NORTHERN STATES POWER CO /MN/
8-K, EX-99.03, 2000-08-21
ELECTRIC & OTHER SERVICES COMBINED

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Exhibit 99.03—Supplemental Consolidated Condensed Six Months Ended Financial Statements

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 Supplemental 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 items described under "Factors Affecting Results of Operations"



•

the other risk factors listed from time to time by Xcel Energy in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.04 to this Report on Form 8-K

RESULTS OF OPERATIONS

    Xcel Energy's earnings per share were $0.87 for the first six months of 2000, compared with $0.64 for the first six months of 1999. Xcel Energy's earnings per share for the first six months of 2000 were reduced by 4 cents per share for an extraordinary item related to the deregulation of SPS's generation business, as discussed later. Xcel Energy's results for the first six months of 2000, increased by 13 cents per share due to higher project earnings at NRG and 5 cents per share due to increased equity earnings from Yorkshire Power.

Extraordinary Item

    With the issuance of a final written order by the PUCT on May 31, 2000, addressing the implementation of electric utility restructuring for SPS, management believes that sufficient details of a transition plan to competition now exist allowing for a reasonable determination of the impacts of the deregulation of SPS' generation business. Accordingly, SPS discontinued the application of SFAS 71 for the generation portion of its business during the second quarter of 2000. SPS applied the provisions of SFAS No. 101, "Regulated Enterprises—Accounting for the Discontinuation of SFAS 71" and Emerging Issues Task Force Consensus No. 97-4, "Deregulation of the Pricing of Electricity—Issues Related to the Application of FASB Statements No. 71 and 101" to SPS' electric generation business. While the

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PUCT rate order only addresses Texas operations, SPS plans to pursue a similar strategy to implement the restructuring legislation enacted in New Mexico and believes that all of its generation will ultimately be deregulated. Accordingly, SPS has applied SFAS 101 to all jurisdictions of its generation business. SPS's transmission and distribution business continues to meet the requirements of SFAS 71, as that business is expected to remain regulated. During the second quarter of 2000, SPS wrote off its generation related regulatory assets and other deferred costs totaling approximately $19 million. This resulted in an after-tax extraordinary charge of approximately $13.7 million against the earnings of Xcel Energy and SPS. The total impacts of deregulation 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 (see Note 2 Regulation and Rate Matters for further discussion).

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, most fluctuations in energy costs 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, therefore, higher costs in periods of extreme temperatures can result in an adverse earnings impact.

    Electric revenue and margin for the first six months of 2000 increased, compared with the first six months of 1999, largely due to increased retail and wholesale sales. Favorable results from the wholesale sale energy marketing and trading, contributed $34 million to electric margin. In addition, revenue and margin for the first six months of 1999 were reduced by approximately $32 million for the disallowance of 1998 conservation incentives in Minnesota.

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.

    Gas revenue and margin for the first six months of 2000 increased, compared with the first six months of 1999, largely due to higher sales and a PSCo gas rate increase, which was effective July 1999.

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The increase in gas revenue and margin during the first six months of 2000 was partially offset by warmer-than-normal winter weather in Minnesota, Wisconsin and Colorado. Revenue for the first six months of 2000 also increased due to higher costs of purchased gas, which is recovered through various purchased gas adjustment clauses in Xcel Energy's utility jurisdictions.

Nonregulated Operating Margins

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

    Nonregulated revenue increased for the first six months of 2000, largely due to NRG's acquisitions of generating facilities in the Northeast United States. These acquisitions closed at various times from April 1999 through March 2000.

    Earnings from equity investments for the first six months of 2000 increased compared with the first six months of 1999. Equity earnings from Yorkshire increased by approximately $17 million, due to a stronger performance in the supply business, lower operating costs and a change in its accounting for depreciation. Equity earnings also increased at NRG due to acquisitions and warmer than normal weather on the West Coast.

    Nonregulated margin increased for the first six months of 2000, largely due to NRG's acquisitions of generating facilities in the Northeast United States. These acquisitions closed at various times from April 1999 through March 2000.

