Xcel Energy (XEL) 10-Q 1999 Q3 Quarterly report

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

/x/  Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

or

/ /  Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For Quarter Ended September 30, 1999 Commission File Number 1-3034

NORTHERN STATES POWER COMPANY

(Exact name of registrant as specified in its charter)

Minnesota	41-0448030
(State of other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
414 Nicollet Mall, Minneapolis, Minnesota	55401
(Address of principal executive offices)	(Zip Code)

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

None

Former name, former address and former fiscal year, if changed since last report

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes  /x/    No  / /

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

ClassCommon Stock, $2.50 par value Outstanding at October 31, 1999154,798,564 shares

PART 1. FINANCIAL INFORMATION

Item 1. Financial Statements

Northern States Power Company (Minnesota) and Subsidiaries

Consolidated Statements of Income (Unaudited)

	Three Months Ended September 30						Nine Months Ended September 30
	1999			1998			1999			1998
	(Thousands of dollars)
Utility operating revenues
Electric: Retail	$	679,626		$	638,623		$	1,723,908		$	1,637,193
Sales for resale and other		76,811			61,984			178,171			155,635
Gas		57,045			65,841			313,961			313,623
Total		813,482			766,448			2,216,040			2,106,451
Utility operating expenses
Fuel for electric generation		93,752			89,744			245,059			240,850
Purchased and interchange power		168,857			112,621			374,136			282,044
Cost of gas purchased and transported		31,711			32,226			179,011			182,945
Other operation		98,083			95,656			300,993			287,603
Maintenance		39,720			36,795			137,766			131,100
Administrative and general		34,327			36,946			100,123			111,217
Conservation and energy management		19,626			19,403			53,555			52,954
Depreciation and amortization		89,128			84,809			264,708			252,020
Taxes: Property and general		58,875			58,004			173,868			170,308
Current income tax		59,521			69,878			126,335			128,616
Deferred income tax		(470	)		(2,377	)		(8,987	)		(5,643	)
Investment tax credits recognized		(2,214	)		(2,242	)		(6,652	)		(6,653	)
Total		690,916			631,463			1,939,915			1,827,361
Utility operating income		122,566			134,985			276,125			279,090
Other income (expense)
Income (loss) from nonregulated businesses—before interest and taxes		52,818			(5,114	)		45,604			6,854
Allowance for funds used during construction—equity		859			1,562			3,616			5,118
Regulatory reserve—conservation program recovery		—			—			(35,035	)		—
Other utility income (deductions)—net		(1,336	)		(2,187	)		(10,686	)		(7,873	)
Income tax benefit—nonregulated operations and nonoperating items		3,747			18,021			55,733			43,872
Total		56,088			12,282			59,232			47,971
Income before financing costs		178,654			147,267			335,357			327,061
Financing costs
Interest on utility long-term debt		27,496			26,788			74,748			78,258
Other utility interest and amortization		5,958			2,627			18,568			8,668
Nonregulated interest and amortization		31,901			14,445			61,230			40,583
Allowance for funds used during construction—debt		(1,976	)		(2,225	)		(6,151	)		(6,106	)
Total interest charges		63,379			41,635			148,395			121,403
Distributions on redeemable preferred securities of subsidiary trust		3,938			3,938			11,813			11,813
Total financing costs		67,317			45,573			160,208			133,216
Net income		111,337			101,694			175,149			193,845
Preferred stock dividends		1,060			1,060			4,231			4,487
Earnings available for common stock	$	110,277		$	100,634		$	170,918		$	189,358
Average number of common shares outstanding (000's)		153,662			151,026			153,027			150,045
Average number of common and potentially dilutive shares outstanding (000's)		153,723			151,227			153,133			150,284
Earnings per average common share—basic	$	0.72		$	0.67		$	1.12		$	1.26
Earnings per average common share—assuming dilution	$	0.72		$	0.67		$	1.12		$	1.26
Common dividends declared per share	$	0.3625		$	0.3575		$	1.0825		$	1.0675
Consolidated Statements of Retained Earnings (Unaudited)
Balance at beginning of period, as previously reported	$	1,383,257		$	1,346,977		$	1,432,696		$	1,364,875
Net income for period		111,337			101,694			175,149			193,845
Dividends declared:
Cumulative preferred stock		(1,060	)		(1,060	)		(4,231	)		(4,487	)
Common stock		(55,742	)		(54,142	)		(165,822	)		(160,764	)
Pooling of interests with acquired companies		—			6,066			—			6,066
Balance at end of period	$	1,437,792		$	1,399,535		$	1,437,792		$	1,399,535

The Notes to Consolidated Financial Statements are an integral part of the Statements of Income and Retained Earnings.

Northern States Power Company (Minnesota) and Subsidiaries

Consolidated Statements of Cash Flows (Unaudited)

	Nine Months Ended September 30,
	1999			1998
	(Thousands of dollars)
Cash Flows from Operating Activities:
Net Income	$	175,149		$	193,845
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization		307,420			283,173
Nuclear fuel amortization		37,783			34,066
Deferred income taxes		(37,142	)		(7,109	)
Deferred investment tax credits recognized		(6,693	)		(6,885	)
Allowance for funds used during construction—equity		(3,616	)		(5,118	)
Distributions less than equity in earnings of unconsolidated affiliates		(969	)		(36,849	)
Write-down of investments in NRG projects		—			23,410
Regulatory reserve—conservation recovery		35,035			—
Cash provided by changes in certain working capital items		4,903			51,551
Cash provided by changes in other assets and liabilities		12,876			20,856
Net cash provided by operating activities		524,746			550,940
Cash Flows from Investing Activities:
Capital expenditures		(401,771	)		(312,212	)
Increase (decrease) in construction payables		1,515			(2,169	)
Allowance for funds used during construction—equity		3,616			5,118
Investment in external decommissioning fund		(32,649	)		(31,234	)
Equity investments, loans and deposits for nonregulated projects		(141,202	)		(154,194	)
Collection of loans made to nonregulated projects		30,156			77,565
Business acquisitions		(930,185	)		—
Other investments—net		(21,356	)		(17,531	)
Net cash used for investing activities		(1,491,876	)		(434,657	)
Cash Flows from Financing Activities:
Change in short-term debt—net issuances (repayments)		763,555			(33,923	)
Proceeds from issuance of long-term debt—net		594,517			280,485
Repayment of long-term debt		(218,617	)		(128,650	)
Proceeds from issuance of common stock—net		40,659			59,514
Redemption of preferred stock		—			(95,000	)
Dividends paid		(168,687	)		(164,543	)
Net cash provided by (used for) financing activities		1,011,427			(82,117	)
Net increase in cash and cash equivalents		44,297			34,166
Cash and cash equivalents at beginning of period		42,364			54,765
Cash and cash equivalents at end of period	$	86,661		$	88,931

The Notes to Consolidated Financial Statements are an integral part of the Statements of Cash Flows.

