UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2005
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from                to                  

 

Commission File Number: 1-3034

 

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

 

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

 

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

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ý Yes o No

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

ý Yes o No

 

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

 

Class		Outstanding at April 27, 2005
Common Stock, $2.50 par value		402,258,533 shares

 

 

TABLE OF CONTENTS

 

PART I — FINANCIAL INFORMATION
			Item 1. Financial Statements
				CONSOLIDATED STATEMENTS OF OPERATIONS
				CONSOLIDATED STATEMENTS OF CASH FLOWS
				CONSOLIDATED BALANCE SHEETS
				CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
				NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
		Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
		Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
		Item 4. CONTROLS AND PROCEDURES
Part II — OTHER INFORMATION
	Item 1. Legal Proceedings
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
	Item 5. Other Information
	Item 6. Exhibits
SIGNATURES
Certifications Pursuant to Section 302
Certifications Pursuant to Section 906
Statement Pursuant to Private Litigation

 

2

 

PART I – FINANCIAL INFORMATION
Item 1. Financial Statements

 

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

 

		Three Months Ended March 31,
(Thousands of Dollars, Except Per Share Data)		2005			2004
Operating revenues:
Electric utility		$	1,539,165		$	1,473,600
Natural gas utility		836,969			762,808
Nonregulated and other		23,555			25,240
Total operating revenues		2,399,689			2,261,648
Operating expenses:
Electric fuel and purchased power – utility		761,408			678,693
Cost of natural gas sold and transported – utility		668,786			594,252
Cost of sales – nonregulated and other		10,685			12,033
Other operating and maintenance expenses – utility		402,470			393,645
Other operating and maintenance expenses – nonregulated		8,089			7,422
Depreciation and amortization		191,789			169,567
Taxes (other than income taxes)		81,938			84,798
Total operating expenses		2,125,165			1,940,410
Operating income		274,524			321,238
Interest and other income, net of nonoperating expenses (see Note 8)		492			(421		)
Allowance for funds used during construction - equity		5,183			8,456
Interest charges and financing costs:
Interest charges – (includes other financing costs of $6,479 and $7,426, respectively)		113,641			113,831
Allowance for funds used during construction - debt		(4,833		)	(6,103		)
Total interest charges and financing costs		108,808			107,728
Income from continuing operations before income taxes		171,391			221,545
Income taxes		45,509			72,413
Income from continuing operations		125,882			149,132
Income (loss) from discontinued operations - net of tax (see Note 2)		(4,404		)	779
Net income		121,478			149,911
Dividend requirements on preferred stock		1,060			1,060
Earnings available to common shareholders		$	120,418		$	148,851
Weighted average common shares outstanding (thousands):
Basic		401,116			398,583
Diluted		424,449			421,921
Earnings per share – basic:
Income from continuing operations		$	0.31		$	0.37
Discontinued operations		(0.01		)	0.00
Earnings per share – basic		$	0.30		$	0.37
Earnings per share – diluted:
Income from continuing operations		$	0.30		$	0.36
Discontinued operations		(0.01		)	0.00
Earnings per share – diluted		$	0.29		$	0.36

 

See Notes to Consolidated Financial Statements

 

3

 

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(Thousands of Dollars)

 

		Three Months Ended March 31,
		2005			2004
Operating activities:
Net income		$	121,478		$	149,911
Remove (income) loss from discontinued operations		4,404			(779		)
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		198,426			178,623
Nuclear fuel amortization		10,066			11,596
Deferred income taxes		5,662			(1,974		)
Amortization of investment tax credits		(2,905		)	(3,055		)
Allowance for equity funds used during construction		(5,183		)	(8,456		)
Undistributed equity in earnings of unconsolidated affiliates		6,963			(998		)
Unrealized (gain) loss on derivative financial instruments		2,467			2,807
Change in accounts receivable		(16,964		)	(15,462		)
Change in inventories		119,090			73,777
Change in other current assets		106,382			120,260
Change in accounts payable		(174,436		)	(153,708		)
Change in other current liabilities		42,354			59,555
Change in other noncurrent assets		17,684			40,083
Change in other noncurrent liabilities		35,936			35,604
Operating cash flows used in discontinued operations		85,376			(100,004		)
Net cash provided by operating activities		556,800			387,780
Investing activities:
Utility capital/construction expenditures		(301,978		)	(242,067		)
Allowance for equity funds used during construction		5,183			8,456
Investments in external decommissioning fund		(20,145		)	(20,145		)
Nonregulated capital expenditures and asset acquisitions		(2,208		)	—
Restricted cash		—			36,288
Other investments — net		10,798			1,814
Investing cash flows provided by discontinued operations		—			(3,330		)
Net cash used in investing activities		(308,350		)	(218,984		)
Financing activities
Short-term borrowings –net		(103,300		)	32,000
Proceeds from issuance of long-term debt		99,889			—
Repayment of long-term debt, including reacquisition premiums		(121,752		)	(145,574		)
Proceeds from issuance of common stock		1,343			—
Repurchase of stock		—			(32,023		)
Dividends paid		(84,156		)	(75,867		)
Financing cash flows used in discontinued operations		(200		)	(200		)
Net cash used in financing activities		(208,176		)	(221,664		)
Net (decrease) increase in cash and cash equivalents		40,274			(52,868		)
Net increase in cash and cash equivalents -discontinued operations		3,309			4,091
Net increase in cash and cash equivalents –adoption of FIN No. 46		—			3,408
Cash and cash equivalents at beginning of year		25,403			564,213
Cash and cash equivalents at end of quarter		$	68,986		$	518,844

