XCEL ENERGY INC, 10-Q, 2000-11-14

XCEL ENERGY INC
10-Q, 2000-11-14
ELECTRIC & OTHER SERVICES COMBINED

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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

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

For Quarter Ended September 30, 2000

Commission File Number 1-3034

Xcel Energy Inc.
(Exact name of registrant as specified in its charter)

Minnesota (State of other jurisdiction of incorporation or organization)		41-0448030 (I.R.S. Employer Identification No.)
800 Nicollet Mall, Minneapolis, Minnesota (Address of principal executive offices)		55402 (Zip Code)

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

Northern States Power Company
414 Nicollet Mall, Minneapolis, Minnesota 55401
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.

Class
Common Stock, $2.50 par value

Outstanding, at October 31, 2000
340,588,932 shares

PART 1. FINANCIAL INFORMATION
Item 1. Financial Statements

XCEL ENERGY INC.

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(Thousands of Dollars, Except per Share Data)

			Three Months Ended Sept. 30						Nine Months Ended Sept. 30
			2000			1999			2000			1999
Operating revenues:
	Electric utility		$	1,678,801		$	1,457,919		$	4,196,079		$	3,773,152
	Gas utility			176,914			140,019			895,956			880,688
	Nonregulated and other			611,009			186,044			1,514,219			355,075
	Equity earnings from investments in affiliates			95,995			32,357			166,515			60,355

		Total revenue		2,562,719			1,816,339			6,772,769			5,069,270
Operating expenses:
	Electric fuel and purchased power—utility			791,277			592,622			1,812,057			1,427,744
	Cost of gas sold and transported—utility			84,169			67,594			542,920			543,040
	Cost of goods sold—nonregulated and other			297,205			67,570			690,698			238,435
	Other operating and maintenance expenses—utility			324,487			320,816			1,017,599			993,590
	Other operating and maintenance expenses—nonregulated			167,682			79,457			445,685			197,414
	Depreciation and amortization			201,073			173,911			583,570			469,083
	Taxes (other than income taxes)			90,062			90,768			271,991			280,416
	Special charges (see Note 2)			201,482			—			201,482			—

		Total operating expenses		2,157,437			1,392,738			5,566,002			4,149,722

Operating income				405,282			423,601			1,206,767			919,548
Other income (deductions):
	Minority interest			(19,025	)		(564	)		(28,752	)		(1,716	)
	Other			(5,027	)		7,049			(11,099	)		(18,822	)

		Total other income (deductions)		(24,052	)		6,485			(39,851	)		(20,538	)
Interest charges and financing costs:
	Interest charges—net of amount capitalized			175,880			117,842			487,115			292,998
	Distributions on redeemable preferred securities of subsidiary trusts			9,700			9,700			29,100			29,100

		Total interest charges and financing costs		185,580			127,542			516,215			322,098

Income before income taxes and extraordinary item				195,650			302,544			650,701			576,912
Income taxes				97,734			93,280			242,714			153,302

Income before extraordinary item				97,916			209,264			407,987			423,610
Extraordinary item, net of tax (See Note 4)				(5,302	)		—			(18,960	)		—

Net income				92,614			209,264			389,027			423,610
Dividend and redemption premiums on preferred stock				(1,060	)		(1,060	)		(3,181	)		(4,230	)

Earnings available for common shareholders			$	91,554		$	208,204		$	385,846		$	419,380

Weighted average common shares outstanding:
	Basic			338,495			332,510			337,287			331,359
	Diluted			338,876			332,591			337,450			331,505
Earnings per share—basic and diluted before extraordinary item			$	0.29		$	0.63		$	1.20		$	1.27
Extraordinary item (see Note 4)			$	(0.02	)		—		$	(0.06	)		—

Earnings per share—basic and diluted			$	0.27		$	0.63		$	1.14		$	1.27

See the Notes to the Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(Thousands of Dollars)

				Nine months ended Sept. 30
				2000			1999
Operating activities:
	Net income			$	389,027		$	423,610
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			613,846			527,719
		Nuclear fuel amortization			32,937			37,783
		Deferred income taxes			16,001			(18,443	)
		Amortization of investment tax credits			(10,431	)		(10,519	)
		Allowance for equity funds used during construction			695			(4,685	)
		Distributions in excess of (less than) equity earnings of unconsolidated affiliates			(151,067	)		(16,214	)
		Special charges—noncash			99,830			—
		Conservation incentive accrual adjustment—noncash			19,966			35,035
		Extraordinary item (See Note 4)			18,960			—
		Change in accounts receivable			(188,014	)		(138,638	)
		Change in inventories			(54,988	)		(40,884	)
		Change in other current assets			(111,661	)		9,075
		Change in accounts payable			271,928			83,745
		Change in other current liabilities			60,695			50,073
		Change in other assets and liabilities			(32,911	)		(51,846	)

			Net cash provided by operating activities		974,813			885,811
Investing activities:
	Nonregulated capital expenditures and asset acquisitions				(2,064,006	)		(387,894	)
	Utility capital/construction expenditures				(617,275	)		(474,610	)
	Allowance for equity funds used during construction				(695	)		4,685
	Investments in external decommissioning fund				(35,364	)		(32,649	)
	Equity investments, loans and deposits for nonregulated projects				(82,799	)		(141,202	)
	Collection of loans made to nonregulated projects				1,374			30,156
	Other investments—net				(8,359	)		(952,329	)

			Net cash used in investing activities		(2,807,124	)		(1,953,843	)
Financing activities:
	Short-term borrowings—net				331,517			760,252
	Proceeds from issuance of long-term debt—net				2,856,155			950,852
	Repayment of long-term debt, including reacquisition premiums				(1,363,539	)		(316,938	)
	Proceeds from issuance of Xcel Energy common stock				97,875			70,624
	Proceeds from the public offering of NRG stock				453,705			—
	Dividends paid				(419,912	)		(368,615	)

			Net cash provided by financing activities		1,955,801			1,096,175

	Net increase in cash and cash equivalents				123,490			28,143
	Cash and cash equivalents at beginning of period				139,731			99,031

	Cash and cash equivalents at end of period			$	263,221		$	127,174

See Notes to the Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(Thousands of Dollars)

			Sept. 30 2000			Dec. 31 1999
ASSETS
Current assets:
	Cash and cash equivalents		$	263,221		$	139,731
	Accounts receivable—net of allowance for bad debts of $13,418 and $13,043, respectively			1,030,589			800,066
	Accrued unbilled revenues			469,934			410,798
	Materials and supplies inventories at average cost			278,001			306,524
	Fuel and gas inventories at average cost			297,810			152,874
	Prepayments and other			323,895			250,951

		Total current assets		2,663,450			2,060,944

Property, plant and equipment, at cost:
	Electric utility			15,257,333			14,807,684
	Gas utility			2,335,086			2,266,516
	Nonregulated property and other			5,528,664			3,242,410
	Construction work in progress			524,365			533,046

		Total property, plant and equipment		23,645,448			20,849,656
	Less: accumulated depreciation			(8,670,466	)		(8,153,434	)
	Nuclear fuel—net of accumulated amortization of $956,274 and $923,336, respectively			89,075			102,727

		Net property, plant and equipment		15,064,057			12,798,949

Other assets:
	Investments in unconsolidated affiliates			1,476,901			1,439,002
	Nuclear decommissioning fund investments			559,171			517,129
	Other investments			141,166			133,957
	Regulatory assets			560,256			566,727
	Deferred charges and other			615,575			553,650

		Total other assets		3,353,069			3,210,465

		Total Assets	$	21,080,576		$	18,070,358

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	564,163		$	431,049
	Short-term debt			1,868,831			1,432,686
	Accounts payable			1,153,419			793,139
	Taxes accrued			287,258			260,676
	Dividends payable			75,200			127,568
	Other			487,534			438,101

		Total current liabilities		4,436,405			3,483,219

Deferred credits and other liabilities:
	Deferred income taxes			1,792,994			1,779,046
	Deferred investment tax credits			202,981			214,008
	Regulatory liabilities			505,440			442,204
	Benefit obligations and other			643,295			420,140

		Total deferred credits and other liabilities		3,144,710			2,855,398

Minority interest in subsidiaries				267,806			14,696
Long-term debt				7,132,145			5,827,485
Mandatorily redeemable preferred securities of subsidiary trusts				494,000			494,000
Preferred stockholders' equity				105,340			105,340
Common stock and paid-in capital				3,440,310			3,126,447
Retained earnings				2,275,284			2,253,800
Leveraged shares held by ESOP at cost				(26,614	)		(11,606	)
Accumulated comprehensive income				(188,810	)		(78,421	)

		Total common stockholders' equity		5,500,170			5,290,220
Commitments and contingencies (see Note 5)

		Total Liabilities and Equity	$	21,080,576		$	18,070,358

See Notes to the Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
Three Months Ended Sept. 30, 2000 and 1999
(Thousands of Dollars)

		Par Value			Premium			Retained Earnings			Shares Held by ESOP			Accumulated Other Comprehensive Income			Total Stockholders' Equity
Balance at June 30, 1999		$	831,055		$	2,249,142		$	2,140,654		$	(15,056	)	$	(79,316	)	$	5,126,479

Net income									209,264									209,264
Currency translation adjustments															12,957			12,957