Non-Fuel Operating Expense and Other Costs

    Regulated Other Operation and Maintenance Expense increased by approximately $12 million, or 1.9 percent, for the first six months of 2000, compared with the first six months of 1999. The increase is largely due to $8 million of nuclear outage costs and a $5 million adjustment recorded in 1999 that lowered pension accruals.

    Nonregulated Other Operation and Maintenance Expense increased by approximately $169 million, or 146 percent, for the first six months of 2000, compared with the first six 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 Expense increased by approximately $56 million, or 17.2 percent, for the first six months of 2000, compared with the first six months of 1999, primarily due to acquisitions of generating facilities by NRG and increased capital additions to utility plant.

    Interest expense increased by approximately $131 million, or 73 percent, for the first six months of 2000, compared with the first six months of 1999, primarily due to increased debt levels to fund several asset acquisitions by NRG.

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LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

    Cash provided by operating activities increased for the first six months of 2000, compared with the six months of 1999, primarily due to increased nonregulated operations.

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

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

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 Exhibit in Exhibit 99.02. 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 is in the process of refinancing 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.

Financing Activities

    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

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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. Interest is payable semi-annually on these securities beginning Sept. 15, 2000, through March 15, 2005, and then at intervals and interest rates established in the remarketing process.

    In March 2000, three of NRG's foreign subsidiaries entered into a 335 million pound sterling ($533 million) secured borrowing facility agreement with Bank of America International Limited as arranger. 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.

    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. On July 24, 2000, SPS announced the commencement of a tender offer for all of its outstanding First Mortgage Bonds ($294.9 million). Settlement of bonds tendered will occur no later than Aug. 9, 2000. Any bonds not tendered or otherwise acquired by SPS are expected to be defeased in accordance with SPS's First Mortgage Indenture by the end of 2000.

    On July 20, 2000, SPS closed a $500 million credit agreement, which terminates on Jan. 20, 2002. The funds from this credit agreement will be used for general corporate purposes, including commercial paper backup and costs resulting from Texas and New Mexico deregulation legislation such as 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 2—Regulation and Rate Matters for more information.

    SPS closed a credit agreement on Feb. 25, 2000. The commitment under the credit agreement is $300 million and terminates on Feb. 23, 2001 and will be used primarily for commercial paper backup but also provides for direct borrowings.

    PSCo and its subsidiary, PSCCC, closed on a $600 million credit agreement on July 20, 2000, 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 terminates on July 19, 2001, replaces 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.

    During the second quarter of 2000, NRG completed an initial public offering of 28,170,000 shares priced at $15 per share. NRG also granted the underwriters an over-allotment option to purchase an additional 4,225,500 shares. In June 2000, the underwriters exercised their option and purchased the additional shares. Upon completion of the initial public offering, Xcel Energy owns approximately 147,600,000 Class A shares of NRG common stock, or 82 percent of NRG's outstanding shares. Management has concluded that this offering of NRG stock will 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 will be used 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.

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XCEL ENERGY INC. AND SUBSIDIARIES

SUPPLEMENTAL CONSOLIDATED CONDENSED STATEMENTS OF INCOME

(UNAUDITED)

(Thousands of Dollars, Except per Share Data)