Northern States Power Company (Minnesota) and Subsidiaries

Consolidated Balance Sheets (Unaudited)

	September 30, 1999			December 31, 1998
	(Thousands of dollars)
ASSETS
Utility Plant
Electric	$	7,387,236		$	7,199,843
Gas		928,796			884,182
Other		383,590			365,101
Total		8,699,622			8,449,126
Accumulated provision for depreciation		(4,389,452	)		(4,155,641	)
Nuclear fuel		1,000,591			975,030
Accumulated provision for amortization		(911,064	)		(873,281	)
Net utility plant		4,399,697			4,395,234
Current Assets
Cash and cash equivalents		86,660			42,364
Customer accounts receivable—net		330,549			253,559
Unbilled utility revenues		110,270			139,098
Other receivables		68,669			105,116
Fossil fuel inventories—at average cost		63,336			58,806
Materials and supplies inventories—at average cost		169,654			110,267
Prepayments and other		63,046			44,855
Total current assets		892,184			754,065
Other Assets
Nonregulated property—net of accumulated depreciation		1,236,252			282,524
Equity investments in nonregulated projects		1,000,187			862,596
External decommissioning fund and other investments		516,584			479,402
Regulatory assets		275,861			331,940
Notes receivable from nonregulated projects		96,839			106,427
Intangible assets—net of accumulated amortization		124,858			95,915
Long-term prepayments, deferred charges and receivables		142,685			88,194
Total other assets		3,393,266			2,246,998
TOTAL ASSETS	$	8,685,147		$	7,396,297
LIABILITIES AND EQUITY
Capitalization
Common stock equity:
Common stock and premium—authorized: 1999 350,000,000 and 1998 350,000,000 shares of $2.50 par value, issued shares: 1999 154,358,267 and 1998 152,696,971	$	1,196,783		$	1,156,067
Retained earnings		1,437,792			1,432,696
Leveraged common stock held by ESOP		(13,332	)		(18,503	)
Accumulated other comprehensive income		(73,614	)		(89,014	)
Total common stock equity		2,547,629			2,481,246
Cumulative preferred stock and premium—authorized 7,000,000 shares of $100 par value; outstanding shares: 1999 1,050,000 and 1998 1,050,000 without mandatory redemption		105,340			105,340
Mandatorily redeemable preferred securities of subsidiary trust—guaranteed by NSP*		200,000			200,000
Long-term debt		2,393,364			1,851,146
Total capitalization		5,246,333			4,637,732
Current Liabilities
Long-term debt due within one year		61,103			227,600
Other long-term debt potentially due within one year		141,600			141,600
Short-term debt—utility		179,194			114,273
Short-term debt—nonregulated (mainly temporary NRG project financing)		824,190			125,557
Accounts payable		284,266			271,799
Taxes accrued		219,718			170,274
Interest accrued		49,556			38,836
Dividends payable on common and preferred stocks		57,015			55,650
Other accrued liabilities		102,391			86,673
Total current liabilities		1,919,033			1,232,262
Other Liabilities
Deferred income taxes		782,051			814,983
Deferred investment tax credits		121,106			128,444
Regulatory liabilities		398,912			372,239
Postretirement and other benefit obligations		132,944			129,514
Other long-term obligations and deferred income		84,768			81,123
Total other liabilities		1,519,781			1,526,303
Commitments and Contingent Liabilities (See Note 4)
TOTAL LIABILITIES AND EQUITY	$	8,685,147		$	7,396,297

*The primary asset of NSP Financing I, a subsidiary trust of NSP, is $200 million principal amount of the Company's 7.875% Junior Subordinated Debentures due 2037.

The Notes to Consolidated Financial Statements are an integral part of the Balance Sheets.

Northern States Power Company (Minnesota) and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

    In the opinion of management, the accompanying unaudited financial statements contain all adjustments necessary to present fairly the financial position of Northern States Power Company (Minnesota) (NSP-Minnesota) and its subsidiaries (collectively, NSP) as of Sept. 30, 1999 and Dec. 31, 1998, the results of its operations for the three and nine months ended Sept. 30, 1999 and 1998, and its cash flows for the nine months ended Sept. 30, 1999 and 1998. Due to the seasonality of NSP's electric and gas sales and variability of nonregulated operations, quarterly results are not necessarily an appropriate base from which to project annual results.

    The accounting policies followed by NSP are set forth in Note 1 to the financial statements in NSP's Annual Report on Form 10-K for the year ended Dec. 31, 1998 (1998 Form 10-K). The following notes should be read in conjunction with such policies and other disclosures in the 1998 Form 10-K.

1.  Proposed Business Combination

    On March 24, 1999, NSP and New Century Energies, Inc. (NCE) agreed to merge and form a new entity, Xcel Energy Inc. For more discussion of this proposed business combination, see Part II, Item 5—Other Information of this report.

    At Sept. 30, 1999, NSP had deferred $18.9 million of merger costs, based on NSP's plan to request regulatory amortization and rate recovery over future periods.

2.  Business Developments

NRG Energy, Inc. (NRG)—In April 1999, NRG completed its acquisition of the Somerset power station for approximately $55 million from Eastern Utilities Associates. The Somerset station, located in Somerset, Mass., includes two coal-fired generating facilities and two aeroderivative combustion turbine peaking units with a nominal capacity rating of 160 MW. NRG owns a 100 percent interest in the project.

    In May 1999, NRG and Dynegy acquired the Encina generating station and 17 combustion turbines for $356 million from San Diego Gas & Electric Company. The facilities, which have a combined capacity of 1,218 MW, are located near Carlsbad and San Diego, Calif. NRG and Dynegy each own a 50 percent interest in the joint venture.

    In June 1999, NRG completed its acquisition of the Huntley and Dunkirk generating stations from Niagara Mohawk Power Corp. for $355 million. The two coal-fired plants are located near Buffalo, N.Y., and have a combined summer capacity of 1,360 MW. NRG owns a 100 percent interest in the project.

    In June 1999, NRG completed its acquisition of the Arthur Kill generating station and the Astoria gas turbine site for $505 million from Consolidated Edison Company. These facilities, which are located in the New York City area, have a combined summer capacity of 1,456 MW. NRG owns a 100 percent interest in the project.

    In July 1999, NRG reached agreement to purchase gas and oil electric generating stations with a combined capacity of 2,235 MW for $460 million from Connecticut Light & Power Company (CL&P). The facilities are located throughout Connecticut. The acquisition is expected to close in the fourth quarter of 1999, pending regulatory approvals.

    In August 1999, NRG agreed to sell a portion of its ownership interest in Cogeneration Corp. of America (CogenAmerica) to Calpine Corp. for $25 per share. As a result of the sale, NRG will reduce its ownership stake in CogenAmerica from 45 percent to 20 percent. NRG expects to close on the sale in the fourth quarter of 1999 and record a gain of about 2 cents per share.

    In August 1999, a U.S. district judge issued a settlement order clearing the way for Louisiana Generating LLC to be confirmed as the winning bidder for Cajun Electric Power Cooperative's 1,700 MW of fossil-fueled generation. Confirmation of Louisiana Generating's approximate $1 billion offer by a U.S. bankruptcy judge is expected in the fourth quarter of 1999. Cajun sought bankruptcy protection in December 1994 amid financial problems related to an investment in the River Bend Nuclear Power Plant. The transaction is subject to various regulatory approvals. NRG currently owns 100 percent of Louisiana Generating. At the current time, NRG is evaluating ownership options regarding the Cajun acquisition. It is expected that output from the base-load Cajun facility will be sold principally under long-term contracts and that the acquisition will be completed in the first quarter of 2000.

    In October 1999, NRG purchased the 1,700 MW oil and gas-fired Oswego generating station, located in Oswego, N.Y., for approximately $85 million from Niagara Mohawk Power Corporation and Rochester Gas and Electric Corporation.

    In October 1999, NRG entered into a Standard Offer Service Wholesale Sales Agreement with CL&P in which NRG will supply CL&P with 35% of its standard offer service load during 2000, 40% during 2001 and 2002 and 45% during 2003. NRG expects the transaction to close during the fourth quarter of 1999.

Independent Transmission Company (ITC)—In April 1998, NSP announced its intention to form an ITC unaffiliated with the rest of its utility operations. As originally proposed, NSP anticipated divesting its transmission assets to an ITC. In light of the proposed merger with NCE, divestiture of transmission assets would appear to trigger adverse tax and accounting consequences. As an alternative to divestiture of its transmission assets, NSP has joined (in which it will transfer control, but not ownership of its transmission assets) the Midwest Independent System Operator (ISO). The Midwest ISO expects to be operational by the middle of 2001.

    In April 1998, Wisconsin state legislators enacted a law which includes provisions that require the Public Service Commission of Wisconsin (PSCW) to order a public utility that owns transmission facilities in Wisconsin to transfer control of its transmission facilities to an ISO or divest its interest in its transmission facilities to an ITC if the public utility has not already transferred control to an ISO or divested to an ITC by June 30, 2000. NSP has joined the Midwest ISO and will file for PSCW approval by March 2000.