 

See Notes to Consolidated Financial Statements

 

4

 

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)

 

		March 31, 2005			Dec. 31, 2004
ASSETS
Current assets:
Cash and cash equivalents		$	68,986		$	25,403
Accounts receivable – net of allowance for bad debts of $34,164 and $34,694, respectively		780,555			763,591
Accrued unbilled revenues		419,149			435,431
Materials and supplies inventories – at average cost		159,019			161,323
Fuel inventory – at average cost		64,355			64,265
Natural gas inventories – at average cost		98,088			214,964
Recoverable purchased natural gas and electric energy costs		209,412			264,628
Derivative instruments valuation – at market		163,613			129,218
Prepayments and other		155,793			149,687
Current assets held for sale and related to discontinued operations		314,150			362,730
Total current assets		2,433,120			2,571,240
Property, plant and equipment, at cost:
Electric utility plant		18,319,934			18,236,957
Natural gas utility plant		2,637,584			2,617,552
Common utility and other		1,620,264			1,483,589
Construction work in progress		708,327			721,335
Total property, plant and equipment		23,286,109			23,059,433
Less accumulated depreciation		(9,187,679		)	(9,053,834		)
Nuclear fuel – net of accumulated amortization: $1,155,294 and $1,145,228, respectively		106,124			74,308
Net property, plant and equipment		14,204,554			14,079,907
Other assets:
Investments in unconsolidated affiliates		67,156			79,386
Nuclear decommissioning fund and other investments		1,001,537			969,647
Regulatory assets		986,805			850,636
Derivative instruments valuation – at market		400,383			424,786
Prepaid pension asset		650,222			642,873
Other		186,111			177,555
Noncurrent assets held for sale and related discontinued operations		370,950			508,813
Total other assets		3,663,164			3,653,696
Total assets		$	20,300,838		$	20,304,843
LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt		$	215,567		$	223,655
Short-term debt		209,000			312,300
Accounts payable		730,473			904,909
Taxes accrued		287,193			209,910
Dividends payable		83,690			83,405
Derivative instruments valuation – at market		82,886			135,098
Other		322,451			350,451
Current liabilities held for sale and related to discontinued operations		71,761			116,266
Total current liabilities		2,003,021			2,335,994
Deferred credits and other liabilities:
Deferred income taxes		2,099,115			2,074,942
Deferred investment tax credits		140,121			143,028
Regulatory liabilities		1,798,780			1,630,545
Derivative instruments valuation – at market		538,589			450,883
Asset retirement obligations		1,108,394			1,091,089
Customer advances		301,322			303,928
Minimum pension liability		63,967			62,669
Benefit obligations and other		365,640			328,521
Noncurrent liabilities held for sale and related to discontinued operations		30,057			79,106
Total deferred credits and other liabilities		6,445,985			6,164,711
Minority interest in subsidiaries		3,334			3,220
Commitments and contingent liabilities (see Note 5)
Capitalization:
Long-term debt		6,236,611			6,353,020
$ 400-million, 5-year, senior unsecured credit facility		240,000			140,000
Preferred stockholders’ equity - authorized 7,000,000 shares of $100 par value; outstanding shares: 1,049,800		104,980			104,980
Common stockholders’ equity - authorized 1,000,000,000 shares of $2.50 par value; outstanding shares: 2005 – 401,835,013; 2004 – 400,461,804		5,266,907			5,202,918
Total liabilities and equity		$	20,300,838		$	20,304,843

 

See Notes to Consolidated Financial Statements

 

5

 

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
AND OTHER COMPREHENSIVE INCOME
(UNAUDITED)
(Thousands)

 

		Common Stock Issued
		Number of Shares		Par Value			Capital in Excess of Par Value			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
Three months ended March 31, 2005 and 2004
Balance at Dec. 31, 2003		398,965		$	997,412		$	3,890,501		$	368,663		$	(90,136	)	$	5,166,440
Net income										149,911						149,911
Currency translation adjustments													5,394			5,394
After-tax unrealized and realized losses related to derivatives -net (see Note 7)													(5,502		)	(5,502		)
Unrealized gain on marketable securities													123			123
Comprehensive income for the period																149,926
Dividends declared: Cumulative preferred stock of Xcel Energy										(1,060		)				(1,060		)
Common stock										(75,000		)				(75,000		)
Issuances of common stock – net proceeds		1,717		4,292			24,922									29,214
Purchase for restricted stock issuance		(1,800	)	(4,500		)	(27,523		)							(32,023		)
Balance at March 31, 2004		398,882		$	997,204		$	3,887,900		$	442,514		$	(90,121	)	$	5,237,497
Balance at Dec. 31, 2004		400,462		$	1,001,155		$	3,911,056		$	396,641		$	(105,934	)	$	5,202,918
Net income										121,478						121,478
Minimum pension liability													220			220
After-tax unrealized and realized losses related to derivatives - net (see Note 7)													1,778			1,778
Unrealized gain on marketable securities													27			27
Comprehensive income for the period																123,503
Dividends declared: Cumulative preferred stock of Xcel Energy										(1,060		)				(1,060		)
Common stock										(83,380		)				(83,380		)
Issuances of common stock – net proceeds		1,373		3,433			21,493									24,926
Balance at March 31, 2005		401,835		$	1,004,588		$	3,932,549		$	433,679		$	(103,909	)	$	5,266,907

 

See Notes to Consolidated Financial Statements

 

6

 

XCEL ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

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 March 31, 2005, and Dec. 31, 2004; the results of its operations and changes in stockholders’ equity for the three months ended March 31, 2005 and 2004; and its cash flows for the three months ended March 31, 2005 and 2004. Due to the seasonality of Xcel Energy’s electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results.