				Six Months Ended June 30
				2000			1999
Operating revenues:
	Electric utility			$	2,517,279		$	2,315,008
	Gas utility				718,360			660,430
	Nonregulated and other				902,634			250,157
	Equity earnings from investments in affiliates				70,089			27,336
		Total revenue			4,208,362			3,252,931
Operating expenses:
	Electric fuel and purchased power—utility				1,020,779			901,171
	Cost of gas sold and transported—utility				449,614			416,224
	Cost of sales—nonregulated and other				406,621			147,909
	Other operating and maintenance expenses—utility				679,649			667,147
	Other operating and maintenance expenses—nonregulated				285,230			115,835
	Depreciation and amortization				385,158			328,748
	Taxes (other than income taxes)				181,445			190,795
	Special charges—write down of CellNet stock				937			3,412
		Total operating expenses			3,409,433			2,771,241
Operating income					798,929			481,690
Other income (deductions)—net					(13,242	)		(7,833	)
Interest charges and financing costs:
	Interest charges—net of amount capitalized				311,236			180,089
	Distributions on redeemable preferred securities of subsidiary trusts				19,400			19,400
		Total interest charges and financing costs			330,636			199,489
Income before income taxes and extraordinary item					455,051			274,364
Income taxes					144,979			60,022
Income before extraordinary item					310,072			214,346
Extraordinary item (See Note 2)					(13,658	)		—
Net income					296,414			214,346
Dividend requirements and redemption premiums on Xcel Energy preferred stock					2,121			3,171
Earnings available for common shareholders				$	294,293		$	211,175
Weighted average common shares outstanding:
	Basic				336,663			330,770
	Diluted				336,769			330,954
Earnings per share—basic and diluted before extraordinary item				$	0.91		$	0.64
Extraordinary item (see Note 2)				$	(0.04	)	$	—
Earnings per share—basic and diluted				$	0.87		$	0.64

See Notes to the Supplemental Consolidated Condensed Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

SUPPLEMENTAL CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(Thousands of Dollars)

					Six Months Ended June 30
					2000			1999
Operating activities:
	Net income				$	296,414		$	214,346
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization				407,409			345,124
		Nuclear fuel amortization				20,675			24,867
		Deferred income taxes				33,045			(18,743	)
		Amortization of investment tax credits				(7,013	)		(7,016	)
		Allowance for equity funds used during construction				(743	)		(3,584	)
		Distributions in excess of (less than) equity earnings of unconsolidated affiliates				(61,384	)		14,399
		Conservation incentive accrual adjustment—noncash				—			35,035
		Extraordinary item (See Note 2)				13,658			—
		Change in accounts receivable				(66,468	)		3,238
		Change in inventories				20,855			23,066
		Change in other current assets				(18,454	)		29,677
		Change in accounts payable				9,816			(27,341	)
		Change in other current liabilities				19,528			(54,422	)
		Change in other assets and liabilities				3,023			(10,158	)
			Net cash provided by operating activities			670,361			568,488
Investing activities:
	Nonregulated capital expenditures and asset acquisitions					(1,793,959	)		(985,459	)
	Utility capital/construction expenditures					(442,956	)		(470,709	)
	Allowance for equity funds used during construction					743			3,584
	Proceeds from disposition of property, plant and equipment					2,747			512
	Investments in external decommissioning fund					(26,443	)		(21,119	)
	Equity investments, loans and deposits for nonregulated projects					(70,028	)		(77,606	)
	Collection of loans made to nonregulated projects					339			39,956
	Other investments—net					(53,519	)		(24,909	)
			Net cash used in investing activities			(2,383,076	)		(1,535,750	)
Financing activities:
	Short-term borrowings—net					85,300			1,045,694
	Proceeds from issuance of long-term debt—net					2,404,630			465,685
	Repayment of long-term debt, including reacquisition premiums					(1,014,739	)		(275,441	)
	Proceeds from issuance of Xcel Energy common stock					51,376			48,090
	Proceeds from the public offering of NRG stock					453,705			—
	Dividends paid					(250,709	)		(245,467	)
			Net cash provided by financing activities			1,729,563			1,038,561
Net increase in cash and cash equivalents						16,848			71,299
Cash and cash equivalents at beginning of period						139,731			99,031
Cash and cash equivalents at end of period					$	156,579		$	170,330

See Notes to the Supplemental Consolidated Condensed Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

SUPPLEMENTAL CONSOLIDATED CONDENSED BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)