Nuclear Management Company (NMC)—In February 1999, NSP, Wisconsin Electric Power Co. (WE) and Wisconsin Public Service Corp. (WPS) established an NMC. In October 1999, Alliant Energy received approval from the SEC to join the NMC. During the fourth quarter of 1999, NMC member utilities will consider applying to the Nuclear Regulatory Commission (NRC) to transfer plant operating licenses to the NMC. The four partners, including NSP, will retain ownership of the nuclear plant assets. License transfer would allow the NMC to become an operating company in 2000. The request to transfer operating licenses requires approval from each of its members' board of directors, as well as state and federal regulators, including the NRC. As of early November 1999, the NSP, WE and WPS boards of directors had approved the transfer of the nuclear operating licenses for their respective companies to the NMC.

Viking Gas—During the second quarter of 1999, Viking Gas reached a settlement with TransCanada Pipelines, Ltd. and NICOR, Inc., Viking's former partners in the Viking Voyageur pipeline project, which was cancelled in 1998. Viking Gas purchased all engineering and other studies related to the Voyageur project. Since the studies obtained through the settlement have continuing value to Viking Gas the payment has been capitalized as plant.

Black Dog—In September 1999, NSP filed with the MPUC its plan to "repower" two coal-fired units at its Black Dog plant in Burnsville, Minn. with natural gas combined-cycle technology. The MPUC and other government agencies will review the merits of the project. Currently, Black Dog units 1 and 2 have a maximum capacity of 175 MW. Under NSP's proposal, the units would have a maximum capacity of 290 MW. The total cost of the project is estimated to be $156 million. If approved, the repowered units could begin operating in mid-2002.

Natrogas Inc. Merger—In August 1999, NSP and Natrogas announced their intentions to merge. Natrogas, based in Minneapolis, has approximately 20,000 natural gas and propane customers in four states. The transaction is pending regulatory approval and is expected to be structured as a tax-free reorganization for income tax purposes and will be accounted for using a pooling of interests method. Prior period financial statements will not be restated due to immateriality.

3.  Regulation and Rate Matters

FERC Transmission Rate Case—As discussed in NSP's 1998 Form 10-K, in the first quarter of 1998, NSP filed wholesale electric point-to-point and network integration transmission service (NTS) rate cases with the Federal Regulatory Energy Commission (FERC). In March 1999, NSP filed an offer of settlement which would resolve virtually all issues in the two cases. The offer of settlement provides an approximate two percent reduction in point-to-point rates, which combined with anticipated reductions in non-firm discounting, is expected to have little or no impact on annual revenue. In addition, the settlement calls for an annual increase of approximately $1 million in ancillary service revenues. Finally, the settlement places a cap on NSP's annual NTS payment liabilities to its five current NTS customers at $10 million per year. The point-to-point and ancillary rates would be effective June 1, 1998. The offer also includes a three-year moratorium period on future transmission rate changes. In October 1999, the affected customers and NSP filed a motion asking the FERC to approve the settlement promptly so it can be implemented in 1999.

Midcontinent Area Power Pool (MAPP) Transmission Tariff—In May 1999, MAPP members voted to approve a MAPP regional transmission service tariff which will prospectively supercede MAPP members' individual electric transmission service tariffs for most wholesale transactions. The proposed MAPP tariff was filed with the FERC in July 1999. MAPP proposed the new tariff be effective 90 days after a FERC order accepting the tariff for filing. NSP estimates the new MAPP regional transmission service tariff would reduce NSP's year 2000 pretax earnings by between $5 million and $16 million due to lower revenues and/or higher costs. NSP and several other parties filed protests to the MAPP tariff, asking the FERC to modify and/or delay implementation of the new tariff. The tariff is pending FERC action, which is expected later in 1999.

Viking Rate Case—In June 1998, Viking filed a rate case with the FERC, requesting a $3 million annual rate increase. In March 1999, Viking filed an agreement of settlement which resolved all issues in the case. The settlement provides Viking an annual rate increase of approximately $1.3 million, or 6 percent, effective Jan. 1, 1999, and a four year phased rate roll-in for the cost of Viking's 1996 and 1997 expansion projects. FERC approved this settlement in May 1999.

NSP-Wisconsin—On Oct. 28, 1999 the PSCW approved NSP-Wisconsin's application for authority to maintain base retail electric and natural gas service rates in Wisconsin at current levels through 2001. NSP-Wisconsin is required to make a biennial rate filing in odd-numbered years. Current rates were placed in effect in September 1998.

4.  Commitments and Contingent Liabilities

Conservation Improvement Program (CIP) 1998—In the second quarter of 1999, NSP recorded a charge to earnings of $35 million (before tax), or approximately 14 cents per share, due to the potential disallowance of rate recovery for accrued conservation program incentives based on a June 24, 1999, decision by the MPUC.

    State law requires Minnesota utilities to fund and participate in various energy conservation programs and initiatives. After NSP's last electric rate case in 1993, NSP incurred higher levels of conservation program expenditures, and in 1994 requested MPUC approval of a rate recovery mechanism to avoid a significant delay between the incurring of CIP costs and their recovery in rates. Since 1995, the MPUC has approved the use of this special rate recovery mechanism to provide timely recovery (for NSP and other Minnesota public utilities) of CIP costs and also to provide conservation program incentives, including: reimbursement of a portion of electric margins lost due to energy conservation, reimbursement of certain load management discounts provided to customers under CIP programs, and performance incentives based on the success of NSP's conservation programs.

    MPUC procedures require an annual filing by each utility for MPUC approval before implementing the new conservation rate adjustment. For NSP, this annual filing has typically occurred in the second quarter of the year, and the rate recovery levels have been adjusted each July 1 and then continued until the following June 30. The requested recovery levels approved for NSP since 1995 have included recovery of budgeted levels of conservation related items recoverable in the current year.

    In late 1998, the MPUC considered a proposal to discontinue recovery of lost margins and load management discounts related to conservation programs for NSP and other Minnesota public utilities. The MPUC declined to take such action, but put Minnesota utilities on notice that there may be significant changes, including elimination of lost margin and load management discount recovery for programs, beginning January 1999.

    On June 24, 1999, the MPUC held a hearing to consider NSP's April 1999 conservation rate adjustment filing. The MPUC voted 3-2 to deny NSP recovery of its lost margins, load management discounts and incentives related to 1998 that were associated with state-mandated programs for electric energy conservation. On July 27, 1999, the MPUC issued an order formalizing its conservation decision. The MPUC decision did not appear to affect the recovery of CIP program expenditures. Also, the MPUC did not address or change 1999 conservation incentive recovery levels.

    NSP has requested reconsideration of the MPUC decision and, if necessary, may seek court review. The MPUC's decision appears to contradict previous orders and reduce NSP's 1998 rates retroactively. However, due to the uncertainty of the challenge, NSP established a regulatory reserve of $35 million (before tax) in the second quarter of 1999 for all income recorded for 1998 accruals of lost margins, load management discounts and performance incentives. On Oct. 4, 1999, the MPUC granted NSP's request for reconsideration for the purpose of more fully reviewing its decision on disallowance of 1998 conservation incentive recovery. A final decision on 1998 conservation incentive recovery is possible at a MPUC meeting currently scheduled for Nov. 18, 1999.

CIP Recovery 1999—NSP has been working with the Minnesota Department of Commerce and other parties (Parties) to address the MPUC's concerns for conservation program incentives for 1999 and subsequent years. On Nov. 1, 1999, the Parties filed a proposal which would replace the current rate recovery of lost margins, load management discounts and performance incentives with a new shared savings incentive process, including a maximum payment cap of 30 percent of expenditures, effective Jan. 1, 1999. On Nov. 8, 1999, NSP filed its proposal to accept the Parties' recommendation with a revision to continue recovery of load management discounts offered to customers. The MPUC is expected to consider these proposals for NSP's 1999 conservation program recovery and reach a final decision later this year.