 

The significant accounting policies followed by Xcel Energy are set forth in Note 1 to the consolidated financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2004. The following notes should be read in conjunction with such policies and other disclosures in the Annual Report on Form 10-K.

 

1. Accounting Policies

 

FASB Interpretation No. 47 (FIN No. 47) – In April 2005, the Financial Accounting Standards Board (FASB) issued FIN No. 47 to clarify the scope and timing of liability recognition for conditional asset retirement obligations pursuant to Statement of Financial Accounting Standard (SFAS) No. 143 - “Accounting for Asset Retirement Obligations”.  The interpretation requires that a liability be recorded for the fair value of an asset retirement obligation, if the fair value is estimable, even when the obligation is dependent on a future event.  FIN No. 47 further clarified that uncertainty surrounding the timing and method of settlement of the obligation should be factored into the measurement of the conditional asset retirement obligation rather than affect whether a liability should be recognized.  Implementation is required to be effective no later than the end of fiscal years ending after Dec. 15, 2005.  Additionally, FIN No. 47 will permit but not require restatement of interim financial information during any period of adoption.  Both recognition of a cumulative change in accounting and disclosure of the liability on a pro forma basis are required for transition purposes.  Xcel Energy is evaluating the impact of FIN No. 47, however, it is not expected to have a material impact on results of operations or financial position due to the expected recovery in customer rates.

 

Reclassifications – Certain items in the statements of operations and balance sheets have been reclassified from prior period presentation to conform to the 2005 presentation. These reclassifications had no effect on net income or earnings per share. The reclassifications were primarily related to the presentation of Utility Engineering operations as discontinued following the announcement of its sale in March 2005, as discussed below.

 

2. Discontinued Operations

 

A summary of the subsidiaries presented as discontinued operations is discussed below. Results of operations as well as assets and liabilities for the divested businesses and the businesses held for sale are reported on a net basis as a component of discontinued operations for all periods presented. Amounts previously reported for 2004 have been restated to conform to the 2005 discontinued operations presentation.

 

Regulated Utility Segments

 

During 2004, Xcel Energy reached an agreement to sell its regulated electric and natural gas subsidiary, Cheyenne Light, Fuel and Power Company (CLF&P).  The sale was completed on January 21, 2005.

 

Nonregulated Subsidiaries — All Other Segment

 

Utility Engineering - In March 2005, Xcel Energy agreed to sell its non-regulated subsidiary, Utility Engineering (UE), to Zachary Group, Inc.  In April 2005, Zachary acquired all of the outstanding shares of UE.  Quixx Corp., a subsidiary of UE that partners in cogeneration projects, was not included in the transaction.  Xcel Energy recorded an immaterial loss in the first quarter of 2005 as a result of the transaction.

 

Seren — On Sept. 27, 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Seren Innovations, Inc., a wholly owned broadband communications services subsidiary. Seren delivers cable television, high-speed Internet and telephone service over an advanced network to approximately 45,000 customers in St. Cloud, Minn., and Concord and Walnut Creek, Calif.  An after-tax impairment charge, including disposition costs, of $143 million, or 34 cents per share, was recorded in 2004. Xcel

 

7

 

Energy expects to complete the sale in the latter half of 2005.

 

Xcel Energy International and e prime — In 2004, Xcel Energy exited all business conducted by its nonregulated subsidiary, e prime, and most conducted by Xcel Energy International.  Xcel Energy sold all of the contractual assets of e prime and closed on the sale of one of the Argentina subsidiaries of Xcel Energy International during the first quarter of 2004.  The sale price was immaterial and approximated the book value of Xcel Energy’s investment.

 

Summarized Financial Results of Discontinued Operations

 

(Thousands of dollars)		Utility Segments			All Other			Total
Three months ended March 31, 2005
Operating revenue		$	6,579		$	21,663		$	28,242
Operating and other expenses		6,131			28,812			34,943
Pretax income (loss) from operations of discontinued components		448			(7,149		)	(6,701		)
Income tax expense (benefit)		268			(2,565		)	(2,297		)
Net income (loss) from discontinued operations		$	180		$	(4,584	)	$	(4,404	)
Three months ended March 31, 2004
Operating revenue and equity in project income		$	19,099		$	67,574		$	86,673
Operating and other expenses		17,866			71,205			89,071
Other income		—			827			827
Pretax income (loss) from operations of discontinued components		1,233			(2,804		)	(1,571		)
Income tax expense (benefit)		444			(2,794		)	(2,350		)
Net income (loss) from operations of discontinued components		$	789		$	(10	)	$	779

 

The major classes of assets and liabilities held for sale and related to discontinued operations are as follows:

