiliates		52,934			23,013
Taxes accrued		171,543			147,144
Accrued interest		23,043			42,998
Dividends payable to parent		54,672			53,033
Derivative instrument valuation - at market		28,728			58,366
Other		52,862			51,560
Total current liabilities		826,325			835,830
Deferred credits and other liabilities:
Deferred income taxes		788,523			785,046
Deferred investment tax credits		57,465			59,119
Regulatory liabilities		964,820			944,364
Asset retirement obligations		1,108,394			1,091,089
Derivative instrument valuation - at market		304,701			246,872
Benefit obligations and other		151,002			136,131
Total deferred credits and other liabilities		3,374,905			3,262,621
Long-term debt		1,859,871			1,859,737
Common stock — authorized 5,000,000 shares of $0.01 par value, outstanding 1,000,000 shares		10			10
Premium on common stock		1,073,377			1,023,377
Retained earnings		970,896			983,940
Total common stockholder’s equity		2,044,283			2,007,327
Commitments and contingencies (see Note 3)
Total liabilities and equity		$	8,105,384		$	7,965,515

 

See Notes to Consolidated Financial Statements

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly the financial position of NSP-Minnesota and its subsidiaries as of March 31, 2005, and Dec. 31, 2004; the results of its operations for the three months ended March 31, 2005 and 2004; and its cash flows for the three months ended March 31, 2005 and 2004. Due to the seasonality of electric and natural gas sales of NSP-Minnesota, quarterly results are not necessarily an appropriate base from which to project annual results.

 

The significant accounting policies of NSP-Minnesota 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 Form 10-K.

 

1.     Significant Accounting Policies

 

The significant accounting policies set forth in Note 1 to the consolidated financial statements in NSP-Minnesota’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-Minnesota 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-Minnesota and Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin), 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-Minnesota 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-Minnesota with the FERC on Feb. 7, 2005.  This analysis demonstrated that NSP-Minnesota 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 or condition the market-based rate authority of NSP-Minnesota.  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-Minnesota expects to submit a delivered-price test analysis to support the continuance of market-based rate authority in its control area.  NSP-Minnesota 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-Minnesota and NSP-Wisconsin 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.  NSP-Minnesota does not expect the mitigation measures imposed, if any, to have a significant financial impact on its commodity marketing operations.

 

Midwest Independent Transmission System Operator, Inc.

 

MISO Operations — In August 2000, NSP-Minnesota and NSP-Wisconsin 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-Minnesota and NSP-Wisconsin electric transmission system.  In 2002, NSP-Minnesota and NSP-Wisconsin 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-Minnesota, with questions regarding generation price offers submitted to MISO in comparison to reference prices calculated by the MISO independent market monitor.  NSP-Minnesota submitted a timely response to the FERC letter.  NSP-Minnesota and other market participants are actively working with MISO, the independent market monitor and the FERC to resolve Day 2 market implementation issues.  NSP-Minnesota 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-Minnesota through a reduction in overall wholesale power costs.  However, NSP-Minnesota cannot at this early stage estimate the total financial impact of the new market structure on 2005 costs or revenues.

 

MISO Cost Recovery  — On Dec. 18, 2004, NSP-Minnesota filed with the Minnesota Public Utilities Commission (MPUC) a petition to seek recovery of the Minnesota jurisdictional portion of all net costs associated with the implementation of the MISO Day 2 market through its fuel clause adjustment (FCA) mechanism.  Under the current FCA mechanism in Minnesota, NSP-Minnesota is allowed full recovery of its fuel and purchased energy costs.  The proposal would allow recovery of locational marginal pricing market costs, including congestion and marginal loss costs, which would be netted by revenues generated by financial transmission rights and revenues received that are related to marginal compensation loss costs, as well as MISO energy market operations costs.  NSP-Minnesota sought recovery effective with the beginning of the energy market on April 1, 2005, and the deferral of costs incurred prior to MPUC action.  On April 7, 2005, the MPUC issued an order allowing NSP-Minnesota to recover these costs through the FCA effective April 1, 2005, on an interim basis, subject to refund, pending a later decision on the merits when the full record of the case is developed.  A decision on the merits is expected later in 2005.