    Under the Parties' proposal NSP's conservation incentive recovery for 1999 would be based on performance with a maximum potential recovery of about $9 million for the year. NSP's proposal, which adds to the Parties' proposal the recovery of $6 million of load management discounts, would result in a maximum potential conservation incentive recovery of about $15 million for 1999.

    NSP is currently accruing income for 1999 conservation program incentives at the $27 million annual level proposed in a filing earlier this year. Although the MPUC has not approved any proposals, NSP intends to adjust the amount of conservation incentives accrued for 1999 to the level likely to be recovered under the NSP proposal. If the NSP proposal is approved by the MPUC, 1999 conservation incentive recovery is estimated to be in the range of $9 million to $13 million, depending on the ultimate performance of NSP's conservation programs for the year. If the Parties' proposal is approved, 1999 conservation incentive recovery is estimated to be in the range of $3 million to $7 million, again dependent on performance.

    Depending on the MPUC's decision and the level of program performance vs. targets, the adjustment to accrued conservation incentives for 1999 is expected to result in a reduction in NSP's earnings for the fourth quarter of 1999 of 5 cents to 9 cents per share. Approximately three-fourths of this reduction relates to conservation incentives accrued during the first nine months of 1999.

Rate Investigation—On July 27, 1999, the MPUC issued an order requiring an investigation into the reasonableness of NSP's retail electric rates in Minnesota. As required by the rate investigation order, NSP filed a written explanation and detailed schedules showing the individual adjustments to the 1998 and projected 1999 normalized rate base, revenue and expense statements, and the cost of capital that are necessary to reconcile 1998 normalized and 1999 projected returns on equity to the 11.47 percent authorized return on equity. As required, NSP also filed an explanation of why it believes its current rates continue to be just and reasonable.

    In its filings, NSP stated that it believes that its rates are reasonable and that under a number of projected scenarios for 1999, it does not expect to exceed its allowed return on equity for that year. Interested parties have until late November 1999 to review NSP's filings and submit comments and recommendations.

    The rate investigation does not authorize the MPUC to reduce base rates, but only to determine whether a rate proceeding should be initiated. If, after hearing, the MPUC finds that a rate proceeding should be initiated, it must then, under Minnesota law, allow the utility 120 days after the MPUC's order to file its case. If a rate case is initiated, NSP's rates would first become subject to refund, as interim rates, 60 days after NSP files its rate case.

Nuclear Insurance—The circumstances set forth in Note 14 to NSP's financial statements in NSP's 1998 Form 10-K appropriately represent, in all material respects, the current status of commitments and contingent liabilities regarding public liability for claims resulting from any nuclear incident.

5.  Short-Term Borrowings

    At Sept. 30, 1999, NSP and its subsidiaries had approximately $1.0 billion of short-term debt outstanding at a weighted average interest rate of 6.35 percent. NSP-Minnesota had $179 million in short-term commercial paper borrowings outstanding at a composite rate of 5.37 percent. Included in NSP's subsidiary debt is approximately $614 million of short-term NRG project financing, which is expected to be refinanced with long-term project debt. NSP has regulatory approval for up to $1.2 billion in short-term debt levels.

    As of Sept. 30, 1999, NSP-Minnesota had a $300 million revolving credit facility under a commitment fee arrangement. This facility provides short-term financing in the form of bank loans, letters of credit and support for commercial paper sales. In addition to NSP-Minnesota lines, at Sept. 30, 1999, commercial banks provided credit lines of approximately $361 million to wholly owned subsidiaries of NSP with approximately $210 million in borrowings outstanding, mainly to NRG.

6.  Other Comprehensive Income

    NSP's other comprehensive income consists of foreign currency translation adjustments related to NRG's investments in international projects and changes in the fair value of investments in certain marketable securities. Other comprehensive income items for the three and nine month ended periods of 1999 and 1998 are listed below.

	3 Mos. Ended
Increase / (decrease) in Equity
	9/30/99			9/30/98
	Millions of Dollars
Currency translation adjustments	$	(6.7	)	$	(6.7	)
Marketable securities:
Holding loss during period—net of tax		(2.5	)		0.0
Loss realized during period—net of tax		0.0			0.0
Total	$	(9.2	)	$	(6.7	)
	9 Mos. Ended
Increase / (decrease) in Equity
	9/30/99			9/30/98
	Millions of Dollars
Currency translation adjustments	$	13.9		$	(29.8	)
Marketable securities:
Holding loss during period—net of tax		(0.5	)		0.0
Loss realized during period—net of tax		2.0			0.0
Total	$	15.4		$	(29.8	)

7.  Segment Information

    NSP has four reportable segments: Electric Utility, Gas Utility and two of its wholly owned, nonregulated subsidiaries, NRG and EMI. Segment information for the third quarter and nine month ended periods of 1999 and 1998 are as follows:

Business Segments

3 Mos. Ended 9/30/99	Operating Revenues from External Customers		Inter- Segment Revenues			Segment Net Income (Loss)
	(Thousands of dollars)
Electric Utility	$	756,234	$	202		$	95,540
Gas Utility		57,042		1,612			(9,228	)
NRG		139,758		216			27,607
EMI		9,714		0			(2,478	)
All Other		7,480		0			(104	)
Reconciling Eliminations		0		(1,824	)		0
Consolidated Total(a)	$	970,228	$	206		$	111,337

3 Mos. Ended 9/30/98	Operating Revenues from External Customers		Inter- Segment Revenues			Segment Net Income (Loss)
	(Thousands of dollars)
Electric Utility	$	700,458	$	149		$	111,092
Gas Utility		65,839		4,617			(3,813	)
NRG		24,688		359			(4,775	)
EMI		14,007		0			(1,805	)
All Other		7,173		118			995
Reconciling Eliminations		0		(5,092	)		0
Consolidated Total(a)	$	812,165	$	151		$	101,694

9 Mos. Ended 9/30/99	Operating Revenues from External Customers		Inter- Segment Revenues			Segment Net Income (Loss)
	(Thousands of dollars)
Electric Utility	$	1,901,475	$	604		$	145,474
Gas Utility		313,861		3,267			6,112
NRG		236,892		963			29,008
EMI		37,796		0			(4,912	)
All Other		21,991		0			(533	)
Reconciling Eliminations		0		(4,130	)		0
Consolidated Total(a)	$	2,512,015	$	704		$	175,149

9 Mos. Ended 9/30/98	Operating Revenues from External Customers		Inter- Segment Revenues			Segment Net Income (Loss)
	(Thousands of dollars)
Electric Utility	$	1,792,234	$	595		$	183,016
Gas Utility		313,542		7,984			5,762
NRG		73,788		1,041			8,284
EMI		36,727		0			(6,308	)
All Other		21,466		433			3,091
Reconciling Eliminations		0		(9,378	)		0
Consolidated Total(a)	$	2,237,757	$	675		$	193,845

(a)

The consolidated total revenue amounts represent the sum of utility and nonregulated amounts.

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

    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:

•

general economic conditions, including their impact on capital expenditures;



•

business conditions in the energy industry;



•

competitive factors;



•

unusual weather;



•

changes in federal or state legislation;



•

regulation;



•

issues relating to Year 2000 remediation efforts;



•

the higher degree of risk associated with NSP's nonregulated businesses as compared to NSP's regulated business;



•

the items set forth below under "Factors Affecting Results of Operations";



•

currency translation and transaction adjustments;



•

regulatory delays or conditions imposed by regulatory agencies in approving the proposed merger with NCE;



•

and the other risk factors listed from time to time by NSP in reports filed with the SEC, including Exhibit 99.01 to this report on Form 10-Q for the quarter ended Sept. 30, 1999.

RESULTS OF OPERATIONS

    On March 24, 1999, NSP and NCE agreed to merge and form a new entity, Xcel. For more discussion of this proposed business combination, see Part II, Item 5—Other Information and Note 1 to the Financial Statements of this report. The following discussion and analysis is based on the financial condition and operations of NSP and does not reflect the potential effects of the combination between NSP and NCE.