 

(Thousands of dollars)		March 31, 2005			Dec. 31, 2004
Cash		$	30,137		$	31,187
Restricted cash		—			15,000
Trade receivables — net		6,188			22,036
Deferred income tax benefits		251,123			234,305
Other current assets		26,702			60,202
Current assets held for sale		314,150			362,730
Property, plant and equipment — net		59,240			151,590
Deferred income tax benefits		298,072			338,863
Other noncurrent assets		13,638			18,360
Noncurrent assets held for sale		370,950			508,813
Current portion of long-term debt		—			—
Accounts payable — trade		22,519			28,151
Other current liabilities		49,242			88,115
Current liabilities held for sale		71,761			116,266
Long-term debt		—			24,800
Other noncurrent liabilities		30,057			54,306
Noncurrent liabilities held for sale		$	30,057		$	79,106

 

NRG - In December 2003, Xcel Energy divested its ownership interest in NRG Energy Inc. (NRG), a former independent power production subsidiary that had filed for bankruptcy protection in May 2003.  Changes in the accounting estimates of Xcel Energy’s NRG-related tax benefits may continue to occur in the future as better information becomes available regarding the treatment of the divestiture transaction by tax authorities.  Cash flows from receipt of NRG-related deferred income tax benefits did occur in 2003 and 2004, and will continue in the future as tax loss carryforwards related to the investment in and financial results of NRG are utilized on Xcel Energy’s tax returns.  Approximately $439 million of deferred tax benefits related to NRG are included in discontinued operations assets listed above as of Mar. 31, 2005.   In addition, payments to NRG creditors under the NRG bankruptcy settlement are included in Xcel Energy’s cash flows from discontinued operations in the statement of cash flows for the three months ended March 31, 2004.

 

8

 

3.     Tax Matters — Corporate-Owned Life Insurance

 

Interest Expense Deductibility — PSR Investments, Inc. (PSRI), a wholly owned subsidiary of Public Service Company of Colorado (PSCo), a utility subsidiary of Xcel Energy, owns and manages permanent life insurance policies, known as corporate-owned life insurance (COLI) policies, on some of PSCo’s employees. At various times, borrowings have been made against the cash values of these COLI policies and deductions taken on the interest expense on these borrowings. The Internal Revenue Service (IRS) has challenged the deductibility of such interest expense deductions and has disallowed the deductions taken in tax years 1993 through 2001.

 

After consultation with tax counsel, Xcel Energy contends that the IRS determination is not supported by tax law. Based upon this assessment, management believes that the tax deduction of interest expense on the COLI policy loans is in full compliance with the law. Accordingly, PSRI has not recorded any provision for income tax or related interest or penalties that may be imposed by the IRS and has continued to take deductions for interest expense related to policy loans on its income tax returns for subsequent years.

 

In April 2004, Xcel Energy filed a lawsuit in U.S. District Court for the District of Minnesota against the IRS to establish its entitlement to deduct policy loan interest for tax years 1993 and 1994.  In December 2004, Xcel Energy filed suit in U.S. Tax Court in Washington D.C. for tax years 1995 through 1997 and again in March 2005 for tax years 1998 and 1999.  Xcel Energy expects to request that the tax court consolidate and stay its petitions pending the decision in the district court litigation.  Xcel Energy intends to bring a motion for summary judgment in the district court litigation.  Its brief in support of this motion is expected to be filed on or before May 3, 2005, with oral arguments presented to the district court on June 17, 2005.  The litigation could require several years to reach final resolution. Although the ultimate resolution of this matter is uncertain, it could have a material adverse effect on Xcel Energy’s financial position and results of operations. Defense of Xcel Energy’s position may require significant cash outlays, which may or may not be recoverable in a court proceeding.

 

Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2004, would reduce earnings by an estimated $311 million.  In 2004, Xcel Energy received formal notification that the IRS will seek penalties. If penalties (plus associated interest) also are included, the total exposure through Dec. 31, 2004, is approximately $368 million.  Xcel Energy estimates its annual earnings for 2005 would be reduced by $40 million, after tax, which represents 9 cents per share, if COLI interest expense deductions were no longer available.

 

Accounting for Uncertain Tax Positions — In July 2004, the FASB discussed potential changes or clarifications in the criteria for recognition of tax benefits, which may result in raising the threshold for recognizing tax benefits, which have some degree of uncertainty. The FASB has not issued any proposed guidance, but an exposure draft may be released in the second quarter of 2005.  Xcel Energy is unable to determine the impact or timing of any potential accounting changes required by the FASB, but such changes could have a material impact on Xcel Energy’s financial statements.

 

4. Rates and Regulation

 

Federal Regulation

 

Market-Based Rate Authority — The Federal Energy Regulatory Commission (FERC) regulates the wholesale sale of electricity.  In addition to FERC’s traditional cost of service methodology for determining the rates allowed to be charged for wholesale electric sales, in the 1990’s FERC began to allow utilities to make sales at market-based rates.  In order to obtain market-based rate authorization from the FERC, utilities such as the utility subsidiaries of Xcel Energy have been required to submit analyses demonstrating that they did not have market power in the relevant markets.  Xcel Energy and its utility subsidiaries were previously granted market-based rate authority by FERC.  The utility subsidiaries include Northern States Power Company, a Minnesota corporation (NSP-Minnesota), Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin), PSCo and Southwestern Public Service Co. (SPS), which are collectively referred to as the Utility Subsidiaries.