Comprehensive income for three months ended 9/30/99																		222,221
Dividends declared:
	Cumulative preferred stock of Xcel								(1,060	)								(1,060	)
	Common stock								(122,751	)								(122,751	)
Issuances of common stock—net			2,667			21,321												23,988
Other			(132	)		(1,408	)		299						(2,499	)		(3,740	)
Repayment of ESOP loan(a)												1,724						1,724

Balance at Sept. 30, 1999		$	833,590		$	2,269,055		$	2,226,406		$	(13,332	)	$	(68,858	)	$	5,246,861

Balance at June 30, 2000		$	845,642		$	2,555,398		$	2,298,337		$	(8,249	)	$	(140,681	)	$	5,550,447

Net income									92,614									92,614
Currency translation adjustments															(48,129	)		(48,129	)

Comprehensive income for three months ended 9/30/00																		44,485
Dividends declared:
	Cumulative preferred stock of Xcel								(1,060	)								(1,060	)
	Common stock								(114,561	)								(114,561	)
Issuances of common stock—net			4,582			36,676												41,258
Other			1			(1,989	)		(46	)								(2,034	)
Loan to ESOP(a)												(18,365	)					(18,365	)

Balance at Sept. 30, 2000		$	850,225		$	2,590,085		$	2,275,284		$	(26,614	)	$	(188,810	)	$	5,500,170

(a): Did not affect cash flows

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
Nine Months Ended Sept. 30, 2000 and 1999
(Thousands of Dollars)

		Par Value			Premium			Retained Earnings			Shares Held by ESOP			Accumulated Other Comprehensive Income			Total Stockholders' Equity
Balance at Dec. 31, 1998		$	825,396		$	2,197,058		$	2,173,373		$	(18,504	)	$	(81,250	)	$	5,096,073

Net income									423,610									423,610
Currency translation adjustments															10,896			10,896

Comprehensive income for nine months ended 9/30/99																		434,506
Dividends declared:
	Cumulative preferred stock of Xcel								(4,230	)								(4,230	)
	Common stock								(366,347	)								(366,347	)
Issuances of common stock—net			8,326			73,349												81,675
Tax benefit from stock options exercised						56												56
Other			(132	)		(1,408	)								1,496			(44	)
Repayment of ESOP loan(a)												5,172						5,172

Balance at Sept. 30, 1999		$	833,590		$	2,269,055		$	2,226,406		$	(13,332	)	$	(68,858	)	$	5,246,861

Balance at Dec. 31, 1999		$	838,192		$	2,288,255		$	2,253,802		$	(11,607	)	$	(78,422	)	$	5,290,220

Net income									389,027									389,027
Currency translation adjustments															(110,388	)		(110,388	)

Comprehensive income for nine months ended 9/30/00																		278,639
Dividends declared:
	Cumulative preferred stock of Xcel								(3,181	)								(3,181	)
	Common stock								(364,319	)								(364,319	)
Issuances of common stock—net			12,033			87,839												99,872
Tax benefit from stock options exercised						47												47
Other						(1,989	)		(45	)								(2,034	)
Gain recognized from NRG stock offering						215,933												215,933
Loan to ESOP(a)												(15,007	)					(15,007	)

Balance at Sept. 30, 2000		$	850,225		$	2,590,085		$	2,275,284		$	(26,614	)	$	(188,810	)	$	5,500,170

(a): Did not affect cash flows

See Notes to Consolidated Financial Statements

Xcel Energy Inc.

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 Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) as of Sept. 30, 2000, and Dec. 31, 1999, the results of its operations and stockholders' equity for the three and nine months ended Sept. 30, 2000 and 1999, and its cash flows for the nine months ended Sept. 30, 2000 and 1999. Due to the seasonality of Xcel Energy's electric and gas sales and variability of nonregulated operations, quarterly and year-to-date results are not necessarily an appropriate base from which to project annual results.

The accounting policies followed by Xcel Energy are set forth in Note 1 to the supplemental consolidated financial statements in Xcel Energy's Form 8-K filed on August 21, 2000. The following notes should be read in conjunction with such policies and other disclosures in the Form 8-K.

1. Merger to Create Xcel Energy

On Aug. 18, 2000, New Century Energies, Inc. (NCE) and Northern States Power Company (NSP) merged and formed Xcel Energy Inc. Xcel Energy, a Minnesota corporation, is a registered holding company under the Public Utility Holding Company Act of 1935. Each share of NCE common stock was exchanged for 1.55 shares of Xcel Energy common stock. NSP shares became Xcel Energy shares on a one-for-one basis. The merger was structured as a tax-free, stock-for-stock exchange for shareholders of both companies (except for fractional shares), and accounted for as a pooling of interests.

Xcel Energy owns the following direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries:

•: Northern States Power Company Minnesota (NSP-Minnesota)
•: Northern States Power Company Wisconsin (NSP-Wisconsin)
•: Public Service Company of Colorado (PSCo)
•: Southwestern Public Service Company (SPS)
•: Black Mountain Gas (BMG)
•: Cheyenne Light, Fuel and Power Company
•: Viking Gas Transmission Company
•: WestGas InterState Inc.
•: Xcel Energy Wholesale Energy Group Inc.
•: Xcel Energy Markets Group Inc.
•: Xcel Energy International Group Inc.
•: Xcel Energy Ventures Inc.
•: Xcel Energy Retail Services Group Inc.
•: Xcel Energy Communications Group Inc.
•: Xcel Energy WYCO Inc.

Also, as part of the merger, NSP transferred its existing utility operations that were being conducted directly by NSP at the parent company level to a newly formed wholly owned subsidiary of

Xcel Energy named NSP-Minnesota. Xcel Energy has the following public utility subsidiary companies: NSP-Minnesota, NSP-Wisconsin, PSCo, SPS, Cheyenne and BMG.

In addition, Xcel Energy, through the Xcel Wholesale Energy Group, owns 82 percent of the common stock of NRG Energy, Inc., a publicly traded independent power producer. Xcel Energy owned 100 percent of NRG until the second quarter 2000, when NRG completed its initial public offering.

Consistent with pooling accounting requirements, upon consummation of the merger in the third quarter of 2000, Xcel Energy expensed all merger-related costs as discussed in Note 2. An allocation of merger costs was made to utility operating companies consistent with prior regulatory filings.

2. Special Charges

During the third quarter of 2000, Xcel Energy expensed pretax special charges totaling $201 million. In the aggregate these special charges reduced Xcel Energy's third quarter 2000 earnings by 43 cents per common share.

The pretax charges included $49 million related to one-time transaction-related costs incurred in connection with the merger of NSP and NCE. These transaction costs include investment banker fees, legal and regulatory approval costs, and expenses for support of and assistance with planning and completing the merger transaction.

Also included were $110 million of pretax charges pertaining to incremental costs of transition and integration activities associated with merging NSP and NCE to begin operations as Xcel Energy. These transition costs include approximately $68 million for severance and related expenses associated with staff reductions of 656 employees, most of whom were released in September and October 2000. Other transition and integration costs include amounts incurred for facility consolidation, systems integration, regulatory transition, merger communications and operations integration assistance.

In addition, the pretax charges include $42 million of asset impairments and other costs resulting from the post-merger strategic alignment of Xcel Energy's nonregulated businesses. These special charges include: $22 million of write-offs of goodwill and project development costs for Planergy and Energy Masters International (EMI) energy services operations that will change their business focus and direction after the merger; $9 million of contractual obligations and other costs associated with post-merger changes in the strategic operations and related revaluations of e prime's energy marketing business; and $10 million in asset write-downs and losses resulting from various other nonregulated business ventures that will no longer be pursued after the merger.

The pretax special charges recognized for merger transaction, transition and integration activities include approximately $66 million in costs incurred prior to third quarter 2000, which had been deferred prior to merger consummation. Of the special charges recorded in third quarter 2000, approximately $57 million relates to accruals of severance and other employee costs, and various integration obligations, that will be paid out in future periods. These accruals are reported in Xcel Energy's balance sheet in other current liabilities.

In addition to the special charges recorded in third quarter 2000, Xcel Energy anticipates approximately $30 million to be incurred in the fourth quarter of 2000 for additional merger transition, integration and severance activities that are expected to occur prior to year-end. Management expects

the majority of its merger-related transition and integration activities to be completed by early 2001 so that Xcel Energy can fully realize in 2001 and future years the operating synergies anticipated from the merger of NSP and NCE.

3. Business Developments

NRG Acquisitions—In January 2000, NRG reached agreement to purchase 1,875 megawatts of fossil-fueled electric generation assets in the Northeast region of the United States from Conectiv. The purchase price is approximately $800 million. NRG will sell 500 megawatts of energy around the clock to Delmarva Power and Light Company under a five-year agreement. The remaining energy and capacity will be sold into the markets in the Northeast region of the United States. NRG will own a 100 percent interest in the project. NRG expects to close the acquisition in the first quarter of 2001.

In March 2000, NRG purchased 1,708 megawatts of fossil-fueled generation from Cajun Electric Power Cooperative for approximately $1 billion. The output from the base-load Cajun facility will be sold principally under long-term contracts. NRG owns 100 percent of this project. Pro forma results including Cajun are presented in Note 8.