				June 30 2000			Dec. 31 1999
ASSETS
Current assets:
	Cash and cash equivalents			$	156,579		$	139,731
	Accounts receivable—net of allowance for bad debts of $12,340 and $13,043, respectively				891,650			800,066
	Accrued unbilled revenues				363,273			410,798
	Materials and supplies inventories at average cost				387,074			306,524
	Fuel and gas inventories at average cost				108,238			152,874
	Prepayments and other				315,587			250,951
		Total current assets			2,222,401			2,060,944
Property, plant and equipment, at cost:
	Electric utility				15,092,500			14,807,684
	Gas utility				2,313,390			2,266,516
	Nonregulated property and other				5,151,652			3,242,410
	Construction work in progress				547,845			533,046
		Total property, plant and equipment			23,105,387			20,849,656
	Less: accumulated depreciation				(8,500,169	)		(8,153,434	)
	Nuclear fuel—net of accumulated amortization of $944,012 and $923,336, respectively				97,314			102,727
	Net property, plant and equipment				14,702,532			12,798,949
Other assets:
	Investments in unconsolidated affiliates				1,442,519			1,439,002
	Nuclear decommissioning fund investments				547,498			514,011
	Other investments				182,146			137,075
	Regulatory assets				564,498			566,727
	Deferred charges and other				673,022			553,650
		Total other assets			3,409,683			3,210,465
		Total Assets		$	20,334,616		$	18,070,358
LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt			$	557,762		$	431,049
	Short-term debt				1,523,099			1,432,686
	Accounts payable				819,817			793,139
	Taxes accrued				219,015			260,676
	Dividends payable				128,737			127,568
	Other				495,650			438,101
		Total current liabilities			3,744,080			3,483,219
Deferred credits and other liabilities:
	Deferred income taxes				1,853,366			1,779,046
	Deferred investment tax credits				206,623			214,008
	Regulatory liabilities				557,999			442,204
	Benefit obligations and other				477,726			420,140
		Total deferred credits and other liabilities			3,095,714			2,855,398
Minority interest in subsidiaries					257,477			14,696
Long-term debt					7,087,558			5,827,485
Mandatorily redeemable preferred securities of subsidiary trusts (see Note 5)					494,000			494,000
Preferred stockholders' equity					105,340			105,340
Common stock and paid-in capital					3,401,040			3,126,447
Retained earnings					2,298,335			2,253,800
Leveraged shares held by ESOP at cost					(8,248	)		(11,606	)
Accumulated comprehensive income					(140,680	)		(78,421	)
		Total common stockholders' equity			5,550,447			5,290,220
Commitments and contingencies
		Total Liabilities and Equity		$	20,334,616		$	18,070,358

See Notes to the Supplemental Condensed Financial Statements

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Xcel Energy Inc.

NOTES TO SUPPLEMENTAL CONSOLIDATED
CONDENSED FINANCIAL STATEMENTS

    In the opinion of management, the accompanying unaudited consolidated condensed financial statements contain all adjustments necessary to present fairly the financial position of Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) as of June 30, 2000, and Dec. 31, 1999, the results of its operations for the six months ended June 30, 2000 and 1999, and its cash flows for the six months ended June 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 financial statements in Exhibit 99.02. The following notes should be read in conjunction with such policies and other disclosures in the Form 8-K.

1. Business Developments

    NRG—In January 2000, NRG reached agreement to purchase 1,875 Mw 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 Mw 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 fourth quarter of 2000.

    In March 2000, NRG purchased 1,708 Mw 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-Mw 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 August 2000, NRG was named the successful bidder in the South Australian Government's electricity privatization auction for Flinders Power, South Australian's final generation company to be privatized. NRG agreed to pay (AUS) $313 million ($180 million US) for a 100 year lease of the Flinders Power assets. Flinders Power includes two power stations totaling 760 Mw, the Leigh Creek coal mine and a dedicated rail line. The lease agreement also includes managing the long-term fuel supply and power purchase agreement of the 180-Mw Osborne Cogeneration Station. The transaction is expected to close in the third quarter of 2000.