 

In 2004, the FERC adopted two indicative screens (an uncommitted pivotal supplier analysis and an uncommitted market share analysis) as a revised test to assess market power.  Passage of the two screens creates a rebuttable presumption that an applicant does not have market power, while the failure creates a rebuttable presumption that the utility does have market power.  An applicant or intervenor can rebut the presumption by performing a more extensive delivered-price test analysis.  If an applicant is determined to have generation market power, the applicant has the opportunity to propose its own mitigation plan or may implement default mitigation established by the FERC.  The default mitigation limits prices for sales of power to cost-based rates within areas where an

 

9

 

applicant is found to have market power.

 

Xcel Energy filed the required analysis applying the FERC’s two indicative screens on behalf of itself and the Utility Subsidiaries with the FERC on Feb. 7, 2005.  This analysis demonstrated that all of the Utility Subsidiaries, with the exception of PSCo, passed the pivotal supplier analysis in their own control areas and all adjacent markets, but that all failed the market share analysis in their own control areas, and in the case of NSP-Minnesota and NSP-Wisconsin, which jointly operate a single control area and accordingly are analyzed as one company, in certain adjacent markets.  Numerous parties filed interventions and requested that FERC set the analysis for hearing.  Certain parties asked the FERC to revoke the market-based rate authority of the Utility Subsidiaries.  It is accordingly expected that the FERC will set the market-based rate authorizations for investigation and hearing under Section 206 of the Federal Power Act.  At that time, the Utility Subsidiaries expect to submit a delivered-price test analysis to support the continuance of market-based rate authority in their control areas.  Xcel Energy also expects that following the April 1, 2005 commencement of the Midwest Independent Transmission System Operator, Inc. (MISO) energy market, referred to as the Day 2 market, NSP-Minnesota and NSP-Wisconsin will be analyzed as part of the larger MISO market, and that those companies will pass both of the FERC’s indicative screens in the larger MISO market.  Xcel Energy does not expect the mitigation measures imposed, if any, to have a significant financial impact on its Utility Subsidiaries’ commodity marketing operations.

 

Midwest Independent Transmission System Operator, Inc.

 

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

 

MISO initiated the Day 2 wholesale market on April 1, 2005, including locational marginal pricing.  While it is anticipated that the Day 2 market will provide short-term efficiencies through a region-wide generation dispatch and increased reliability, as well as long-term benefits through dispatch of power from the most cost-effective sources of generation or transmission, there are costs associated with Day 2.  To date, the information systems required to operate the market have performed satisfactorily.  However, during the initial days of operation, MISO centrally dispatched generation in a manner different than pre-market individual utility dispatch, with more dispatch of natural gas and oil fired peaking units for similar load and weather conditions.  MISO has stated that energy imports from coal and hydro generation located outside the MISO region were also substantially lower than in pre-market periods.  It is not known if these conditions are short-term implementation issues related to the complexity of centralized market operations and market participant inexperience.  In early April 2005, the FERC sent letters to several MISO market participants, including Xcel Energy, with questions regarding generation price offers submitted to MISO in comparison to reference prices calculated by the MISO independent market monitor.  Xcel Energy submitted a timely response to the FERC letter.  Xcel Energy and other market participants are actively working with MISO, the independent market monitor and the FERC to resolve Day 2 market implementation issues.  Xcel Energy is also considering its regulatory and other options if the initial market operation issues continue.

 

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

 

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

 

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

 

On March 29, 2005, NSP-Wisconsin received an order from the Public Service Commission of Wisconsin (PSCW) granting its requests to defer the costs and benefits attributable to the start-up of MISO.  Because it is difficult to predict or quantify the costs or benefits, the deferral order provides temporary protection to both utilities and customers, until a long-term solution regarding recovery of Day 2 costs can be designed and implemented.  Also, NSP-Wisconsin received an order granting its request to record energy market transactions on a net basis. The netting of transactions is consistent with the approach envisioned by the FERC in approving the transmission and energy markets tariff and is consistent with generally accepted accounting principles.

 

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

 

Other Regulatory Matters – By Jurisdiction

 

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

 

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

 

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

 

NSP-Wisconsin 2005 Fuel Cost Recovery - On April 22, 2005, NSP-Wisconsin filed an application with the PSCW to increase electric rates by $10 million, or 2.7 percent, annually to provide for recovery of forecasted increased costs of fuel and purchased power over the balance of 2005.  March 2005 actual fuel costs were approximately 13 percent higher than authorized recovery in current base rates, and the current forecast for the remainder of 2005 shows costs outside the annual range by 9.6 percent.  If approved as filed, NSP-Wisconsin is expected to recover approximately $6.2 million, subject to refund, in additional revenue in 2005, based on an implementation date of May 19, 2005 under provisions of the PSCW fuel cost recovery rules.  Final rates would be determined later in 2005 after a full audit and public hearing, and would remain in effect until new rates set in the 2006 rate case are implemented.