In March 2000, NRG purchased the 680-megawatts Killingholme A station from National Power plc. for approximately 390 million pounds sterling (approximately $615 million based on exchange rates at the time of acquisition). Killingholme A was commissioned in 1994 and is a combined-cycle, gas-turbine power station located in England. NRG owns 100 percent of this project.

During June 2000, the Estonian Cabinet approved the terms under which NRG may proceed to purchase a 49-percent interest in Narva Power, which owns approximately 3,000 megawatts of oil shale-fired generation plants and a 51-percent interest in state-owned oil shale mines, Eesti Polevkivi. NRG's purchase of a 49-percent interest in Narva Power remains subject to successful negotiation of definitive agreements. State-owned Eesti-Energia will retain 51-percent ownership of Narva Power. The terms include a commitment by Narva Power to invest approximately $361 million for reconstructing and refurbishing the generation plants and making environmental improvements. NRG Energy will make an initial $65 million to $70 million equity commitment. Narva Power's two stations, Balti and Eesti, currently supply more than 90 percent of Estonia's electricity. Narva Power will enter into a 15-year power purchase agreement with Eesti-Energia.

During September 2000, NRG acquired a 100-year lease of the Flinders Power assets in South Australia for approximately AUD $314 million (approximately $170 million U.S. at time of purchase). Flinders Power includes two power stations totaling 760 megawatts, the Leigh Creek coal mine 175 miles north of the power stations, a dedicated rail line between the two, and Leigh Creek township.

In October 2000, NRG agreed to purchase a 50-percent interest in the Sierra Pacific Resources' 522-megawatt coal-fired North Valmy Generating Station and a 100-percent interest in 25 megawatts of peaking units near Valmy Station. The Valmy assets are currently owned by Sierra Pacific Resources' subsidiary, Sierra Pacific Power Company. Idaho Power, the other 50-percent owner of the Station, has a 180-day right of first refusal on purchasing Sierra Pacific Resources' 50-percent interest. The agreement includes a transitional power purchase agreement (TPPA) for Sierra Pacific Power to purchase energy and ancillary services through March 1, 2003, under a contract that will provide price certainty for Sierra's customers. The asset purchase price was approximately $273 million, net of the TPPA, subject to tax and other adjustments. The project is expected to close in first quarter of 2001.

In November 2000, NRG agreed to acquire a 5,961-megawatt portfolio of operating projects and projects in construction and advanced development from LS Power, LLC for $658 million, subject to purchase price adjustments. The acquisition is expected to close in January 2001.

Nuclear Management Company (NMC)—During 1999, NSP-Minnesota, Wisconsin Electric Power Co., Wisconsin Public Service Corp. and Alliant Energy established the NMC. The four companies operate seven nuclear units at five sites, with a total generation capacity exceeding 3,650 megawatts.

During the second quarter of 2000, the Nuclear Regulatory Commission (NRC) approved requests by NMC's four affiliated utilities to transfer operating authority for their five nuclear plants to NMC. NRC action paves the way for NMC to assume management of operations and maintenance at the five plants. The NRC also is considering requests from three intervenors for hearings regarding NSP-Minnesota's application. NMC responsibilities will include oversight of on-site dry storage facilities for used nuclear fuel at the Point Beach and Prairie Island nuclear plants. Utility plant owners will continue to own the plants, control all energy produced by the plants and retain responsibility for nuclear liability insurance and decommissioning costs. The transfer of operating authority will formally establish NMC as an operating company, with a senior management team focused on sharing best practices. Existing personnel will continue to provide day-to-day plant operations, with the additional benefit of tapping into ideas from all NMC-operated plants for improved safety, reliability and operational performance.

During the third quarter of 2000, NMC and Consumers Energy (CE) reached a tentative agreement, subject to the approval of the CE board of directors, for NMC to operate CE's 789-megawatt Palisades nuclear plant in Covert, Mich. The addition of Palisades would give NMC 4,500 megawatts of generation, making it the sixth largest operator of nuclear plants in the United States.

Utility Engineering—During the third quarter of 2000, Utility Engineering, a wholly owned subsidiary of Xcel Energy, acquired Proto-Power, an engineering services consulting firm in Groton, Conn. Utility Engineering's primary business is power plant design and construction. Proto-Power employs approximately 150 employees.

4. Regulation and Rate Matters

SPS

Restructuring Legislation

Restructuring legislation has been enacted in Texas and New Mexico, as summarized below. SPS has made and continues to make filings with the Public Utility Commission of Texas (PUCT) and the New Mexico Public Regulation Commission (NMPRC) to address critical issues related to SPS's transition plans to retail competition. Retail competition is expected to be implemented in these states on or before Jan. 1, 2002.

Overview of New Mexico Legislation—In April 1999, New Mexico enacted the Electric Utility Restructuring Act of 1999, which provides for customer choice. The legislation provides for recovery of no less than 50 percent of stranded costs for all utilities as quantified by the NMPRC. Transition costs must be approved by the NMPRC prior to being recovered through a non-bypassable wires charge, which must be included in transition plan filings. SPS must separate its utility operations into at least two segments: energy generation and competitive services, and transmission and distribution utility

services either by the creation of separate affiliates that may be owned by a common holding company or by the sale of assets to one or more third parties. A regulated company, in general, is prohibited from providing unregulated services. In May 2000, the NMPRC approved:

•: customer choice for residential, small commercial and educational customers by Jan. 1, 2002;
•: customer choice for commercial and industrial customers by July 1, 2002; and
•: completion of SPS corporate separation by Aug. 1, 2001.

Overview of Texas Legislation—In June 1999, an electric utility restructuring act (SB-7) was passed in Texas, which provides for the implementation of retail competition for most areas of the state beginning Jan. 1, 2002. The PUCT can delay the date for retail competition if a power region is unable to offer fair competition and reliable service during the 2001 pilot projects. The legislation requires:

•: a rate freeze for all customers until Jan. 1, 2002;
•: an annual earnings test through 2001;
•: a 6 percent rate reduction for those residential and small commercial customers who choose not to switch suppliers at the start of retail competition;
•: the unbundling of business activities, costs and rates relating to generation, transmission and distribution and retail services;
•: reductions in NOx and SO2 emissions; and
•: the recovery of stranded costs.

SB-7 requires each utility to unbundle its business activities into three separate legal entities: a power generation company, a regulated transmission and distribution company, and a retail electric provider. SB-7 limits the market share that a single generation provider can control to 20 percent of the generating capacity within a power region. The establishment of a qualified power region with multiple generation suppliers is required under SB-7 in order to implement full retail competition. SPS must return any excess earnings indicated in the annual earnings tests to customers during the period Jan. 1, 1999, through Dec. 31, 2001, or alternatively may direct any excess earnings to improvements in transmission and distribution facilities, to capital expenditures to improve air quality or to accelerate the amortization of regulatory assets, subject to PUCT approval.

Implementation—SPS filed its business separation plan in Texas during the first quarter of 2000 for the unbundling of power generation, transmission, and distribution and retail electric provider services. In April 2000, the PUCT approved SPS's business separation plan. Overall, the plan provides for the separation of all competitive energy services, the establishment of an Xcel Energy customer care company, which will provide customer services for all of Xcel Energy's operating utilities, and a formal code of conduct and compliance manual for managing affiliate transactions.

Subject to all required approvals and indebtedness restrictions, it is anticipated that all generation-related and certain other assets and liabilities will be transferred at net book value to newly-formed affiliates in accordance with SPS' business separation plan by Jan. 1, 2001, (approximately 50 percent of SPS' assets). It is expected that SPS and its affiliates will be capitalized consistent with their respective business operations.

In April 2000, SPS filed with the PUCT a stipulation agreement, which specifically addresses SPS implementation plans to meet the requirements of the Texas deregulation legislation. The stipulation provides for the implementation of full retail customer choice by SPS in its Texas service region, including the future divestiture of certain SPS generation assets. Subject to certain market conditions, SPS has agreed to divest 1,750 megawatts, at a minimum, by Jan. 1, 2002, and has specifically identified the plants that it would sell in connection with additional divestitures required to establish a qualified power region under SB-7. For SPS to comply with this qualified power region requirement and to implement full customer choice in Texas, a minimum of 2,843 megawatts and a maximum of 3,184 megawatts of existing power generation assets or capacity must be sold to third party non-affiliates. SPS has committed to complete these divestitures by Jan. 1, 2006. SPS expects some or all of these divestitures to be completed by the end of 2001. Management believes that these divestitures are in response to the legal requirements of SB-7 and that these divestitures can occur consistent with the pooling-of-interests accounting requirements. The stipulation provides that if the SEC determines that the divestitures would be a pooling violation, the divestitures would be delayed until at least September 2002 to meet the pooling-of-interests requirements.

In May 2000, the PUCT issued a rate order approving the stipulation. SPS has committed to transfer functional control of its electric transmission system to the Midwest Independent System Operator, Inc. (MISO), a regional transmission organization that will operate the transmission systems of multiple owners in the central United States.

SPS filed a rate case on March 31, 2000, to set the rates for the transmission and distribution services in Texas, which are to be unbundled and implemented on Jan. 1, 2002. SPS requested recovery of all jurisdictional costs associated with restructuring in Texas. Hearings and a final rate order are not expected before 2001.