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2. Regulation and Rate Matters

Restructuring Legislation

    SPS is an integrated electric utility and serves approximately 385,000 retail customers in portions of the states of Texas, New Mexico, Oklahoma and Kansas. Over 97 percent of SPS's retail customers, sales and revenues are in Texas and New Mexico. SPS serves wholesale customers, within its service territory, that comprise approximately 30-35 percent of total electric revenues and Kwh sales. Restructuring legislation has been enacted in Texas and New Mexico, as summarized below. SPS has made and continues to make filings with the PUCT and the NMPRC, as required by each state's legislation, 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. Texas is expected to institute a 5-percent pilot program beginning June 2001. State and federal regulators will be addressing a number of issues related to the implementation of restructuring during 2000 and 2001. SPS is diligently working to satisfy the legislative and regulatory requirements in developing its transition plans. It is anticipated that the implementation approach being developed in Texas, as discussed below, will satisfy the legislative and regulatory requirements in New Mexico and will be consistent with other state and federal regulations.

Overview of New Mexico Legislation

    On April 8, 1999, New Mexico enacted the Electric Utility Restructuring Act of 1999, which provides for customer choice for residential, small commercial and educational customers beginning Jan. 1, 2001, and all remaining retail customers beginning Jan. 1, 2002. Customers of a municipal utility and customers of a distribution cooperative utility will be afforded choice only if the respective utility elects to participate. 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-by-passable wires charge, which must be included in transition plan filings. SPS must separate its utility operations into at least two segments: 1) energy generation and competitive services and 2) 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 January 2000, SPS petitioned the NMPRC to file its transition plan by June 1, 2000. Additionally, SPS requested that the NMPRC postpone the beginning of customer choice for certain retail customers until June 1, 2001, and postpone the completion of SPS corporate separation from Jan. 1, 2001, to Jan. 1, 2002. On May 16, 2000, the NMPRC approved: 1) a one-year delay of customer choice for residential, small commercial and educational customers to Jan. 1, 2002, 2) a six-month delay in customer choice for commercial and industrial customers to July 1, 2002, 3) a seven-month delay for completion of SPS corporate separation by Aug. 1, 2001 and 4) a utility transition plan filing date of June 1, 2000.

Overview of Texas Legislation

    On June 18, 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 legislation requires, among other things, a rate freeze for all customers, effective Sept. 1, 1999, until Jan. 1, 2002, together with an annual earnings test through 2001; a 6-percent rate reduction for those

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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. 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.

    Overall, SB-7's objective is to introduce full retail competition into the Texas electric utility industry. SB-7 requires each utility to unbundle its business activities into three separate legal entities: 1) a power generation company, 2) a regulated transmission and distribution company, and 3) 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. SB-7 specifically addresses competition in the Texas Panhandle, where SPS operates, recognizing that certain transmission constraints exist within the region that may require full retail customer choice to develop on a more structured schedule than the rest of the state. SPS must file a transition to competition plan with the PUCT by Dec. 1, 2000. SPS, with no estimated net stranded costs, 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 business activities relating to power generation, transmission, and distribution and retail electric provider services. In summary, SPS has committed to separate into distinct businesses and to operate in an arm's length manner so that the transactions between affiliated entities and regulated entities do not confer any undue competitive advantages on Xcel Energy's businesses compared with non-affiliates. In April 2000, the PUCT approved SPS's business separation plan. Overall, the plan provides for the separation of all competitive energy services by Sept. 1, 2000, 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. Prior to any legal separation and unbundling, SPS will be required to address the provisions limiting or otherwise affecting such activities contained in its first mortgage bond indenture. SPS has arranged interim financing, as approved by the NMPRC, to enable SPS to make open market purchases, and to complete a tender offer and the monetary defeasance of all outstanding First Mortgage Bonds. 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.

    On April 18, 2000, SPS entered into a stipulation with the staff of the PUCT and other significant parties to the NCE/NSP merger docket, which was filed with the PUCT, and among other things, specifically addresses SPS implementation plans to meet the requirements of the Texas deregulation

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legislation. In summary, 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. 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. These divestitures represent approximately 64-71 percent of the generation capacity owned by SPS and its affiliates. SPS expects some or all of these divestitures to be completed by the end of 2001. Assuming these divestitures are completed, approximately 1,281 to 1,608 megawatts of generation capacity in Texas and New Mexico would be retained by Xcel Energy through an affiliated power generation company. 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 scheduled to meet the SEC's pooling-of-interests requirements.