 

PSCo Resource Plan — In December 2004, the Colorado Public Utilities Commission (CPUC) approved a settlement agreement between PSCo and many intervening parties concerning its future resource plan.  As a part of the settlement the CPUC approved

 

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PSCo’s plan to construct a 750-megawatt net output pulverized coal-fired unit at the Comanche Station located near Pueblo, Colo. and transfer up to 250 megawatts of capacity ownership from the 750-megawatt unit to Intermountain Rural Electric Association (IREA) and Holy Cross Energy, if negotiations with those entities are successful.

 

On April 12, 2005, PSCo signed agreements with IREA that define the respective rights and obligations of PSCo and IREA in the transfer of 25 percent of the capacity ownership of the new 750-megawatt Comanche unit to IREA.  Transfer of ownership to IREA is contingent upon IREA’s successful completion of its financing, among other things, and is expected to occur in the fourth quarter of 2005.

 

On April 8, 2005, the Colorado Department of Public Health and Environment issued draft air quality permits for the new Comanche unit for public comment.  The public comment period for the permit extends until May 15, 2005, and a public hearing is expected to be held in late May or early June.  Final permits are likely to be issued several weeks after close of the comment period.  Construction on the plant is planned to commence when final air quality permits are received.

 

PSCo plans to contract for the construction of the new Comanche unit in primarily five components.  These primary contracts would cover construction related to the boiler, turbine, air quality control, stack and most other work.  Contracts are expected to be executed throughout the summer of 2005.

 

On Feb. 16, 2005, PSCo filed an application with the CPUC for a certificate of public convenience and necessity for construction of the transmission associated with the new Comanche unit.  The transmission project consists primarily of a new 345-kilovolt transmission line that will be constructed between Comanche Station and Daniels Park, Colorado.  As part of the transmission project, PSCo plans to upgrade an existing 230-kilovolt line to 345-kilovolt operation.  The CPUC has set this matter for hearing before an administrative law judge during the summer of 2005.

 

Colorado Legislative Changes (PSCo) - In November 2004, an amendment to the Colorado statutes was passed requiring implementation of a renewable energy portfolio standard for electric service.  The new law requires PSCo to generate, or cause to be generated, a certain level of electricity from eligible renewable resources.  Generation of electricity from renewable resources, particularly solar energy, may be a higher-cost alternative to traditional fuels, such as coal and natural gas.  Such incremental costs are expected to be recovered from customers.  On March 29, 2005, the CPUC initiated a proceeding to determine the rules and regulations required to implement the renewal portfolio standard.  The CPUC has scheduled hearings regarding the proposed rules for July 11-14, 2005.  Final rules are expected to become effective later this year.

 

Texas Retail Fuel Cost (SPS)  — Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor.  In May 2004, SPS filed with the Public Utility Commission of Texas (PUCT) its periodic request for fuel and purchased power cost recovery for electric generation and fuel management activities for the period from January 2002 through December 2003.  SPS requested approval of approximately $580 million of Texas-jurisdictional fuel and purchased power costs for the two-year period.  Intervenor and PUCT staff testimony was filed in October 2004 and hearings were held in December 2004.  Intervenor testimony contained objections to SPS’ methodology for assigning average fuel costs to wholesale sales, among other things.  Recovery of $49 million to $86 million of the requested amount was contested by multiple intervenors.

 

In January 2005, SPS filed its post-hearing briefs disputing the intervenor objections.  The administrative law judge issued his recommended proposal for the decision (PFD) on April 15, 2005, which was generally favorable to SPS.  Prior to issuance of the PFD, SPS had entered into a non-unanimous stipulation with the PUCT staff and several of the intervenors.  The stipulation would provide reasonable regulatory certainty for SPS on all key issues raised in this proceeding.  Certain intervenors, although not presently signatories to the non-unanimous stipulation, are expected to file agreement with the majority of the stipulation principles, while opposing certain other provisions.  If the PUCT does not approve the filed stipulation without modification, SPS, as well as the other signatories have the option of withdrawing from the stipulation.  If one or more signatories withdraw from the stipulation, the PUCT could revert to the consideration of the PFD or continue consideration of the non-unanimous stipulation with the remaining signatories.  It is uncertain as to whether the PUCT will approve the stipulation or will adopt any or all of the administrative law judge’s recommendations contained in the PFD.  The settlement reflects a potential liability of approximately $25 million, which is consistent with the reserve that SPS accrued during the fourth quarter of 2004 related to this proceeding.  SPS believes this estimate is appropriate and sufficient, if either the stipulation is accepted or if a litigated outcome develops.  A PUCT decision is expected in late May 2005.

 

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5. Commitments and Contingent Liabilities

 

Environmental Contingencies

 

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, the subsidiary involved is pursuing or intends to pursue insurance claims and believes it will recover some portion of these costs through such claims. Additionally, where applicable, the subsidiary involved 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 in its consolidated financial statements.

 

Clean Air Interstate and Mercury Rules - In March 2005, the Environmental Protection Agency (EPA) issued two significant new air quality rules.  The Clean Air Interstate Rule (CAIR) further regulates sulfur dioxide (SO₂) and nitrogen oxide (NOx) emissions, and the Clean Air Mercury Rule regulates mercury emissions from power plants for the first time.