On June 1, 2000, SPS filed its transition plan with the NMPRC. SPS filed to establish rates for the transmission and distribution business in New Mexico, requesting approval of its corporate restructuring/separation and other associated matters. Hearings related to corporate separation are under way. A final rate order is not expected until mid 2001.

Financial Impact—With the issuance of a final written order by the PUCT in May 2000, addressing the implementation of electric utility restructuring, SPS discontinued regulatory accounting under SFAS 71 for the generation portion of its business during the second quarter of 2000. Consistent with current accounting rules, this resulted in extraordinary charges in the second and third quarters of 2000.

During the second quarter of 2000, SPS wrote off its generation-related regulatory assets and other deferred costs totaling approximately $19 million before taxes. This resulted in an after-tax extraordinary charge of approximately $13.7 million against the earnings of Xcel Energy and SPS. During the third quarter of 2000, SPS recorded an extraordinary charge of $8.2 million before tax, or $5.3 million after tax, related to the tender offer/defeasance of approximately $295 million of First Mortgage bonds.

SPS's transmission and distribution business continues to meet the requirements of SFAS 71, as that business is expected to remain regulated.

The total impacts of restructuring may be affected by the results of future state and federal regulatory proceedings prior to actual implementation of full competition, currently anticipated to begin on Jan. 1, 2002.

Additionally, there may be other significant financial implications of implementing SB-7 and electric restructuring in New Mexico. These implications include, but are not limited to investments in information technology, establishing an independent operation of the electric transmission systems, implementing the procedures to govern affiliate transactions, the pricing of unbundled energy services and the regulatory recovery of incurred costs related to these issues. Based on current estimates, these incurred costs could be as much as $75 million.

The resolution of these matters may have a significant financial impact on the financial position, results of operations and cash flows of Xcel Energy and SPS.

Earnings Test—Texas

On May 18, 2000, SPS filed its 1999 Earnings Report with the PUCT indicating no excess earnings. On Sept. 26, 2000, the PUCT staff and the Office of Public Utility Counsel (OPUC) filed a Notice of Disagreement with the PUCT indicating adjustments to SPS's calculations, which would result in excess earnings. During the third quarter of 2000, SPS recorded an estimated obligation for 1999 equal to $6.4 million and an estimated obligation for 2000 equal to $5.9 million. SPS continues to work with both the PUCT staff and the OPUC in resolving these matters and final resolution is pending.

Electric Cost Adjustment Mechanisms—Texas

The PUCT's regulations require periodic examination of SPS fuel and purchased power costs, the efficiency of the use of such fuel and purchased power, fuel acquisition and management policies and purchase power commitments. SPS is required to file an application for the PUCT to retrospectively review, at least every three years, the operations of a utility's electricity generation and fuel management activities. In June 1998, SPS filed its reconciliation for the generation and fuel management activities totaling approximately $690 million, for the period from January 1995 through December 1997. In July 2000, the PUCT approved a settlement agreement between SPS and the general counsel of the PUCT, which provided for the recovery of substantially all fuel costs, including approximately $12.1 million of the Texas retail jurisdictional portion of the Thunder Basin judgment.

In June 2000, SPS filed an application for the PUCT to retrospectively review the operations of a utility's electricity generation and fuel management activities. In this application, SPS filed its reconciliation for the generation and fuel management activities totaling approximately $419 million, for the period from January 1998 through December 1999. Final approval is pending.

SPS filed an application on July 21, 2000, seeking to increase its fixed fuel factors as a result of recent increases in natural gas costs. On Aug. 10, 2000, SPS filed a second application seeking authority to surcharge approximately $26 million in fuel under recoveries and related interest accrued through the June 2000 billing cycle over the eight months ending May 2001. On Aug. 18, 2000, the PUCT consolidated these two filings into one docket. SPS reached a unanimous stipulation with all parties to the case resolving all outstanding issues. This stipulation was approved by the PUCT in September 2000 and allowed for the new fuel factors and surcharge factors to become effective in the October 2000 billing cycle.

New Mexico

The NMPRC regulations provide for a fuel and purchased power cost adjustment clause and a fixed annual fuel factor for SPS's New Mexico retail jurisdiction. SPS files monthly and annual reports of its fuel and purchased power costs with the NMPRC, which include the current over/under fuel collection calculation, plus interest. In addition, SPS revises its fixed fuel factor annually to recover projected fuel and purchased power costs as well as any over/under cost balance for the current year. SPS is required to petition for a change in the fixed fuel factor if the over/under recovery balance reaches $5 million.

SPS filed an unopposed motion with the NMPRC on Oct. 4, 2000, seeking to change the date for the implementation of its next fixed annual fuel factor. SPS was approximately $12.8 million under collected in fuel and purchased power costs through August 2000 and projected that these under collections would continue based on recent increases in natural gas costs. On Oct. 24, 2000, the NMPRC approved SPS's revised fixed annual fuel factor to be effective in the November 2000 billing cycle.

PSCo

Performance Based Regulatory Plan—The Colorado Public Utility Commission (CPUC) has established a performance based regulatory plan under which PSCo operates. The major components of this regulatory plan include the following:

•: an annual electric earnings test with the sharing of earnings in excess of an 11 percent return on equity for the calendar years 1997-2001;
•: a Quality Service Plan (QSP) that provides for refunds to customers if PSCo does not achieve certain performance measures relating to electric reliability and customer service; and
•: an incentive cost adjustment (ICA) that provides for the sharing of energy costs and savings relative to an annual target cost/delivered kilowatt-hours.

PSCo regularily monitors and records as necessary an estimated customer refund obligation under the earnings test. In April of each year following the measurement period, PSCo files its proposed rate adjustment under the PBRP. The CPUC conducts proceedings to review and approve these rate adjustments annually. During the nine months ended Sept. 30, 2000, PSCo has recorded an estimated customer refund obligation of approximately $12 million (excluding adjustments to true-up prior year estimates). In June 2000, an administrative law judge (ALJ) issued a recommendation on the unresolved issues related to the 1998 earnings test. PSCo filed its brief on exceptions with the CPUC, asking the CPUC to disregard the ALJ's recommendation and to issue an order adopting PSCo's position. A final CPUC decision related to the refund obligation for 1998 is pending. The procedural schedule for the 1999 earnings test has been established, with hearings set for February 2001.

Gas Rate Case—On July 17, 2000, PSCo filed a retail rate case with the CPUC requesting an annual increase in its jurisdictional gas department revenues of approximately $40 million. The request for a rate increase reflects revenues for additional plant investment, a 12.5-percent return on equity, new depreciation rates and recovery of the dismantlement costs associated with the Leyden Gas Storage facility. Hearings have not yet been scheduled.

NSP-Minnesota

Conservation Recovery—NSP-Minnesota has had a 4.1-percent conservation rate surcharge in place since 1998, pending resolution of the conservation incentive recovery issue. On July 31, 2000, the MPUC approved NSP-Minnesota's request to prospectively reduce the surcharge level to 0.68 percent (consistent with current costs to be recovered) and to refund cumulative overcollections of approximately $24 million. The refund will occur during December 2000. This refund does not include the 1998 conservation incentive amounts still under appeal. Although cash flows will be reduced, Xcel Energy does not expect any earnings impact from these actions due to accruals previously recorded.

NSP-Wisconsin

Temporary Fuel Cost Surcharge—On Feb. 14, 2000, NSP-Wisconsin filed an application with the Public Service Commission of Wisconsin (PSCW) to increase electric rates to recover higher fuel costs. This application was subsequently updated with additional information on March 17, 2000. The increase is primarily the result of higher purchased power costs than were anticipated in base rates. The surcharge factor is expected to increase revenues by approximately $6.5 million in 2000 and represents an average increase for all customer classes of approximately 3 percent. The PSCW issued their order granting the surcharge on May 2, 2000. The surcharge factor is expected to be effective through Dec. 31, 2001.

Electric Transmission—In April 1998, Wisconsin state legislators enacted a law that includes provisions that require the PSCW to order a public utility that owns transmission facilities in Wisconsin to transfer control of its transmission facilities to an Independent System Operator (ISO), or divest its interest in its transmission facilities to an Independent Transmission Company (ITC), if the public utility has not already transferred control to an ISO or divested to an ITC by June 30, 2000. NSP joined the Midwest ISO (MISO) in late 1999 and filed for PSCW and Federal Energy Regulatory Commission (FERC) approval in March 2000. The MISO is not expected to be operational until November 2001. On June 30, 2000, the PSCW issued an order that effectively waived the June 30, 2000, deadline for the state's five major utilities, including NSP-Wisconsin, to relinquish transmission system control. In October 2000, the PSCW issued an order authorizing NSP-Wisconsin's transfer of operating control of its transmission system to the MISO.

5. Commitments and Contingent Liabilities

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.

Xcel Energy and its subsidiaries have been or are currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, Xcel Energy is pursuing or intends to pursue insurance claims and believes it will recover some portion of these costs through such claims. Additionally, where applicable, Xcel Energy 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, Xcel Energy would be required to recognize an expense for such unrecoverable amounts.

On Nov. 1, 2000, the FERC issued an order resulting from its investigation of Summer 2000 wholesale markets in California. As part of the order, the FERC said that certain jurisdictional

wholesale sales made under market-based rate authority are subject to possible refund for a period up to 24 months. NRG owns all or portions of certain generating plants in California, which make wholesale sales at market-based rates subject to FERC jurisdiction and could be affected by the refund condition. The FERC order, which is subject to potential requests for rehearing or appeals, thus could affect future NRG revenues and margins from wholesale sales into the California market.