 

In addition, in March 2005, NSP-Minnesota filed similar petitions with the North Dakota Public Service Commission (NDPSC) and the South Dakota Public Utilities Commission (SDPUC) proposing changes to allow recovery of the applicable North Dakota and South Dakota jurisdictional portions of all net costs associated with implementation of the MISO Day 2 market, to be effective April 1, 2005.  The SDPUC approved the proposed tariff changes effective April 1, 2005, as requested.  The NDPSC granted interim recovery through the FCA beginning April 1, 2005, but similar to the decision of the MPUC, conditioned the relief as being subject to refund until the merits of the case are determined.

 

7

 

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-Minnesota 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

 

Natural Gas Rate Case - In September 2004, NSP-Minnesota filed a natural gas rate case for its Minnesota retail customers, seeking a rate increase of $9.9 million, based on a return on equity of 11.5 percent.  Interim rates collecting $6.4 million per year were implemented December 1, 2004, subject to refund.

 

On April 19, 2005, NSP-Minnesota and the Department of Commerce filed with an administrative law judge and the MPUC an offer of settlement related to the natural gas rate case.  The settlement agreement includes an annual rate increase of $5.8 million, based on a return on equity of 10.4 percent.  The settlement also reflects an increase in the residential customer charge from $6.50 to $8.00 per month.  Other parties to the proceeding were to file surrebuttal testimony by April 29, 2005, and hearings are expected to be held in early May.   The settlement agreement is subject to the approval of the MPUC, which is expected to act in this proceeding in August 2005.

 

Nuclear Plant Re-licensing — On Aug. 25, 2004, the Xcel Energy board of directors authorized the pursuit of renewal of the operating licenses for the Monticello and Prairie Island nuclear plants.  Monticello’s current 40-year license expires in 2010, and Prairie Island’s licenses for its two units expire in 2013 and 2014.  NSP-Minnesota filed its application for Monticello with the MPUC in January 2005 seeking a certificate of need for dry spent fuel storage.  On March 24, 2005, a license renewal application for Monticello was filed with the Nuclear Regulatory Commission (NRC), commencing a 22-month review and approval process necessary for the NRC to grant the 20-year license extension allowed by NRC regulations. Plant assessments and other work for the Prairie Island applications are planned in the next two to three years.

 

3. Commitments and Contingent Liabilities

 

Environmental Contingencies

 

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

 

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 Minnesota.  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

 

8

 

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-Minnesota has not yet completed an analysis of the probable impact on operations of the CAIR and mercury rules.  However, NSP-Minnesota’s emission reduction initiatives have reduced the potential impact of the rules on its operations.  Based on currently available information, NSP-Minnesota 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-Minnesota 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, 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-Minnesota 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-Minnesota’s financial position and results of operations.

 

Other Contingencies

 

The circumstances set forth in Notes 11 and 12 to the financial statements in NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2004 and Notes 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, including those regarding public liability for claims resulting from any nuclear incident and are incorporated herein by reference

 

4. Short-Term Borrowings and Financing Activities

 

At March 31, 2005, NSP-Minnesota had approximately $120 million of short-term debt outstanding at a weighted average interest rate of 4.48 percent.

 

NSP-Minnesota renewed its credit facility on April 21, 2005.  The $375 million facility has a term of 5 years and is unsecured.  The credit facility has one financial covenant, requiring that the debt to total capitalization ratio be less than or equal to 65 percent.

 

On March 22, 2005, NSP-Minnesota filed a shelf registration statement with the SEC to register an additional $1 billion of secured or unsecured debt securities, which may be issued from time to time in the future.  This registration supplements the $40 million of debt securities previously registered with the SEC.

 

5.     Derivative Valuation and Financial Impacts

 

NSP-Minnesota 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 operations, 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-Minnesota’s Other Comprehensive Income, included as a component of stockholder’s equity, are detailed in the following table:

 

		Three months ended March 31,
(Millions of dollars)		2005			2004
Balance at Jan. 1,		$	—		$	0.0
After-tax net unrealized gains related to derivatives accounted for as hedges		4.2			0.4
After-tax net realized losses on derivative transactions reclassified into earnings		(4.2		)	(0.5		)
Accumulated other comprehensive income (loss) related to cash flow hedges — March 31,		$	—		$	(0.1	)

 

9

 

Cash Flow Hedges

 

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

 

At March 31, 2005, NSP-Minnesota had no commodity-related contracts designated as cash flow hedges.  The fair value of cash flow hedges is recorded in either Other Comprehensive Income or deferred as a regulatory asset or liability. This classification is based on the regulatory recovery mechanisms in place. Amounts deferred in these accounts are recorded in earnings as the hedged purchase or sales transaction is settled. This could include the physical purchase or sale of energy and energy related products, the use of natural gas to generate electric energy or natural gas purchased for resale. As of March 31, 2005, NSP-Minnesota had no amounts accumulated in Other Comprehensive Income related to commodity cash flow hedge contracts that are expected to be recognized in earnings during the next 12 months as the hedged transactions settle. However, due to the volatility of commodities markets, the value in Other Comprehensive Income will likely change prior to its recognition in earnings.