 

The objective of the CAIR is to cap emissions of SO₂ and NOx in the eastern United States, including Minnesota, Texas and Wisconsin within Xcel Energy’s service territory.  Xcel Energy generating facilities in other states are not affected.  When fully implemented, CAIR will reduce SO₂ emissions in 28 eastern states and the District of Columbia by over 70 percent and NOx emissions by over 60 percent from 2003 levels. It is designed to address the transportation of fine particulates, ozone and emission precursors to non-attainment downwind states.  CAIR has a two-phase compliance schedule, beginning in 2009 for NOx and 2010 for SO₂, with a final compliance deadline in 2015 for both emissions.  Under CAIR, each affected state will be allocated an emissions budget for SO₂ and NO_X that will result in significant emission reductions.  It will be based on stringent emission controls and forms the basis for a cap-and-trade program.   State emission budgets or caps decline over time.  States can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.

 

The EPA’s Clean Air Mercury Rule also uses a national cap-and-trade system and is designed to achieve a 70 percent reduction in mercury emissions.  It affects all coal- and oil-fired generating units across the country greater than 25 megawatts.  Compliance with this rule also occurs in two phases, with the first phase beginning in 2010 and the second phase in 2018.  States will be allocated mercury allowances based on their baseline heat input relative to other states and by coal type.  Each electric generating unit will be allocated mercury allowances based on its percentage of total coal heat input for the state.

 

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

 

Fort Collins Manufactured Gas Plant (MGP) Site — Prior to 1926, Poudre Valley Gas Co., a predecessor of PSCo, operated an MGP in Fort Collins, Colo., not far from the Cache la Poudre River. In 1926, after acquiring the Poudre Valley Gas Co., PSCo shut down the MGP site and has sold most of the property.  An oily substance similar to MGP byproducts was discovered in the Cache la Poudre River.  On Nov. 10, 2004, PSCo entered into an agreement with the EPA, the city of Fort Collins and Schrader Oil Co., under which PSCo will perform remediation and monitoring work.  Work is currently under way, with completion of construction anticipated in the second quarter of 2005, followed by ongoing operation and maintenance.  On or about April 28, 2005, PSCo brought a contribution action against Schrader Oil Co. and related parties alleging Schrader Oil Co. released hazardous substances into the environment and these releases increased the migration and environmental impact of the MGP byproducts at the site.  PSCo requested damages, including a portion of the costs PSCo incurred to investigate and remove contaminated sediments from the Cache la Poudre River.

 

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Legal Contingencies

 

Lawsuits and claims arise in the normal course of business. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition of them. The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have a material adverse effect on Xcel Energy’s financial position and results of operations.

 

Fru-Con Construction Corporation v. Utility Engineering, et al. – On March 28, 2005 Fru-Con Construction Corporation (Fru-Con) commenced a lawsuit in United States District Court for the Eastern District of California against UE and the Sacramento Municipal Utility District (SMUD) for damages allegedly suffered during the construction of a natural gas-fired, combined cycle power plant in Sacramento County.  Fru-Con’s complaint alleges that it entered into a contract with SMUD to construct the power plant and further alleges that UE was negligent with regard to the design services it furnished to SMUD.  UE denies this claim and intends to vigorously defend itself in this lawsuit.  Because this lawsuit was commenced prior to the April 8, 2005 closing of the sale of UE to Zachary Group, Inc., Xcel Energy is obligated to indemnify Zachary up to $17.5 million.  Pursuant to the terms of its professional liability policy, UE is insured up to $35 million.

 

Xcel Energy Inc. Securities Class Action Litigation — On July 31, 2002, a lawsuit purporting to be a class action on behalf of purchasers of Xcel Energy’s common stock between Jan. 31, 2001, and July 26, 2002, was filed in the U.S. District Court for the District of Minnesota. The complaint named Xcel Energy and current and former Xcel Energy and NRG executives as defendants. Among other things, the complaint alleged violations of Section 10(b) of the Securities Exchange Act and Rule 10(b-5) related to allegedly false and misleading disclosures concerning various issues including but not limited to “round trip” energy trades, the nature, extent and seriousness of liquidity and credit difficulties at NRG and the existence of cross-default provisions (with NRG credit agreements) in certain of Xcel Energy’s credit agreements. After filing the lawsuit, several additional lawsuits were filed with similar allegations and all have been consolidated.  On Jan. 14, 2005, the District Court issued an order of preliminary approval for a settlement reached by the parties.  Under the terms of the settlement, the plaintiffs are to receive $80 million, with Xcel Energy’s insurance carriers paying $62.5 million, and Xcel Energy paying $17.5 million.  Xcel Energy’s portion of the settlement payment was accrued at Dec. 31, 2004.  On April 1, 2005, the District Court entered a final order approving the settlement and dismissing the lawsuit with prejudice.

 

Xcel Energy Inc. Shareholder Derivative Action - Edith Gottlieb vs. Xcel Energy Inc. et al; Essmacher vs. Brunetti; McLain vs. Brunetti - In August 2002, a shareholder derivative action was filed in the U.S. District Court for the District of Minnesota (Gottlieb), purportedly on behalf of Xcel Energy, against the directors and certain present and former officers, citing allegedly false and misleading disclosures concerning various issues and asserting breach of fiduciary duty. This action has been consolidated with other similar securities class actions and an amended complaint was filed.  A settlement in the federal derivative lawsuit was reached in December 2004 and given preliminary approval by the District Court in an order dated Jan. 14, 2005.  Under the terms of the settlement, Xcel Energy agreed to adopt certain corporate governance measures and pay plaintiff’s attorneys’ fees and expenses in an amount not to exceed $125,000.  On April 1, 2005, the District Court entered a final order approving the settlement and dismissing the lawsuit with prejudice.