On March 30, 2000, NRG received notification from the New York Independent System Operator (NYISO) of their petition to the FERC to place a $2.52-per-megawatt-hour market cap on ancillary service revenues. The NYISO also requested authority to impose this cap on a retroactive basis to March 1, 2000. On May 31, 2000, FERC approved a request of the NYISO to impose price limitations on one ancillary service, ten minute non-synchronize reserves, effective March 28, 2000. FERC rejected the NYISO's request for authority to adjust the market clearing prices for that service on a retroactive basis. As a result of the FERC order (unless the NYISO or another party successfully appeals the order), NRG will retain the approximately $8.0 million of revenues collected in February 2000 and approximately $8.2 million included in revenues, but not collected, for March 2000. The NYISO has sought reconsideration of the FERC order.

The circumstances set forth in Notes 6 and 14 to Xcel Energy's financial statements in Xcel Energy's Form 8-K dated August 21, 2000, 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.

6. Short-Term Borrowings

At Sept. 30, 2000, Xcel Energy and its subsidiaries had approximately $1.9 billion of short-term debt outstanding at a weighted average interest rate of 6.68 percent.

In July 2000, PSCo and its subsidiary PSCCC entered into a $600 million credit agreement, which will be used primarily to support the issuance of commercial paper by PSCo and PSCCC, but also provides for direct borrowings. This credit agreement, which is effective through July 19, 2001, replaced PSCo's existing $300 million 364-day facility, which expired on July 23, 2000, and PSCo and its subsidiaries' $300-million, multi-year facility, which would have terminated on Nov. 17, 2000.

In July 2000, SPS entered into a $500-million credit agreement, which is effective through Jan. 20, 2002. The funds available from this credit agreement were used for general corporate purposes, including support for commercial paper, open market purchases, tender offer and defeasance costs of SPS's outstanding First Mortgage Bonds and other related restructuring costs. SPS is the initial borrower under this credit agreement; however, at the time of separation of the generation assets, the obligations under this credit agreement will be assumed by a newly formed generation company. See Note 4—Regulation and Rate Matters for more information on restructuring.

SPS entered into a credit agreement on Feb. 25, 2000. The commitment under the credit agreement is $300 million and is effective through Feb. 23, 2001. It will be used primarily for support for commercial paper, but also provides for direct borrowings.

As of Sept. 30, 2000, 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.

NRG has a $500-million revolving credit facility under a commitment fee arrangement that matures in March 9, 2001. This facility provides short-term financing in the form of bank loans. At Sept. 30, 2000, NRG had no amounts outstanding under this facility.

In September 2000, NRG borrowed $40 million under a floating rate working capital facility in which NRG South Central Generating LLC, a wholly owned subsidiary of NRG entered into in April 2000. The facility terminates in March 2001. The working capital facility allows NRG to choose between the lenders' prime rate or LIBOR in determining an interest rate.

7. Financial Instruments

As of Sept. 30, 2000, NRG had five interest rate swap agreements with notional amounts totaling approximately $725 million. If the swaps had been discontinued on Sept. 30, 2000, NRG would have owed the counter-parties approximately $8 million. NRG believes that its exposure to credit risk due to nonperformance by the counter-parties to the hedging contracts is insignificant. These swaps are described below.

•: NRG has a swap agreement effectively converting the 7.5 percent fixed rate on $200 million of Senior Notes due 2007 to a variable rate based on LIBOR. The swap expires on June 1, 2009.
•: A second swap effectively converts a $16 million issue of non-recourse variable rate debt into fixed rate debt. The swap expires on Sept. 30, 2002 and is secured by the Camas Power Boiler assets.
•: A third swap converts $177 million of non-recourse variable rate debt into fixed rate debt. The swap expires on Dec. 17, 2014, and is secured by the Crockett Cogeneration assets.
•: A fourth swap converts £188 million, the equivalent of $275 million, of non-recourse variable rate debt into fixed rate debt. The swap expires on June 30, 2019, and is secured by the Killingholme assets.
•: The fifth swap converts variable rate debt to fixed debt. The notional amount is AUD 105 million, the equivalent of $57 million as of Sept. 30, 2000. The swap expires in September 2012 and is secured by the Flinders Power assets.

SPS has an interest rate swap with a notional amount of $25 million, converting variable rate debt to a fixed rate. Young Gas Storage and Quixx, both wholly owned subsidiaries of Xcel Energy, have interest rate swaps converting project debt from variable rate to fixed rate. These two amortizing swaps had a notional amount of $40.3 million on Sept. 30, 2000. The approximate termination cost of these three swaps was $0.9 million at Sept. 30, 2000.

8. Pro Forma Information—NRG's Cajun Acquisition

During March 2000, NRG completed the acquisition of two-fossil fueled generating plants from Cajun Electric Power Cooperative, Inc. for approximately $1 billion. The following information summarizes the pro forma results of operations as if the acquisition, which was accounted for as a

purchase, had occurred as of the beginning of the respective periods for which pro forma information is presented.

Millions of Dollars except earnings per share	Actual Results				Pro Forma Results
Three months Ended	9/30/00		9/30/99		9/30/00		9/30/99
Revenue	$	2,563	$	1,816	$	2,563	$	1,931
Net income		93		209		93		219
Earnings available for common shareholders		92		208		92		218
Earnings per share	$	0.27	$	0.63	$	0.27	$	0.65

Millions of Dollars except earnings per share	Actual Results				Pro Forma Results
Nine months Ended	9/30/00		9/30/99		9/30/00		9/30/99
Revenue	$	6,773	$	5,069	$	6,853	$	5,357
Net income		389		424		386		430
Earnings available for common shareholders		386		419		382		426
Earnings per share	$	1.14	$	1.27	$	1.13	$	1.28

9. Segment Information

Xcel Energy has four reportable segments: Electric Utility, Gas Utility and two of its nonregulated energy businesses, NRG and Xcel International. The segment results for the third quarter and the first nine months of 2000, reflect the write-off of special charges related to the merger.

Business Segments

Three months ended 9/30/2000
Three months ended 9/30/2000	Electric Utility							Xcel International						Reconciling Eliminations			Consolidated Total
(Thousands of dollars)	Electric Utility		Gas Utility			NRG		Xcel International			All Other			Reconciling Eliminations			Consolidated Total
Operating revenues from external customers	$	1,678,312	$	175,907		$	532,855		—		$	77,472			—		$	2,464,546
Intersegment revenues		311		(3,171	)		301		—			11,214		$	(6,477	)		2,178
Equity earnings from investments in affiliate		—		—			91,643		3,237			1,115			—			95,995

Segment net income (loss)	$	93,246	$	(16,513	)	$	88,604	$	(2,575	)	$	(51,759	)	$	(13,087	)	$	97,916

Three months ended 9/30/1999
Three months ended 9/30/1999	Electric Utility							Xcel International						Reconciling Eliminations			Consolidated Total
(Thousands of dollars)	Electric Utility		Gas Utility			NRG		Xcel International			All Other			Reconciling Eliminations			Consolidated Total
Operating revenues from external customers	$	1,457,831	$	140,546			139,758		—		$	45,641			—		$	1,783,776
Intersegment revenues		313		2,959			216		—			41,126		$	(44,408	)		206
Equity earnings from investments in affiliate		—		—			29,686		3,639			(968	)		—			32,357

Segment net income (loss)	$	184,750		(12,866	)		27,607	$	7,974		$	4,339		$	(2,540	)	$	209,264

Nine months ended 9/30/2000
Nine months ended 9/30/2000	Electric Utility						Xcel International					Reconciling Eliminations			Consolidated Total
(Thousands of dollars)	Electric Utility		Gas Utility		NRG		Xcel International		All Other			Reconciling Eliminations			Consolidated Total
Operating revenues from external customers	$	4,195,199	$	894,182	$	1,338,761		—	$	175,458			—		$	6,603,600
Intersegment revenues		880		4,801		902		—		54,927		$	(58,856	)		2,654
Equity earnings from investments in affiliate		—		—		130,171		32,307		4,037			—			166,515

Segment net income (loss)	$	272,899	$	24,451	$	140,931	$	25,337	$	(42,768	)	$	(12,863	)	$	407,987

Nine months ended 9/30/1999
Nine months ended 9/30/1999	Electric Utility						Xcel International					Reconciling Eliminations			Consolidated Total
(Thousands of dollars)	Electric Utility		Gas Utility		NRG		Xcel International		All Other			Reconciling Eliminations			Consolidated Total
Operating revenues from external customers	$	3,772,175	$	880,879	$	236,892		—	$	118,265			—		$	5,008,211
Intersegment revenues		977		8,272		963		—		91,120		$	(100,628	)		704
Equity earnings from investments in affiliate		—		—		45,726		19,373		(4,744	)		—			60,355

Segment net income (loss)	$	352,812	$	19,577	$	29,008	$	26,049	$	4,854		$	(8,690	)	$	423,610

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

TO XCEL ENERGY INC.:

We have reviewed the accompanying consolidated balance sheet of Xcel Energy Inc. as of September 30, 2000, and the related consolidated statements of income and stockholders equity for the three-month and nine-month periods ended September 30, 2000, and the consolidated statement of cash flows for the nine-month periods ended September 30, 2000. These financial statements are the responsibility of the Company's management.