 

Gains or losses on hedging transactions for the sales of energy and energy related products 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-Minnesota 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.

 

Derivatives Not Qualifying for Hedge Accounting

 

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

 

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

 

Normal Purchases or Normal Sales Contracts

 

NSP-Minnesota enters into contracts for the purchase and sale of various commodities for use in its business operations. SFAS No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the definition of a derivative may be exempted from SFAS No. 133 as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial 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-Minnesota 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. None of the derivative contracts entered into within the commodity trading operations qualify for a normal designation.

 

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

 

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6. 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 comprises of the following:

 

 

7.     Segment Information

 

NSP-Minnesota has two reportable segments, Regulated Electric Utility and Regulated Natural Gas Utility. Commodity trading operations are not a reportable segment; commodity trading results are included in the Regulated Electric Utility segment.

 

(Thousands of dollars)		Regulated Electric Utility			Regulated Natural Gas Utility			All Other			Reconciling Eliminations			Consolidated Total
Three months ended March 31, 2005
Revenues from:
External customers		$	622,795		$	321,482		$	5,326		$	—		$	949,603
Internal customers		278			1,008			—			(1,286		)	—
Total revenue		623,073			322,490			5,326			(1,286		)	949,603
Segment net income		$	16,132		$	23,203		$	2,292		$	—		$	41,627
Three months ended March 31, 2004
Revenues from:
External customers		$	609,667		$	312,132		$	7,863		$	—		$	929,662
Internal customers		198			2,102			—			(2,300		)	—
Total revenue		609,865			314,234			7,863			(2,300		)	929,662
Segment net income		$	44,506		$	20,751		$	3,100		$	—		$	68,357

 

8.     Comprehensive Income

 

The components of total comprehensive income are shown below:

 

 

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

 

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9. Benefit Plans and Other Postretirement Benefits

 

Components of Net Periodic Benefit Cost

 

		Three months ended March 31,
(Thousands of dollars)		2005			2004			2005			2004
Xcel Energy Inc.		Pension Benefits						Postretirement Health Care Benefits
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-Minnesota
Net periodic benefit cost (credit)		$	(2,900	)	$	(10,706	)	$	4,407		$	4,980
Credits not recognized due to the effects of regulation		3,184			10,177			—			—
Net benefit cost (credit) recognized for financial reporting		$	284		$	(529	)	$	4,407		$	4,980

 

 

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

 

Discussion of financial condition and liquidity for NSP-Minnesota is omitted per conditions set forth in general instructions H (1) (a) and (b) of Form 10-Q for wholly owned subsidiaries. It is replaced with management’s narrative analysis 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-Minnesota during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited financial statements and notes.

 

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “estimate,” “expect,” “objective,” “outlook,” “possible,” “potential” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to:

 

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

•           Business conditions in the energy business;

•           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-Minnesota has a financial interest;

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

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

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

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

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

•           Increased competition in the utility industry;

•           State and federal legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and natural gas markets; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional

 

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regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

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

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

•           Social attitudes regarding the utility and power industries;

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

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

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

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

 

Market Risks

 

NSP-Minnesota is exposed to market risks, including changes in commodity prices and interest rates, as disclosed in Item 7A — Quantitative and Qualitative Disclosures About Market Risk in its Annual Report on Form 10-K for the year ended Dec. 31, 2004. Commodity price and interest rate risks for NSP-Minnesota 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.

 

NSP-Minnesota maintains trust funds, as required by the NRC, to fund certain costs of nuclear decommissioning. Those investments are exposed to price fluctuations in equity markets and changes in interest rates. However, because the costs of nuclear decommissioning are recovered through NSP-Minnesota rates, fluctuations in investment fair value do not affect NSP-Minnesota’s consolidated results of operations.