    NSP's earnings per share, assuming dilution, (EPS) for the three and nine month periods ending Sept 30, 1999 and 1998 were as follows:

	3 mos. Ended					9 Mos. Ended
Earnings per share:
	9/30/99		9/30/98			9/30/99		9/30/98
Regulated	$	0.56	$	0.70		$	0.96	$	1.23
Nonregulated		0.16		(0.03	)		0.16		0.03
Total	$	0.72	$	0.67		$	1.12	$	1.26

Factors Affecting Results of Operations

    In addition to items noted in the 1998 Form 10-K and the Notes to the Financial Statements, the historical and future trends of NSP's operating results are affected by the following factors:

Conservation program recovery—NSP recorded a charge of $35 million (before tax) or approximately 14 cents per share in the second quarter of 1999 as a result of a potential MPUC disallowance of rate recovery of accrued 1998 conservation program incentives. See Note 4 to the Financial Statements for more information.

Estimated Impact of Weather on Regulated Earnings—NSP estimates electric and gas utility sales levels under normal weather conditions and analyzes the approximate effect of variations from historical average temperatures on actual sales levels. The following summarizes the estimated impact of weather on actual utility operating results (in relation to sales under normal weather conditions):

	Increase (Decrease)
Earnings per Share For Periods Ending Sept. 30:	Actual 1999 vs Normal			Actual 1998 vs Normal			Actual 1999 vs 1998
Quarter Ended	$	0.04		$	0.04		$	0.00
Nine Months Ended	$	(0.01	)	$	(0.04	)	$	0.03

Sales Growth—The following table summarizes NSP's growth in actual electric and gas sales and growth on a weather normalized (W/N) basis for the three-month and the nine-month periods ended Sept. 30, 1999, as compared with the same periods in 1998. NSP's weather normalization process removes the estimated impact on sales of temperature variations from historical averages.

	3 Mos. Ended				9 Mos. Ended
	Actual		W/N		Actual		W/N
Electric Residential	3.3	%	3.9	%	3.7	%	3.4	%
Electric Industrial and Commercial	2.5	%	2.7	%	1.3	%	1.3	%
Total Electric Retail	2.8	%	3.0	%	1.9	%	1.9	%
Electric Resale	5.3	%	NA		17.5	%	NA
Firm Gas Sales	4.2	%	NA		13.4	%	2.4	%

Purchased Capacity and Energy Costs—During July 1999, NSP's service territory experienced extremely high temperatures, which drove customer usage to record levels. With NSP's power plants operating at maximum available capacity, market conditions forced NSP to purchase the power necessary to serve customer demand at very high costs. This situation was exacerbated by the inability to use 200 MW of capacity from NSP's King plant due to water discharge temperature limitations. NSP's fuel clause billing adjustment process in Minnesota does not allow for the recovery of capacity charges above the levels reflected in base rates established in 1993, NSP's last general electric rate case in Minnesota. In addition, NSP-Wisconsin does not have an automatic fuel clause to recover increased energy and capacity charges from customers. Without the ability to fully recover these unusually high energy and capacity costs, the otherwise favorable earnings effects of higher sales for the quarter were offset by 7 cents per share compared with 1998.

Year 2000 (Y2K) Readiness—This information is designated as a "Year 2000 Readiness Disclosure." NSP is incurring significant costs to modify or replace existing technology, including computer software, for uninterrupted operation in the year 2000 and beyond as discussed in NSP's 1998 Form 10-K.

    NSP is on schedule for completion of its Y2K project.

•

On Sept. 30, 1999, 99 percent of both NSP's mission-critical and non-critical systems and processes were Y2K ready.



•

On June 30, 1999, NSP completed its contingency plans as required by the North American Electric Reliability Council. NSP's contingency plans are comprehensive and include the following actions: the establishment of back-up or alternative data and voice communications, increasing generation reserves, coordination with government agencies, increased staffing levels during Y2K critical time periods and conducting readiness drills.



•

By Dec. 31, 1999, NSP expects to have completed implementation and testing of all applications.

    Since the start of the Y2K project in 1996 through Sept. 30, 1999, NSP has spent approximately $20.3 million for Y2K efforts, which (except for a portion deferred for approved rate recovery) has been expensed as incurred. The additional development and remediation costs necessary for NSP to prepare for Y2K is estimated to be approximately $4.1 million.

Accounting Change—In June 1998, the FASB issued Statement of Financial Accounting Standard (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." This statement requires that all derivatives be recognized at fair value in the balance sheet and all changes in fair value be recognized currently in earnings or deferred as a component of other comprehensive income, depending on the intended use of the derivative, its resulting designation and its effectiveness. NSP plans to adopt this standard in 2001, as required. NSP has not yet determined the potential impact of implementing this statement.

Third Quarter 1999 vs. Third Quarter 1998

Utility Operating Results

Electric revenues for the third quarter of 1999 increased $55.8 million, or 8.0 percent, compared with the third quarter of 1998. The following table summarizes the change in electric revenues for the third quarter.

	1999 vs. 1998
	Millions of dollars
Retail sales growth (excluding weather impact)	$	18.3
Weather impact		(1.4	)
Sales for resale		17.0
Conservation program recovery		(0.8	)
Fuel cost recovery		22.8
Rate changes		1.7
Transmission and other		(1.8	)
Total electric revenue increase	$	55.8

Electric margin equals electric revenue minus electric fuel and purchased power costs. The table below summarizes the change in electric margin for the third quarter.

	1999 vs. 1998
	Millions of dollars
Retail sales growth (excluding weather impact)	$	13.4
Weather impact		(1.3	)
Sales for resale		0.1
Conservation program recovery		(0.8	)
Rate changes		1.7
Unrecoverable energy and capacity costs		(16.8	)
Transmission and other		(0.7	)
Total electric margin decrease	$	(4.4	)

Gas revenues for the third quarter of 1999 decreased $8.8 million, or 13.4 percent, compared with 1998. The following table summarizes the change in gas revenues for the third quarter.

	1999 vs. 1998
	Millions of dollars
Sales growth (excluding weather impact)	$	(1.3	)
Weather impact		2.6
Rate changes		(0.3	)
Black Mountain—1998 YTD merger adjustment		(3.8	)
Cost of gas recovery		(6.4	)
Other		0.4
Total gas revenue decrease	$	(8.8	)

Gas margin equals gas revenue minus the cost of purchased gas. The table below summarizes the change in gas margin for the third quarter.

	1999 vs. 1998
	Millions of dollars
Sales growth (excluding weather impact)	$	(1.0	)
Weather impact		1.0
Black Mountain—1998 YTD merger adjustment		(2.9	)
Purchased gas cost adjustment		(4.0	)
Rate changes and other		(1.4	)
Total gas margin decrease	$	(8.3	)

Other operation, Maintenance and Administrative and general expenses together increased $2.7 million, or 1.6 percent, compared with the third quarter of 1998. The increases are primarily due to the amortization of deferred NTS costs in Wisconsin and increased tree trimming and line maintenance expense.

Depreciation and amortization expense increased $4.3 million, or 5.1 percent, compared with the third quarter of 1998. The increase is mainly due to increased plant in service.

Utility interest expense increased $4.0 million in the third quarter of 1999 compared with the third quarter of 1998 primarily due to an increase in short-term commercial paper borrowings.

Nonregulated Business Results

    The following table summarizes NSP's nonregulated business results in the aggregate, including consolidated subsidiaries and unconsolidated affiliates.

	3 Mos. Ended
	9/30/99			9/30/98
	(Thousands of dollars, except EPS)
Operating revenues	$	156,952		$	45,868
Equity in project earnings		30,797			28,373
Operating and development expenses		(137,151	)		(80,432	)
Other income (expense)		2,220			1,077
Income (loss) before interest & taxes		52,818			(5,114	)
Interest expense		(31,901	)		(14,445	)
Income tax benefit and credits		4,108			13,974
Net income (loss)	$	25,025		$	(5,585	)
Nonregulated earnings (loss) per share	$	0.16		$	(0.03	)

    NSP's nonregulated operations include diversified businesses, as described below.