We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the financial statements referred to above for them to be in conformity with accounting principles generally accepted in the United States.

ARTHUR ANDERSEN LLP

Minneapolis, Minnesota
November 10, 2000

Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS

FINANCIAL REVIEW

The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy's financial condition and results of operations during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited Consolidated Financial Statements and Notes.

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

•: 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
•: the higher risk associated with Xcel Energy's nonregulated businesses compared with its regulated business
•: currency translation and transaction adjustments
•: the other risk factors listed from time to time by Xcel Energy in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.01 to this Report on Form 10-Q for the quarter ended Sept. 30, 2000.

RESULTS OF OPERATIONS

Xcel Energy's earnings per share were $0.27 for the third quarter of 2000, compared with $0.63 for the third quarter of 1999. Xcel Energy's earnings per share for the third quarter of 2000 were reduced by 43 cents per share for special charges related to the merger of NSP and NCE to form Xcel Energy and by 2 cents per share for an extraordinary item related to the restructuring of SPS's generation business.

Xcel Energy's earnings per share were $1.14 for the first nine months of 2000, compared with $1.27 for the first nine months of 1999. Xcel Energy's earnings per share for the first nine months of 2000 were reduced by 43 cents per share for special charges related to the merger and by 6 cents per share for an extraordinary item related to the restructuring of SPS's generation business.

The following table details the earnings per share contribution of Xcel Energy's regulated and nonregulated businesses.

	Three months ended:					Nine months ended:
Earnings per share (EPS)	9/30/00			9/30/99		9/30/00			9/30/99
Regulated EPS before extraordinary item	$	0.20		$	0.54	$	0.95		$	1.19
Extraordinary item (see Note 4)		(0.02	)		—		(0.06	)		—

Total regulated EPS		0.18			0.54		0.89			1.19
Nonregulated EPS		0.09			0.09		0.25			0.08

Total Xcel Energy EPS	$	0.27		$	0.63	$	1.14		$	1.27

Extraordinary Item—Electric Utility Restructuring

As discussed in Note 4, during the second quarter of 2000, SPS wrote off its generation-related regulatory assets and other deferred costs for an extraordinary charge of approximately $19 million before taxes, or $13.7 million after tax. During the third quarter of 2000, SPS recorded an additional extraordinary charge of $8.2 million before tax, or $5.3 million after tax, related to the tender offer/ defeasance of approximately $295 million of First Mortgage bonds.

Special Charges

During the third quarter and the first nine months of 2000, Xcel Energy expensed pretax special charges of $201 million, or 43 cents per share, for costs related to the merger between NSP and NCE. The merger was completed on Aug 18, 2000. See Note 2 for more information on these charges.

Nonregulated Results

Xcel Energy'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.
•: Yorkshire Power is in the electric distribution and supply business in the United Kingdom. Xcel Energy, through its subsidiary Xcel International, owns a 50-percent share of the Yorkshire Power joint venture.
•: Seren Innovations is a communications and data services subsidiary.
•: Planergy International's primary business is custom energy services and sales.
•: Other includes Xcel Energy's other nonregulated ventures.

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

	Three months ended:						Nine months ended:
Earnings per share (EPS)	9/30/00			9/30/99			9/30/00			9/30/99
NRG Energy Inc.	$	0.23		$	0.08		$	0.35		$	0.09
Yorkshire Power		0.02			0.01			0.12			0.06
Seren International Inc.		(0.02	)		(0.01	)		(0.05	)		(0.02	)
Planergy International		(0.05	)		(0.01	)		(0.06	)		(0.02	)
Other		(0.09	)		0.02			(0.11	)		(0.03	)

Total nonregulated EPS	$	0.09		$	0.09		$	0.25		$	0.08

NRG's earnings for the third quarter and the first nine months of 2000 continue to benefit from increased generation capacity due to recently acquired generation assets. From September 1999 to September 2000, NRG has increased its megawatt ownership interest in generating facilities in operation from 6,719 megawatts to 14,216 megawatts. NRG's earnings for the third quarter and the first nine months of 2000 were also influenced by favorable weather conditions that increased demand for electricity in the western United States, strong performance from existing assets and increases in fuel prices, primarily natural gas and oil, which contributed to higher market prices for electricity. The NRG earnings contribution shown above is net of NRG net income attributable to minority shareholders. For more information on NRG's acquisitions, see Note 3.

Equity earnings from Yorkshire Power increased for both the third quarter and the first nine months of 2000 due to a stronger performance in the supply business from lower electricity supply

prices and lower operating costs due to an aggressive cost reduction program and a change in its accounting for depreciation effective Jan. 1, 2000.

As expected, Seren's expansion of its broadband communications network in St. Cloud, Minn., and construction in California resulted in losses for the third quarter and the first nine months of 2000.

During the third quarter of 2000, Planergy and EMI, both wholly owned subsidiaries of Xcel Energy, were merged to form Planergy International. As a result of this merger, Planergy International reassessed its business model and made a strategic realignment, which resulted in a $22 million (before tax) write-off of goodwill and project development costs. These special charges reduced earnings by 4 cents per share.

The Other Nonregulated results for the third quarter and the first nine months of 2000 include $9 million of contractual obligations and other costs associated with post-merger changes in the strategic operations and related revaluations of e prime's energy marketing business, and $10 million in asset write-downs and losses resulting from various other nonregulated business ventures that will no longer be pursued after the merger. These special charges reduced earnings by 4 cents per share.

Third Quarter 2000 vs. Third Quarter 1999

Electric Utility Margins

The following table details the change in electric revenue and margin. Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel clause cost recovery mechanisms for retail customers in several states and the ability to vary wholesale prices with changing market conditions, fluctuations in energy costs with certain limitations do not affect electric margin. However, the fuel clause cost recovery in the various jurisdictions does not allow for complete recovery of all variable production expenses and periods of higher costs energy, particularly in periods of extreme temperatures, can result in an adverse earnings impact.

	Three months ended Sept. 30
	2000			1999
	(Millions of dollars)
Electric revenue	$	1,679		$	1,458
Electric fuel and purchased power		(791	)		(593	)

Electric margin	$	888		$	865

Electric revenue and margin for the third quarter of 2000 increased, compared with the third quarter of 1999, largely due to increased retail and wholesales sales growth. For the quarter, retail sales increased 2.6 percent and wholesale sales increased 10.3 percent. Fuel and power costs also increased due to higher cost of purchased power, which is generally recoverable in rates within certain limitations.

Increases in electric revenue and margin were partially offset by lower conservation incentive recovery in Minnesota during 2000, which reduced revenue and margin by approximately $13 million. In addition, electric revenue and margin in 2000 was also reduced by approximately $16 million in Colorado and $12 million in Texas for regulatory revenue adjustments for future rate reductions related to the recovery of energy costs, allowed return levels and system reliability and availability, as discussed in Note 4.

Gas Utility Margins

The following table details the change in gas revenue and margin. The cost of gas tends to vary with changing sales requirements and unit cost of gas purchases. However, due to purchased gas cost

recovery mechanisms for retail customers, fluctuations in the cost of gas have little effect on gas margin.

	Three months ended Sept. 30
	2000			1999
	(Millions of dollars)
Gas revenue	$	177		$	140
Cost of gas purchased and transported		(84	)		(68	)

Gas margin	$	93		$	72

Gas revenue for the third quarter of 2000 increased, compared with 1999, largely due to increases in the cost of gas, which is generally recovered in most jurisdictions through various purchased gas adjustment clauses. Gas margin increased for the quarter due to firm gas sales growth and higher transportation revenues.

Nonregulated Operating Margins

The following table details the change in nonregulated revenue and margin.

	Three months ended Sept. 30
	2000			1999
	(Millions of dollars)
Nonregulated and other revenue	$	611		$	186
Earnings from equity investments		96			32
Nonregulated cost of goods sold		(297	)		(68	)

Nonregulated margin	$	410		$	150

Nonregulated revenue and margin increased for the third quarter of 2000, largely due to NRG's acquisitions of generating facilities, favorable weather conditions that increased demand for electricity, strong performance from existing assets and increases in fuel prices, primarily natural gas and oil, which contributed to higher market prices for electricity.

Earnings from equity investments for the third quarter of 2000, increased compared with the third quarter of 1999, primarily due to increased equity earnings from NRG projects. The increase in NRG equity earnings is primarily due to increased earnings from its investments in West Coast Power LLC and Rocky Road LLC, which benefited from warmer weather conditions experienced in the western portion of the United States in 2000. In addition, equity earnings from Yorkshire increased by approximately $3 million.

Non-Fuel Operating Expense and Other Costs

Regulated Other Operation and Maintenance Expenses were fairly stable for the third quarter of 2000, compared with the third quarter of 1999, increasing by approximately $4 million, or 1.1 percent.

Nonregulated Other Operation and Maintenance Expenses increased by approximately $88 million, or 111 percent, for the third quarter of 2000, compared with the third quarter of 1999. The increase is primarily due to costs of nonregulated operations acquired, increased business development activities and legal, technical and accounting expenses resulting from NRG's expanding operations.