 

Results of Operations

 

NSP-Minnesota’s net income was approximately $41.6 million for the first three months of 2005, compared with approximately $68.4 million for the first three months of 2004.

 

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

 

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

 

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Margins from commodity trading activity conducted at NSP-Minnesota are partially redistributed to Public Service Company of Colorado and Southwestern Public Service Company, both wholly owned subsidiaries of Xcel Energy, pursuant to the joint operating agreement (JOA) approved by the FERC.  Margins received pursuant to the JOA are reflected as part of Base Electric Utility Revenue.  Trading revenues are reported net of trading costs in the Consolidated Statements of Income.  Commodity trading costs include fuel, purchased power, transmission and other related costs.  The following table details base electric utility, short-term wholesale and commodity trading revenue and margin:

 

(Millions of dollars)		Base Electric Utility			Short-term Wholesale			Commodity Trading			Consolidated Total
Three months ended March 31, 2005
Electric utility revenue (excluding commodity trading)		$	593		$	29		$	—		$	622
Electric fuel and purchased power		(228		)	(15		)	—			(243		)
Commodity trading revenue		—			—			36			36
Commodity trading costs		—			—			(36		)	(36		)
Gross margin before operating expenses		$	365		$	14		$	—		$	379
Margin as a percentage of revenue		61.6		%	48.3		%	—		%	57.6		%
Three months ended March 31, 2004
Electric utility revenue (excluding commodity trading)		$	555		$	53		$	—		$	608
Electric fuel and purchased power		(200		)	(16		)	—			(216		)
Commodity trading revenue		—			—			42			42
Commodity trading costs		—			—			(41		)	(41		)
Gross margin before operating expenses		$	355		$	37		$	1		$	393
Margin as a percentage of revenue		64.0		%	69.8		%	2.4		%	60.5		%

 

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

 

Base Electric Revenue

 

 

Base Electric Margin

 

 

Short-term wholesale and commodity trading margins decreased approximately $24 million in the first quarter of 2005 compared with the same period in 2004.  The decrease is due to the impact of higher trading volumes in the first quarter of 2004 and a pre-existing contract, which contributed $17 million in the first quarter of 2004 and expired at that time.

 

Natural Gas Utility Margins — The following table details the change in natural gas revenue and margin. The cost of natural gas tends to vary with changing sales requirements and unit cost of natural gas purchases. However, due to purchased natural gas cost recovery mechanisms for retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin.

 

 

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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 Costs — 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 $12.2 million, or 14.9 percent, for the first three months of 2005, compared with the first three months of 2004.  The increase was due primarily to new steam generators at the Prairie Island nuclear plant and software additions placed in service in 2004 or early in 2005.  In addition, renewable development fund amortization increased over 2004.

 

Income tax expense decreased by approximately $13.9 million for the first three months of 2005, compared with the first three months of 2004.  The decrease was primarily due to a decrease in pretax income.  The effective tax rate was 33.7 percent for the first three months of 2005, compared with 33.9 percent for the same period in 2004.

 

Item 4. CONTROLS AND PROCEDURES

 

Disclosure Controls

 

NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the

 

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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-Minnesota’s disclosure controls and procedures are effective.

 

Internal Control Over Financial Reporting

 

No change in NSP-Minnesota’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, 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-Minnesota.  After consultation with legal counsel, NSP-Minnesota 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 11 of NSP-Minnesota’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-Minnesota and there have been no notable changes in the previously reported proceedings.

 

Item 5. OTHER INFORMATION

 

On April 21, 2005, NSP-Minnesota entered into a new five-year $375 million credit facility.  The facility is described in Note 4 and is filed as Exhibit 4.01 hereto.

 

Item 6. EXHIBITS

 

The following Exhibits are filed with this report:

 

4.01*		$375,000,000 Credit Agreement among Northern States Power Company, as Borrower, the several lenders from time to time parties hereto, The Bank of Tokyo-Mitsubishi, LTD., Chicago Branch and CITIBANK, N.A., as documentation agents, The Bank of New York and Wells Fargo Bank, National Association, as Syndication Agents, and JPMorgan Chase Bank, N.A., as administrative agent, dated as of April 21, 2005 (Exhibit 4.01 to Xcel Energy Form 10-Q for the quarter ended March 31, 2005 (file number 001-03034))
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.

* Incorporated by reference.

 

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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 Minnesota corporation)

(Registrant)

 

 

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