•

NRG's primary business is independent power production, commercial and industrial heating and cooling, and energy-related refuse-derived fuel production.



•

EMI's primary business is custom energy services and sales.



•

Eloigne invests in affordable housing projects.



•

Seren Innovations provides communications and data services.

    The following table summarizes the earnings contributions of NSP's nonregulated businesses:

	3 Mos. Ended
	9/30/99			9/30/98
NRG	$	0.18		$	(0.03	)
Eloigne Company		0.01			0.01
EMI, Inc.		(0.02	)		(0.01	)
Seren Innovations		(0.02	)		(0.01	)
Other		0.01			0.01
Total	$	0.16		$	(0.03	)

NRG—NRG's 1999 results for the third quarter reflect increased earnings due to acquisitions in the Northeast region of the United States, which closed during the second quarter of 1999 as discussed in Note 2 to the Financial Statements. Partially offsetting these increased earnings were the effects of cooler-than-normal weather on California projects during the third quarter of 1999 and additional interest expense.

    During the third quarter of 1998, NRG recorded a charge of approximately $20 million ($13.3 million after tax) to write down its investment in a proposed 400 MW coal-fired power station in West Java, due to the political and economic instability in Indonesia. NRG also recorded a $3.3 million charge ($2 million after tax) for other project write-downs. These charges together reduced NRG earnings for both the third quarter and nine-months ended Sept. 30, 1998 by approximately 10 cents per share.

    NRG is a public company and is subject to the informational reporting requirements of the Securities Exchange Act of 1934. Further information about NRG may be obtained from its Form 10-Q for the quarter ended Sept. 30, 1999.

EMI—EMI's losses for the third quarter of 1999 were greater than the third quarter 1998 losses primarily due to lower energy services margin as a result of timing of contract signing and construction progress.

Seren—Seren's build-out of its broadband communications network in St. Cloud, Minn., and initial construction in northern California resulted in losses for the third quarter of 1999, which is consistent with Seren's business plan.

First Nine Months 1999 vs. First Nine Months 1998

Utility Operating Results

Electric revenues for the first nine months of 1999 increased $109.3 million, or 6.1 percent, compared with the first nine months of 1998. The following table summarizes the change in electric revenues.

	1999 vs. 1998
	Millions of dollars
Retail sales growth (excluding weather impact)	$	37.1
Weather impact		0.7
Sales for resale		30.7
Conservation program recovery		(2.3	)
Fuel cost recovery		42.3
Rate changes		5.4
Transmission and other		(4.6	)
Total electric revenue increase	$	109.3

Electric margin equals electric revenue minus electric fuel and purchased power costs. The following table summarizes the change in electric margin for the first nine months.

	1999 vs. 1998
	Millions of dollars
Retail sales growth (excluding weather impact)	$	25.6
Weather impact		0.5
Sales for resale		4.0
Conservation program recovery		(2.3	)
Rate changes		5.4
Unrecoverable energy and capacity costs		(19.1	)
Transmission and other		(1.1	)
Total electric margin increase	$	13.0

Gas revenues for the first nine months of 1999 increased $0.3 million, or 0.1 percent, compared with the first nine months of 1998. The table below summarizes the change in gas revenues.

	1999 vs. 1998
	Millions of dollars
Sales growth (excluding weather impact)	$	3.4
Weather impact		19.8
Rate changes		1.1
Cost of gas recovery		(18.9	)
Other		(5.1	)
Total gas revenue increase	$	0.3

Gas margin equals gas revenue minus the cost of purchased gas. The table below summarizes the change in gas margin for the first nine months.

	1999 vs. 1998
	Millions of dollars
Sales growth (excluding weather impact)	$	1.3
Weather impact		6.3
Rate changes		1.1
Purchased gas cost and other		(4.5	)
Total gas margin increase	$	4.2

Other operation, Maintenance and Administrative and general expenses together increased $9.0 million, or 1.7 percent, compared with the first nine months of 1998. The increases are primarily due to customer service and reliability initiatives, amortization of deferred NTS costs in Wisconsin and an increase in uncollectible accounts. These cost increases were partially offset by lower administrative and general expenses (primarily due to lower employee benefit costs).

Depreciation and amortization expense increased $12.7 million, or 5.0 percent, compared with the first nine months of 1998. The increase is mainly due to increased plant in service.

Utility interest expense increased $6.4 million in the first nine months of 1999 compared with the first nine months of 1998 primarily due to an increase in short-term borrowings, partially offset by a decrease in interest on long term debt as a result of timing between debt retirements and refinancing issuances.

Nonregulated Business Results

    The following table summarizes NSP's nonregulated business results in the aggregate, including consolidated subsidiaries and unconsolidated affiliates.

	9 Mos. Ended
	9/30/99			9/30/98
	(Thousands of dollars, except EPS)
Operating revenues	$	296,679		$	131,981
Equity in project earnings		45,109			56,452
Operating and development expenses		(301,725	)		(183,863	)
Other income (expense)		5,541			2,284
Income before interest & taxes		45,604			6,854
Interest expense		(61,230	)		(40,583	)
Income tax benefit and credits		39,189			38,796
Net income	$	23,563		$	5,067
Nonregulated earnings per share	$	0.16		$	0.03

    The following table summarizes the earnings contributions of NSP's nonregulated businesses.

	9 Mos. Ended
	9/30/99			9/30/98
NRG	$	0.19		$	0.06
Eloigne Company		0.04			0.03
EMI, Inc.		(0.03	)		(0.04	)
Seren Innovations		(0.04	)		(0.01	)
Other		0.00			(0.01	)
Total	$	0.16		$	0.03

NRG—NRG's earnings for the first nine months of 1999 increased compared with 1998, primarily due to acquisitions in the Northeast region of the United States and project write-downs recorded in the third quarter of 1998, as previously discussed. These increased earnings were partially offset by the effects of cooler-than-normal weather in California which reduced equity earnings at the El Segundo, Long Beach and Encina generating stations. In addition, earnings were decreased by costs related to project acquisitions and business development, and increased interest expenses. Also, equity earnings were impacted by several other factors, including lower earnings from the Mt. Poso project primarily due to curtailment revenues that were recorded in 1998; a currency transaction adjustment relating to the Kladno project; and a decrease in earnings from NEO affiliates.

EMI—EMI's losses for the first nine months of 1999 were less than the first nine months of 1998 losses primarily due to increased margins and activity on energy services projects.

Seren—Seren's build-out of its broadband communications network in St. Cloud, Minn., and initial construction in northern California resulted in losses for the first nine months of 1999, which is consistent with Seren's business plan.

LIQUIDITY AND CAPITAL RESOURCES

    For a discussion of short-term borrowings, see Note 5 to the Financial Statements.

    In February 1999, stock options for 993,305 shares were awarded under NSP's Executive Long-Term Incentive Award Stock Plan (the Long-Term Plan). These options can not be exercised for approximately twelve months after the award date. Effective in January 1999, stock options granted to NSP officers vest at a rate of one-third each year for three years. As of Sept. 30, 1999, a total of 3,330,327 options were outstanding, which were considered potentially dilutive common shares for calculating earnings per share.

    During the first nine months of 1999, NSP issued 1,661,296 new shares of common stock under the Long-Term Plan (pursuant to the exercise of options and awards granted in prior years), the Dividend Reinvestment and Stock Purchase Plan and the Employee Stock Ownership Plan.

    NSP filed its proposed 1999 Capital Structure and Financing Plan with the MPUC in October 1999. In its filing, NSP proposed that, if the completion of its merger with NCE is timed as currently anticipated, NSP will be recapitalized as a subsidiary of Xcel. If completion of the merger appears to be delayed, NSP would issue equity or an equity related security near the end of the first quarter of 2000.