    The stipulation also resolved certain issues related to the merger between NCE and NSP and concluded that such merger is in the public interest. On May 30, 2000, the PUCT issued a rate order approving the stipulation. SPS has committed, contingent upon closing of the NCE/NSP merger, 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 are anticipated to be held in the fourth quarter of 2000.

    On July 24, 2000, SPS commenced a fixed spread tender offer to purchase for cash the remaining $294.9 million total principal amount of five series of SPS' First Mortgage Bonds. Under the terms of the offer, SPS will purchase the remaining bonds of each series at a price [determined by the yield to maturity for bonds that are not redeemable and to the first redemption date for bonds that are redeemable], at the time of tender, equal to the sum of the yield on the applicable referenced U.S. Treasury Note plus a fixed spread. The purchase offer expired on Aug. 4, 2000, with approximately 92 percent of the outstanding bonds purchased. SPS currently intends that all bonds which are not tendered or otherwise acquired by SPS (approximately 8 percent of the total outstanding First Mortgage Bonds) will be defeased by the end of 2000. The bonds will be defeased by depositing with the trustee cash sufficient to pay the principal amount of the outstanding First Mortgage Bonds at maturity or the first redemption date, the applicable redemption date, the applicable redemption

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premium at the first redemption date and accrued interest to maturity or the first redemption date. Upon defeasance, all obligations of SPS under its Indenture and the First Mortgage Bonds would be discharged.

Financial Reporting Matters

    With the issuance of a final written order by the PUCT on May 30, 2000, addressing the implementation of electric utility restructuring for SPS, management believes that sufficient details of a transition plan to competition now exist allowing for a reasonable determination of the impacts of the deregulation of SPS's generation business. Accordingly, SPS discontinued the application of SFAS 71 for that portion of its business during the second quarter of 2000. SPS applied the provisions of SFAS No. 101, "Regulated Enterprises—Accounting for the Discontinuation of SFAS 71", and Emerging Issues Task Force Consensus No. 97-4, "Deregulation of the Pricing of Electricity—Issues Related to the Application of FASB Statements No. 71 and 101" for SPS's electric generation business. While the above rate order only addresses Texas operations, SPS plans to pursue a similar strategy to implement the restructuring legislation enacted in New Mexico and believes that all of its generation will ultimately be deregulated. Accordingly, SPS has applied SFAS 101 to all jurisdictions of its generation business. SPS's transmission and distribution business continues to meet the requirements of SFAS 71, as that business remains regulated. During the second quarter 2000, SPS wrote off its generation-related regulatory assets and other deferred costs totaling approximately $19 million. This resulted in an after-tax extraordinary charge of approximately $13.7 million against the earnings of Xcel Energy and SPS. The total impacts of deregulation may be affected by the results of future state and federal regulatory proceedings prior to actual implementation of full competition, estimated 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, the refinancing of securities, 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.

SPS 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. For this same period, SPS had approximately $21.4 million in under-recovered fuel costs associated with the Texas retail jurisdiction. In July 2000, the PUCT approved a settlement agreement between SPS and the General Counsel of the PUCT, which provided for the recovery of

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substantially all fuel costs, including approximately $12.1 million of the Texas retail jurisdictional portion of the Thunder Basin judgment.

    On June 30, 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 emergency application on July 21, 2000, seeking to increase its fixed fuel factor, to be effective Sept. 1, 2000. SPS was approximately $18 million under-recovered in fuel costs associated with the Texas retail jurisdiction through May 2000 as a result of recent increases in natural gas costs. SPS has committed to file an additional application seeking to surcharge its Texas retail customers the under-recovered amount above including any related interest.

Other Rate Matters

    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.