Depreciation and Amortization increased by approximately $27 million, or 15.6 percent, for the third quarter of 2000, compared with the third quarter of 1999, primarily due to acquisitions of generating facilities by NRG and increased capital additions to utility plant.

Interest expense increased by approximately $58 million, or 49.3 percent, for the third quarter of 2000, compared with the third quarter of 1999, primarily due to increased nonregulated debt levels to fund several asset acquisitions by NRG.

First Nine Months 2000 vs. First Nine Months 1999

Electric Utility Margins

	Nine months ended Sept. 30
	2000			1999
	(Millions of dollars)
Electric revenue	$	4,196		$	3,773
Electric fuel and purchased power		(1,812	)		(1,428	)

Electric margin	$	2,384		$	2,345

Electric revenue and margin for the first nine months of 2000 increased, compared with the same period in 1999, largely due to increased retail and wholesales sales growth. For the first nine months of 2000, retail sales increased 4.3 percent and wholesale sales increased 10.3 percent. PSCo's wholesale energy marketing and trading operation provided approximately $37 million of additional electric margin due to favorable market conditions in the western United States. In addition, NSP-Minnesota's wholesale operation increased electric margin by approximately $17 million. Fuel and power costs also increased due to higher cost of purchased power, which is generally recoverable in rates within certain limitations.

Increases in electric revenue and margin in 2000 were partially offset by regulatory adjustments, which reduced revenue and margin by approximately $16 million in Colorado and $12 million in Texas for future rate reductions related to the recovery of energy costs, allowed return levels and system reliability and availability. For more information on these regulatory adjustments, see Note 4.

Gas Utility Margins

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

	Nine months ended Sept. 30
	2000			1999
	(Millions of dollars)
Gas revenue	$	896		$	881
Cost of gas purchased and transported		(543	)		(543	)

Gas margin	$	353		$	338

Gas revenue and margin for the nine months of 2000 increased, compared with the nine months of 1999, largely due to increased transportation sales, which increased 12.2 percent. In addition, revenue and margin also increased due to higher base rates in Colorado, resulting from PSCo's 1998 rate case, which became effective July 1, 1999.

Nonregulated Operating Margins

The following table details the change in nonregulated revenue and margin.

	Nine months ended Sept. 30
	2000			1999
	(Millions of dollars)
Nonregulated and other revenue	$	1,514		$	355
Earnings from equity investments		167			60
Nonregulated cost of goods sold		(691	)		(238	)

Nonregulated margin	$	990		$	177

Nonregulated revenue and margin increased for the first nine months of 2000, largely due to NRG's acquisitions of generating facilities, favorable weather conditions that increased demand for electricity, strong performance from existing assets and increases in fuel prices, primarily natural gas and oil, which contributed to higher market prices for electricity.

Earnings from equity investments for the first nine months of 2000 increased compared with the first nine months of 1999, primarily due to increased equity earnings from NRG projects. The increase in NRG equity earnings is primarily due to increased earnings from its investments in West Coast Power LLC and Rocky Road LLC, which benefited from warmer weather conditions experienced in the western portion of the United States in 2000. Equity earnings from Yorkshire increased by approximately $20 million due to a stronger performance in the supply business from lower electricity supply prices and lower operating costs due to an aggressive cost reduction program and a change in its accounting for depreciation effective Jan. 1, 2000. Equity earnings also increased at NRG due to acquisitions.

Non-Fuel Operating Expense and Other Costs

Regulated Other Operation and Maintenance Expenses for the nine months of 2000, increased by approximately $24 million, or 2.4 percent, compared with the first nine months of 1999. The increase is largely due to the timing of outages at the Prairie Island and Monticello nuclear plants, which increased costs by $17 million. The remaining cost increase is largely due to general inflation and higher costs associated with steam generation, transmission, and customer expenses at SPS.

Nonregulated Other Operation and Maintenance Expenses increased by approximately $248 million, or 125.8 percent, for the first nine months of 2000, compared with the first nine months of 1999. The increase is primarily due to costs of nonregulated operations acquired, increased business development activities and legal, technical and accounting expenses resulting from NRG's expanding operations.

Depreciation and Amortization increased by approximately $114 million, or 24.4 percent, for the first nine months of 2000, compared with the first nine months of 1999, primarily due to acquisitions of generating facilities by NRG and increased capital additions to utility plant.

Interest expense increased by approximately $194 million, or 66.3 percent, for the first nine months of 2000, compared with the first nine months of 1999, primarily due to increased debt levels to fund several asset acquisitions by NRG.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

		Nine months ended Sept. 30
		2000			1999
Net cash provided by operating activities (in millions)		$	975		$	886

Cash provided by operating activities increased for the first nine months of 2000, compared with the first nine months of 1999. Net income was lower for the first nine months of 2000, compared with 1999, however, net income during 2000 was reduced by several non-cash items, such as: accrued special charges related to the merger, depreciation and deferred taxes. After adjusting for these noncash items, operating cash flows for 2000 increased.

		Nine months ended Sept. 30
		2000			1999
Net cash used in investing activities (in millions)		$	(2,807	)	$	(1,954	)

Cash used in investing activities increased for the first nine months of 2000, compared with the first nine months of 1999, primarily due to NRG's acquisitions of the following generating assets: Cajun, Killingholme A and Flinders in 2000. During the first nine months of 1999, NRG acquired the following generating assets: Oswego, Somerset, Encina, Huntly and Dunkirk, Arthur Kill and Astoria.

		Nine months ended Sept. 30
		2000			1999
Net cash provided by financing activities (in millions)		$	1,956		$	1,096

Cash provided by financing activities increased for the first nine months of 2000, compared with the first nine months of 1999, primarily due to the an increase in the issuance of nonregulated debt and a public stock offering by NRG to fund its acquisitions of generating facilities.

Financing Activities

In September 2000, Xcel Energy filed a $1 billion universal debt registration with the SEC. Xcel Energy plans to issue approximately $600 million of debt during the fourth quarter of 2000, dependent on market condition. The proceeds from the debt issuance will be used for general corporate purposes.

NSP-Minnesota plans to file a $500 million long-term debt shelf registration during the fourth quarter of 2000.

In October 2000, NSP-Wisconsin completed the sale of $80 million of 7.64 percent unsecured senior notes, maturing Oct. 1, 2008. The proceeds were used primarily to repay short-term debt.

During the first and second quarters of 2000, SPS repurchased in the open market approximately $27 million and $58 million, respectively, of its First Mortgage Bonds. In addition, during the third quarter 2000, SPS completed a tender offer/defeasence of approximately $295 million of outstanding First Mortgage Bonds. For more information, see Note 4.

In March 2000, NRG South Central Generating LLC, a subsidiary of NRG, issued $800 million of senior secured bonds in a two-part offering. The first tranche was for $500 million with a coupon of 8.962 percent and a maturity of 2016. The second tranche was for $300 million with a coupon of 9.479 percent and a maturity of 2024. The proceeds were used to finance a portion of NRG's investment in the Cajun generating facilities.

In March 2000, NRG issued 160 million pound sterling (approximately $250 million at the time of issuance) of 7.97 percent reset senior notes due 2020, principally to finance NRG's equity investment in the Killingholme facility. On March 15, 2005, these senior notes may be remarketed by Bank of America, N.A. at a fixed rate of interest through the maturity date or at a floating rate of interest for up to one year and then at a fixed rate of interest through 2020.

In March 2000, three of NRG's foreign subsidiaries entered into a 335 million pound sterling ($533 million) secured borrowing facility agreement. Under this facility, the financial institutions have made available to NRG's subsidiaries various term loans totaling 235 million pound sterling ($374 million) for purposes of financing the acquisition of the Killingholme facility and 100 million pound sterling ($159 million) of revolving credit and letter of credit facilities to provide working capital for operating the Killingholme facility. The final maturity date of the facility is the earlier of June 30, 2019, or the date on which all borrowings and commitments under the largest tranche of the term facility have been repaid or cancelled.

In September 2000, NRG issued $350 million of senior secured bonds, with an interest rate of 8.25 percent due in 2010. The proceeds from these bonds were used for repayment of short-term indebtedness incurred to fund acquisitions, primarily Flinders Power, and for investments and general corporate purposes.

During the second quarter of 2000, NRG completed an initial public offering of 32,395,500 shares priced at $15 per share. Xcel Energy owns approximately 147,600,000 Class A shares of NRG common stock, or approximately 82 percent of NRG's outstanding shares. Management has concluded that this offering of NRG stock does not affect Xcel Energy's ability to use the pooling of interests method of accounting for the merger of NSP and NCE. The offering's net proceeds of approximately $454 million were used for general corporate purposes, including to fund a portion of NRG Energy's project investments and other capital requirements for 2000. No proceeds of this offering were received by Xcel Energy. A portion of the proceeds was accounted for as a gain on the sale of 18 percent of Xcel Energy's ownership in NRG. This gain of $216 million was not recorded in earnings, but consistent with Xcel Energy's accounting policy was recorded as an increase in the common stock premium component of stockholders' equity.

During October 2000, Xcel Energy's board of directors authorized NRG to raise up to $600 million of equity through a follow-on offering. The timing and amount is subject to approval by NRG's board of directors and will be dependent on NRG's opportunities and market conditions.

Short-term debt and credit facilities are discussed in Note 6.