    In November 1998, NSP-Minnesota filed a $400 million universal debt shelf registration with the SEC. NSP-Minnesota currently has $50 million of unissued first mortgage bonds remaining from its shelf registration filed in October 1995. In July 1999, NSP-Minnesota issued $250 million of unsecured long-term debt under the universal registration. These bonds have an annual coupon of 6.875% and mature Aug. 1, 2009. The net proceeds were used for general corporate purposes, including reduction of short-term debt levels.

    The board of directors of NSP-Wisconsin authorized the issuance of up to $80 million of long-term debt in 1999 or 2000. NSP-Wisconsin currently expects to issue between $50 million and $80 million of unsecured long-term debt in the first quarter of 2000, primarily to reduce short-term debt levels.

    In March 1999, NRG filed a shelf registration with the SEC to issue up to $500 million of debt securities. In May 1999, NRG issued $300 million of 7.5 percent senior notes due in 2009 under this shelf registration. In September 1999, NRG entered into a $200 million swap agreement effectively converting the 7.5 percent fixed rate on the senior notes to a variable rate based on LIBOR.

    In November 1999, NRG issued an additional $240 million of long-term debt. The securities a have fixed coupon of 8.0 percent and are remarketable after four years. The net proceeds were used for general corporate purposes, which may include financing the development and construction of new facilities, working capital, debt reduction and pending or potential acquisitions.

    During the third quarter of 1999, NRG Northeast Generating LLC (N.E. Generating), a wholly owned subsidiary of NRG, entered into $600 million of treasury locks at various interest rates. These treasury locks, which expire in February 2000, are an interest rate hedge of N.E. Generating's anticipated bond offering in the first quarter of 2000. The proceeds of this bond offering will be used to pay down borrowings under N.E. Generating's currently existing short-term credit facility, which is reported as part of NSP's nonregulated short-term debt.

    During the first quarter of 1999, NRG entered into a forward contract to exchange approximately $10.5 million of U.S. dollars for British pounds. This foreign exchange contract, which expires in December 1999, is a hedge of NRG's equity commitment into the Enfield project currently under construction in England.

Part II. OTHER INFORMATION
Item 1. Legal Proceedings

    In the normal course of business, various lawsuits and claims have arisen against NSP. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters.

    As discussed in NSP's 1998 Form 10-K, Wisconsin Electric Power Co. (WE) filed a complaint against NSP with the FERC, relating to transmission service curtailments. In March 1999, NSP and WE reached a settlement agreement, which was approved by the FERC on May 19, 1999. The settlement provides that NSP would not be liable to WE for transmission curtailments during 1998 and NSP would bear certain disputed transmission mitigation costs for 1998 and 1999.

    As discussed in NSP's 1998 Form 10-K, on Dec. 11, 1998, a gas explosion in downtown St. Cloud, Minn., killed four people, including two NSP employees, injured approximately 14 people and damaged several buildings. The accident occurred as a crew from Cable Constructors Inc. (CCI) was installing fiber optic cable. CCI was performing this work for Seren as part of its broadband communications project in St. Cloud. The accident is under investigation by the National Transportation Safety Board (NTSB). Although this investigation has yet to be completed, the NTSB investigator in charge has stated publicly that "the location of the gas line and a gas main that runs parallel had been properly marked by NSP before the drilling." Presently, there are nine lawsuits related to the explosion. One lawsuit involves multiple plaintiffs seeking damages for personal injuries and property losses. Seren, CCI and Sirti (an architecture/engineering firm retained by Seren for the St. Cloud project) are named as defendants in all of the lawsuits. NSP is a defendant in eight of the lawsuits. NSP is not a defendant in a wrongful death action brought by a trustee on behalf of the family of an NSP employee who was killed during the explosion. NSP and Seren deny any liability for this accident. NSP has a self-insured retention deductible of $2 million with general liability coverage limits of $185 million. Seren's primary insurance coverage is $1 million and its secondary insurance coverage is $185 million. The ultimate cost to NSP and Seren, if any, is presently unknown.

    As discussed in NSP's 1998 Form 10-K, in April 1997, a fire damaged several buildings in downtown Grand Forks, N. D., during the historic floods in that city. On July 23, 1998, the St. Paul Mercury Insurance Co., which insured the First National Corp. and its three buildings in downtown Grand Forks, commenced a lawsuit against NSP for damages in excess of $15 million. The suit was filed in the District Court in Grand Forks County in North Dakota. The insurance company alleges that the fire was electrical in origin and that NSP was legally responsible for the fire because it failed to shut off electrical power to downtown Grand Forks during the flood and prior to the fire. In December 1998, a second lawsuit related to the fire was commenced by two partnerships that owned property damaged by the fire and Protection Mutual Insurance Co., which insured the Grand Forks Herald building damaged by the fire. During 1999, six additional law suits have been filed against NSP by insurance companies, which insured businesses damaged by the fire. It is NSP's position that it is not legally responsible for this unforeseeable event. At no time prior to the fire was NSP instructed to shut off power to downtown Grand Forks by any government officials, including representatives from the fire department. Moreover, people in downtown Grand Forks were relying on electricity before and after the fire occurred. NSP has a self-insured retention deductible of $2 million, with general liability insurance coverage limits of $150 million. The ultimate cost to NSP, if any, is unknown at this time.

    As previously discussed in NSP's 1998 Form 10-K and Report on Form 8-K dated April 6, 1999, NSP filed a complaint, on June 8, 1998, in the Court of Federal Claims against the Department of Energy (DOE) requesting damages in excess of $1 billion for the DOE's partial breach of the Standard Contract. NSP requested damages consist of the costs of storage of spent nuclear fuel at the Prairie Island nuclear generating plant, anticipated costs related to the Private Fuel Storage, LLC and costs relating to the 1994 state legislation limiting the number of casks that can be used to store spent nuclear fuel at Prairie Island. On April 6, 1999, the Court of Federal Claims dismissed NSP's complaint. On May 20, 1999, NSP filed a notice of appeals with the Federal Circuit and on July 20, 1999, NSP filed its initial brief on appeal. The Department of Justice, representing the United States, filed its initial brief on Oct. 29, 1999. No date has been set for oral argument. A decision is expected in mid-2000.

    On or about July 12, 1999, Fortistar Capital, Inc. commenced an action against NRG in Hennepin County (Minnesota) District Court, seeking damages in excess of $100 million and an order restraining NRG from consumating the acquisition of Niagara Mohawk Power Corp.'s Oswego generating station. Fortistar's motion for a temporary restraining order was denied and a temporary injunction hearing was held on Sept. 27, 1999. The acquisition of the Oswego generating station was closed on Oct. 22, 1999, following notification to the Court of the closing date. NRG intends to continue to vigorously defend the suit and believes Fortistar's claims to be without merit. NRG has asserted numerous counterclaims against Fortistar.

    See Notes 3 and 4 of the Financial Statements for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, incorporated by reference.

Item 5. Other Information

Proposed Business Combination

    As previously reported in NSP's Report on Form 8-K, dated March 24, 1999, which was filed on March 25, 1999, NSP and NCE agreed to merge and form Xcel. At the time of the merger, each share of NCE common stock will be exchanged for 1.55 shares of Xcel common stock. NSP shares need not be exchanged and will become Xcel shares on a one-for-one basis. Cash will be paid in lieu of any fractional shares of Xcel common stock which holders of NCE common stock would otherwise receive. The merger agreement was filed as Exhibit 2.1 to NSP's March 24, 1999 Form 8-K, and is incorporated by reference.

    On June 28, 1999, shareholders of both NSP and NCE approved the merger. The merger requires approval or regulatory review by certain state utilities regulators, the SEC, the FERC, the Nuclear Regulatory Commission, the Federal Communications Commission, and expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act.