    On April 14, 2000, PSCo filed an application with the CPUC requesting authority to shut down and abandon its Leyden Natural Gas Underground Storage Facility located northwest of the City of Arvada, Colo., during 2001, after 40 years of operation. The application seeks approval of a formal decommissioning plan. The plan outlines PSCo's proposal to plug and abandon the wells that are currently being used to inject and withdraw gas from the mine and requests approval of the costs to decommission and shut down the facility, which are currently estimated at approximately $8.6 million. In June 2000, an ALJ determined that the notice was adequate and the application was proper. Hearings and testimony are scheduled for the third quarter of 2000. PSCo has requested recovery of these costs and its remaining plant investments in the retail rate case filed in July 2000.

    On Feb. 14, 2000, NSP-Wisconsin filed an application with the Public Service Commission of Wisconsin (PSCW) to increase electric rates for 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 anticipated in current rates. The surcharge factor is expected to increase revenues by approximately $6.5 million in 2000 and represents an increase for a typical residential electric customer 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.

    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 ordered NSP-Minnesota to reduce the surcharge level to 0.68 percent (consistent with current costs to be recovered) and to refund cumulative overcollections of approximately $24 million. 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.

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3. Commitments and Contingent Liabilities

    As of June 30, 2000, Seren had approximately $5 million of intangible assets related to CellNet Data Systems, Inc. In February 2000, CellNet filed for Chapter 11 bankruptcy protection. Although recovery of these assets is not assured at this time, pending the resolution of CellNet's financial difficulties, NSP-Minnesota is working with CellNet to restructure our contracts with them to provide recovery.

    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 sought reconsideration of the FERC order on June 30, 2000.

    The circumstances set forth in Note 6 to Xcel Energy's financial statements in Exhibit 99.02 appropriately represent, in all material respects, the current status of commitments and contingent liabilities regarding public liability for claims resulting from any nuclear incident.

4. Short-Term Borrowings

    At June 30, 2000, Xcel Energy and its subsidiaries had approximately $1.5 billion of short-term debt outstanding at a weighted average interest rate of 6.22 percent.

5. Financial Instruments

    As of June 30, 2000, NRG had seven interest rate swap agreements with notional amounts totaling approximately $880 million. If the swaps had been discontinued on June 30, 2000, NRG would have owed the counter-parties approximately $4.4 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 entered into 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 the London Interbank Offered Rate. The swap expires on June 1, 2009.

    A second swap effectively converts a $16 million issue of non-recourse variable rate debt into a 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 of non-recourse variable rate debt into fixed rate debt. The swap expires on June 30, 2019 and is secured by the Killingholme assets.

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    NRG entered into three additional forward swap agreements to hedge against interest rate risk associated with future corporate bond offerings. The swaps expire on December 31, 2000.

6. Other Comprehensive Income

    Xcel Energy's other comprehensive income consists of net income, a gain on from NRG's stock offering, foreign currency translation adjustments related to investments in international projects and changes in the fair value of investments in certain marketable securities. Other comprehensive income for the first six months of 2000 and 1999 is listed below.

7. Segment Information

    Xcel Energy has four reportable segments: Electric Utility, Gas Utility and two of its nonregulated energy businesses, NRG and Xcel International.

Business Segments

Six months ended 6/30/2000		Electric Utility			Gas Utility			NRG			Xcel International			All Other			Reconciling Eliminations			Consolidated Total
(Thousands of dollars)
Operating revenues from external customers		$	2,516,887		$	718,275		$	805,906			—		$	96,729			—		$	4,137,797
Intersegment revenues			569			7,972			601			—			43,713		$	(52,379	)		476
Segment net income (loss)		$	179,653		$	40,964		$	46,682		$	27,913		$	8,991		$	(7,789	)	$	296,414

Six months ended 6/30/1999		Electric Utility			Gas Utility			NRG			Xcel Internalational			All Other			Reconciling Eliminations			Consolidated Total
(Thousands of dollars)
Operating revenues from external customers (b)		$	2,314,606		$	660,333		$	97,133			—		$	153,024			—		$	3,225,096
Intersegment revenues			664			5,313			748			—			49,994		$	(56,220	)		499
Segment net income (loss)		$	168,123		$	32,379		$	1,401		$	18,075		$	517		$	(6,149	)	$	214,346

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8. Pro Forma—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 six-month periods ended June 30.

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