Market Risks

Xcel Energy and its subsidiaries are exposed to market risks, including changes in commodity prices, interest rates and currency exchange rates as disclosed in Management's Discussion and Analysis in its Report, including its Exhibit 99.02, on Form 8-K dated Aug. 21, 2000. Xcel Energy's regulated subsidiaries have limited exposure to commodity price and interest rate risk due to cost-based rate regulation. There have been no material changes in the market risk exposures that affect the quantitative and qualitative disclosures presented as of Dec. 31, 1999.

In connection with the deregulation of the electricity industry in the states of Texas and New Mexico, SPS completed its tender offer/defeasance of its First Mortgage Bonds. As a result, SPS will remain exposed to interest rate risk for its generation business. SPS's fuel adjustment clauses are expected to remain in effect through Dec. 31, 2001, thereby limiting the short-term exposure to commodity price risk.

For information on Xcel Energy's interest rate swaps, see Note 7.

Regulatory Issue

The independent system operators who oversee most of the wholesale power markets in which NRG operates have in the past imposed, and may in the future continue to impose, price limitations and other mechanisms to address some of the volatility in these markets. These types of price limitations and other mechanisms may adversely impact the profitability of NRG's generation facilities that sell energy into the wholesale power markets. Given the extreme volatility and lack of meaningful long-term price history in many of these markets, Xcel Energy and NRG cannot quantify the impact on profitability with any certainty.

Accounting Change

In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." In June 2000, the FASB issued SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities, an Amendment to FASB Statement No. 133."

SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS 133 requires that changes in the derivative instrument's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative instrument's gains and losses to offset related results on the hedged item in the income statement, to the extent effective, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting.

SFAS 133 will apply to Xcel Energy's accounting for commodity futures and options contracts, index or fixed price swaps and basis swaps used to hedge price volatility in the markets. SFAS 133 will also apply to Xcel Energy's accounting for interest rate swaps used to hedge exposure to changes in interest rates. Xcel Energy may apply special hedge accounting to account for these derivative instruments provided they meet the specific hedge accounting criteria established by SFAS 133.

Xcel Energy plans to adopt SFAS 133 in 2001, as required. Xcel Energy expects the following:

•: a one-time gain or (loss) recorded in the first quarter of 2001 related to the cumulative effect of applying the new accounting method to periods prior to 2001;
•: increased volatility in future earnings due to the impact of market fluctuations on derivative instruments used by Xcel Energy and its subsidiaries; and
•: potential changes in the Company's business practices

The cumulative effect adjustment, which will be reported as a separate after-tax gain or (loss), will vary based on market pricing levels in effect at Jan. 1, 2001.

Xcel Energy has reviewed its commodity, energy and other related contracts for purposes of identifying derivative instruments. We are in the process of designating contracts that qualify for the normal purchase and sales exception, determining fair market values for its derivatives, designating and documenting hedge relationships, and evaluating the effectiveness of those hedging relationships. We are completing this review under the current SFAS 133 standards and interpretations. However, the results of this review may need to be reevaluated based on the deliberation and interpretations expected from the FASB in the fourth quarter of 2000, regarding the final implementation guidance for SFAS 133. Pending this review, the actual impact of Xcel Energy's adoption of SFAS 133 is uncertain at this time and will vary based on factors such as specific derivative and hedging activities, market conditions and contractual arrangements at the date of adoption.

Part II. OTHER INFORMATION

Item 1. Legal Proceedings

In the normal course of business, various lawsuits and claims have arisen against Xcel Energy. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters. See Notes 4 and 5 of the Financial Statements in this Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 of NSP's and NCE's 1999 Form 10-K, to Part II, Item 1 of NSP's and NCE's Form 10-Q's for the quarters ended March 31, 2000, and June 30, 2000, and to Note 14 to Xcel Energy's Supplemental Consolidated Financial Statements included in Xcel Energy's Form 8-K filed on Aug. 21, 2000, for a description of certain legal proceedings presently pending. There are no new significant cases to report against Xcel Energy or its subsidiaries and there have been no notable changes in the previously reported proceedings, except as set forth below.

On Dec. 11, 1998, a gas explosion in St. Cloud, Minn., killed four people, including two NSP-Minnesota 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 for Seren. Seren, CCI and Sirti, an architecture/engineering firm retained by Seren, are named as defendants in 10 lawsuits relating to the explosion. NSP-Minnesota is a defendant in eight of the lawsuits. NSP-Minnesota and Seren deny any liability for this accident. On July 11, 2000, the National Transportation Safety Board issued a report, which determined that CCI's inadequate installation procedures and delay in reporting the gas hit were the proximate cause of the accident. NSP-Minnesota 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 Xcel Energy, NSP-Minnesota and Seren, if any, is presently unknown.

In April 1997, a fire damaged several buildings in downtown Grand Forks, N. D., during a flood in the city. On July 23, 1998, the St. Paul Mercury Insurance Co. commenced a lawsuit against NSP-Minnesota 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 the fire was electrical in origin and that NSP-Minnesota 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. Seven additional lawsuits were filed against NSP-Minnesota by insurance companies that insured businesses damaged by the fire. One additional lawsuit filed by the First National Bank of Grand Forks is venued in Federal Court. The total of damages being sought by all these lawsuits is in excess of $30 million. NSP-Minnesota denied any liability, asserting that it was not legally responsible for this unforeseeable event. Trial concerning the state court lawsuits commenced on Aug. 1, 2000, and concluded on Sept. 7, 2000. On Sept. 8, 2000, after deliberating for only one hour, a jury returned a defense verdict in favor of NSP-Minnesota. It is unknown whether the plaintiffs will appeal. NSP-Minnesota has a self-insured retention deductible of $2 million, with general liability insurance coverage limits of $150 million. The ultimate cost to Xcel Energy and NSP-Minnesota, if any, is unknown at this time.

Item 4. Submissions of Matter to a Vote of Securities Holders

Xcel Energy's Annual Meeting of Shareholders was held on Sept. 27, 2000, for the purpose of voting on the matters listed below. Proxies for the meeting were solicited pursuant to Section 14(a) of the Securities Exchange Act of 1934 and there were no solicitation in opposition to management's solicitations. All of management's nominees for directors as listed in the proxy statement were elected. The voting results were as follows.

1.: A proposal to elect five directors to Class II until the 2003 Annual Meeting of Shareholders:

Election of Director	Shares Voted For	Withheld Authority
Wayne H. Brunetti	253,636,064	10,195,632
Giannantonio Ferrari	254,973,250	8,858,447
Roger R. Hemminghaus	255,328,036	8,503,660
Douglas W. Leatherdale	255,426,808	8,404,888
A. Patricia Sampson	255,224,039	8,607,657

A proposal to elect three directors to Class I until the 2002 Annual Meeting of Shareholders:

Election of Director		Shares Voted For		Withheld Authority
C. Coney Burgess		255,511,483		8,320,213
A. Barry Hirschfeld		255,174,084		8,657,612

A proposal to elect three directors to Class III until the 2001 Annual Meeting of Shareholders:

Election of Director	Shares Voted For	Withheld Authority
Albert F. Moreno	255,222,299	8,609,398
Rodney E. Stifer	255,328,854	8,502,843
W. Thomas Stephens	255,547,806	8,283,891

2.: Proposal to approve the Xcel Energy Omnibus Incentive Plan:

Shares Voted For		Shares Voted Against		Shares Abstained
227,743,134		29,619,864		6,468,698

3.: Proposal to approve the Xcel Energy Executive Annual Incentive Award:

Shares Voted For		Shares Voted Against		Shares Abstained
228,393,015		28,170,450		7,268,131

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

The following Exhibits are filed with this report:

15 Letter from Arthur Andersen regarding unaudited interim information for Xcel Energy.

27.01 Financial Data Schedule for the nine months ended Sept. 30, 2000.

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, 2000, or between Sept. 30, 2000, and the date of this report:

Aug. 18, 2000 (filed Aug 21, 2000)—Item 4 and 7. Change in Registrant's Certifying Accountants and Exhibits. Re: Disclosure of Xcel Energy's changing principal auditors from PricewaterhouseCoopers LLP to Arthur Andersen LLP.

Aug. 18, 2000 (filed Aug 21, 2000)—Item 2 and 7. Acquisition or Disposition of Assets and Exhibits. Re: Disclosure of the completed merger between NSP and NCE to form Xcel Energy and the disclosure of Xcel Energy's Supplemental Consolidated Financial Statements.

Oct. 25, 2000 (filed Oct. 25, 2000)—Item 5 and 7. Other Events and Exhibits. Re: Disclosure of Xcel Energy's Third Quarter 2000 Earnings Release.

Oct. 27, 2000 (filed Oct. 27, 2000)—Item 5. Other Events. Re: Disclosure of information to be presented by management of Xcel Energy at the Edison Electric Institute Financial Conference.

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.

	XCEL ENERGY INC. (Registrant)
	By:	/s/ DAVID E. RIPKA David E. Ripka Vice President and Controller
Date: November 14, 2000	By:	/s/ EDWARD J. MCINTYRE Edward J. McIntyre Vice President and Chief Financial Officer

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Part II. OTHER INFORMATION Item 1. Legal Proceedings
Item 4. Submissions of Matter to a Vote of Securities Holders
Item 6. Exhibits and Reports on Form 8-K
SIGNATURES