    NSP and NCE have filed merger applications with regulators in Arizona, Colorado, Minnesota, New Mexico, North Dakota, Wyoming, and Texas, at the FERC and at the SEC. Settlement negotiations are underway with the Oklahoma commission staff. Regulatory requirements have been met in Kansas. Merger approval is not required in Michigan, South Dakota and Wisconsin. The merger approval process is currently expected to be completed by the middle of 2000.

    The merger is expected to be a tax-free, stock-for-stock exchange for shareholders of both companies (except for fractional shares), and to be accounted for as a pooling of interests. NSP and NCE have agreed to certain undertakings and limitations regarding the conduct of their businesses prior to the closing of the transaction. At the time of the merger, Xcel will register as a holding company under the Public Utility Holding Company Act of 1935.

    The dividend payment level of Xcel will be determined by its board of directors. However, NSP anticipates that Xcel will adopt an initial dividend policy which will maintain a dividend equivalent to the current dividend of NCE. Based on the conversion ratio of 1.55, the pro forma dividend for the combined company would currently be $1.50 per share annually.

    Based on the merger agreement, James J. Howard, chairman, president and chief executive officer of NSP, will serve as chairman of Xcel for one year following the merger. Wayne H. Brunetti, vice chairman, president and chief operating officer of NCE, will be president and chief executive officer following the merger and will assume the responsibilities of chairman when James Howard retires.

    Xcel will be created by first transferring NSP-Minnesota's utility assets (other than investments in and assets of subsidiaries) into a newly formed, wholly owned subsidiary (which is referred to in this report as New NSP Utility Sub). At the same time, New NSP Utility Sub will assume all of NSP-Minnesota's liabilities associated with the assets transferred. Then NCE will merge into NSP, with the surviving corporate entity in the merger renamed Xcel. Xcel will be a holding company for the combined assets and operations of NSP and NCE. If difficulties arise in obtaining the approvals and consents required to transfer NSP-Minnesota's utility assets to New NSP Utility Sub, NSP and NCE may negotiate a mutually acceptable alternative.

Xcel Summarized Pro Forma Information

    The following summary of unaudited pro forma financial information for Xcel gives effect to the merger using the pooling of interests method of accounting. Under this accounting method, NSP's and NCE's balance sheets and income statements are treated as if they have always been combined for financial reporting purposes. This unaudited pro forma summarized financial information should be read in conjunction with the historical financial statements and related notes of NSP and NCE, which are included in the 1998 Annual Reports on Form 10-K of the respective companies.

    The unaudited pro forma balance sheet information at Sept. 30, 1999, assumes the merger had been completed on Sept. 30, 1999. The unaudited pro forma income statement information assumes the merger had been completed on Jan.1, 1999, the beginning of the earliest period presented.

    The unaudited summarized pro forma financial information does not necessarily indicate what the combined company's financial position or operating results would have been if the merger had been completed on the assumed completion dates and does not necessarily indicate future operating results of the combined company.

Xcel Energy As of Sept. 30, 1999:	NSP		NCE		Adjustments			Pro Forma
	$Millions
Utility Plant—Net	$	4,400	$	6,149	$	1,236		$	11,785
Current Assets		892		887					1,779
Other Assets		3,393		1,064		(1,236	)		3,221
Total Assets	$	8,685	$	8,100				$	16,785
Common Equity	$	2,548	$	2,699				$	5,247
Pref. Securities		305		294					599
Long-Term Debt		2,393		2,272					4,665
Total Capitalization		5,246		5,265					10,511
Current Liabilities		1,919		1,584					3,503
Other Liabilities		1,520		1,251					2,771
Tot Equity & Liabilities	$	8,685	$	8,100				$	16,785

Xcel Energy For the Nine Months Ended Sept. 30, 1999:	NSP		NCE		Adjustments		Pro Forma
	$Millions except for earnings per share
Revenue	$	2,216	$	2,528	$	357	$	5,101
Operating Income		276		499		166		941
Net Income		175		248				423
Available for Common	$	171	$	248			$	419
Earnings per Share—diluted	$	1.12	$	2.16			$	1.27

New NSP Utility Sub Summarized Pro Forma Information

    The following summary of unaudited pro forma financial information for New NSP Utility Sub adjusts the historical financial statements of NSP after the transfer of ownership of all NSP-Minnesota utility assets (other than investments in and assets of subsidiaries) to New NSP Utility Sub and the assumption by New NSP Utility Sub of all of NSP-Minnesota's liabilities associated with the assets transferred.

    The unaudited pro forma balance sheet information at Sept. 30, 1999, assumes the merger had been completed on Sept. 30, 1999. The unaudited pro forma income statement information assumes the merger had been completed on Jan.1, 1999, the beginning of the earliest period presented.

    The unaudited summarized pro forma financial information does not necessarily indicate what New NSP Utility Sub's financial position or operating results would have been if the merger had been completed on the assumed completion dates and does not necessarily indicate future operating results of New NSP Utility Sub.

New NSP Utility Sub As of Sept. 30, 1999:	NSP		Adjustments			Pro Forma
	$Millions
Utility Plant—Net	$	4,400	$	(834	)	$	3,566
Current Assets		892		(321	)		571
Other Assets		3,393		(2,529	)		864
Total Assets	$	8,685	$	(3,684	)	$	5,001
Common Equity	$	2,548	$	(1,158	)	$	1,390
Pref. Securities		305		(305	)
Long-Term Debt		2,393		(915	)		1,478
Total Capitalization		5,246		(2,378	)		2,868
Current Liabilities		1,919		(1,068	)		851
Other Liabilities		1,520		(238	)		1,282
Tot Equity & Liabilities	$	8,685	$	(3,684	)	$	5,001

New NSP Utility Sub For the Nine Months Ended Sept. 30, 1999:	NSP		Adjustments			Pro Forma
	$Millions
Revenue	$	2,216	$	(166	)	$	2,050
Operating Income		276		(45	)		231
Net Income		175		(51	)		124
Available for Common	$	171	$	(47	)	$	124

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

    The following Exhibits are filed with this report:

    2.01  Agreement and Plan of Merger, dated as of March 24, 1999, by and between Northern States Power Company and New Century Energies, Inc. (Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 1-12907) of New Century Energies, Inc. dated March 24, 1999).

    27.01  Financial Data Schedule for the nine months ended Sept. 30., 1999.

    99.01  Statement pursuant to Private Securities Litigation Reform Act of 1995.

(b) Reports on Form 8-K

    The following reports on Form 8-K were filed either during the three months ended Sept, 30, 1999, or between Sept. 30, 1999 and the date of this report:

    July 15, 1999 (Filed July 15, 1999)—Item 5 and 7. Other Events and Financial Statements and Exhibits. Re: Disclosure of NSP's second quarter earnings.

    July 21, 1999 (Filed July 23, 1999)—Item 5 and 7. Other Events and Financial Statements and Exhibits. Re: Disclosure of NSP's issuance of $250 million of long-term unsecured debt.

    July 27, 1999 (Filed July 30, 1999)—Item 5. Other Events. Re: Disclosure of MPUC's order requiring an investigation into the reasonableness of NSP's Minnesota electric rates.

    Sept. 14, 1999 (Filed Sept. 14, 1999)—Item 5. Other Events. Re: Disclosure of NSP financial information presented to security analysts in Minneapolis, MN.

    Oct. 14, 1999 (Filed Oct. 14, 1999)—Item 5. Other Events. Re: Disclosure of NSP and NRG earnings projections for 1999.

    Nov. 8, 1999 (Filed Nov. 8, 1999)—Item 5. Other Events. Re: Disclosure of NSP proposal relating to CIP incentives for 1999.

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.

	NORTHERN STATES POWER COMPANY (Registrant)
	/s/ ROGER D. SANDEEN Roger D. Sandeen Vice President and Controller
	/s/ JOHN P. MOORE, JR. John P. Moore, Jr. Vice President and Corporate Secretary
Date: November 12, 1999

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Part II. OTHER INFORMATION Item 1. Legal Proceedings
Item 5. Other Information
Item 6. Exhibits and Reports on Form 8-K