 

Xcel Energy Employee ERISA Actions - Newcome vs. Xcel Energy Inc.; Barday vs. Xcel Energy Inc. — On Sept. 23, 2002, and Oct. 9, 2002, two essentially identical actions were filed in the U.S. District Court for the District of Colorado, purportedly on behalf of classes of employee participants in Xcel Energy’s and its predecessors’ 401(k) or ESOP plans, from as early as Sept. 23, 1999, forward. The complaints in the actions name as defendants Xcel Energy, its directors, certain former directors and certain present and former officers.  The complaints allege violations of the ERISA in the form of breach of fiduciary duty in allowing or encouraging purchase, contribution and/or retention of Xcel Energy’s common stock in the plans and making misleading statements and omissions in that regard.  On Jan. 14, 2005, the District Court issued an order of preliminary approval related to a settlement reached by the parties.  Under the terms of the settlement, plaintiffs are to receive a payment of $8 million, which will be paid by Xcel Energy’s insurance carrier.  Xcel Energy also agreed, subject to the provisions of the applicable collective bargaining agreement, to undertake to amend the Xcel Energy 401(k) savings plan and its predecessor plans and the New Century Energies employees’ and stock ownership plan for bargaining unit and former nonbargaining unit employees, by permitting certain diversification of Xcel Energy stock held in participants’ accounts in portions of these plans.  On April 1, 2005, the District Court entered a final order approving the settlement and dismissing the lawsuit with prejudice.

 

Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al. — On Nov. 19, 2003, a class action complaint filed in the U.S. District Court for the Eastern District of California by Texas-Ohio Energy, Inc., was served on Xcel Energy naming e prime as a defendant. The lawsuit, filed on behalf of a purported class of large wholesale natural gas purchasers, alleges that e prime falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California. The case has been conditionally transferred to U.S. District Judge Pro in Nevada, who is supervising western area wholesale natural gas marketing litigation.  In an

 

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order entered April 8, 2005, Judge Pro granted the defendants’ motion to dismiss based on the filed rate doctrine.  Plaintiffs have not indicated whether they will appeal this decision.

 

Other Contingencies

 

The circumstances set forth in Notes 15, 16 and 17 to the consolidated financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2004 and Notes 2, 3 and 4 to the consolidated financial statements in this Quarterly Report on Form 10-Q appropriately represent, in all material respects, the current status of other commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident, and are incorporated herein by reference. The following are unresolved contingencies that are material to Xcel Energy’s financial position:

 

•             Tax Matters — See Note 3 to the accompanying consolidated financial statements for discussion of exposures regarding the tax deductibility of corporate-owned life insurance loan interest; and

 

•             Guarantees — See Note 6 to the accompanying consolidated financial statements for discussion of exposures under various guarantees.

 

6. Short-Term Borrowings and Other Financing Instruments

 

Short-Term Borrowings

 

At March 31, 2005, Xcel Energy and its subsidiaries had approximately $209 million of short-term debt outstanding at a weighted average interest rate of 4.19 percent.

 

Guarantees

 

Xcel Energy provides various guarantees and bond indemnities supporting certain of its subsidiaries. The guarantees issued by Xcel Energy guarantee payment or performance by its subsidiaries under specified agreements or transactions. As a result, Xcel Energy’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees issued by Xcel Energy limit the exposure of Xcel Energy to a maximum amount stated in the guarantees. On March 31, 2005, Xcel Energy had issued guarantees of up to $27.4 million with $0.5 million exposure under these guarantees. In addition, Xcel Energy provides indemnity protection for bonds issued by subsidiaries. The total amount of bonds with this indemnity outstanding as of March 31, 2005, was approximately $105 million. The total exposure of this indemnification cannot be determined at this time. Xcel Energy believes the exposure to be significantly less than the total amount of bonds outstanding.

 

7. Derivative Valuation and Financial Impacts

 

Xcel Energy records all derivative instruments on the balance sheet at fair value unless exempted as a normal purchase or sale. Changes in non-exempt derivative instrument’s fair value are recognized currently in earnings unless the derivative has been designated in a qualifying hedging relationship. The application of hedge accounting allows a derivative instrument’s gains and losses to be reflected in Other Comprehensive Income or to offset related results of the hedged item in the statement of operations, to the extent effective. Statement of Financial Accounting Standard (SFAS) No. 133 – “Accounting for Derivative Instruments and Hedging Activities,” as amended, (SFAS No. 133) requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.

 

Xcel Energy records the fair value of its derivative instruments in its Consolidated Balance Sheet as a separate line item identified as Derivative Instruments Valuation for assets and liabilities, as well as current and noncurrent.

 

Cash Flow Hedges

 

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

 

At March 31, 2005, Xcel Energy and its Utility Subsidiaries had various commodity-related contracts designated as cash flow hedges extending through 2009. The fair value of these cash flow hedges is recorded in either Other Comprehensive Income or deferred as a

 

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

 

Xcel Energy and its subsidiaries enter into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for a specific period. These derivative instruments are designated as cash flow hedges for accounting purposes, and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. Xcel Energy expects to recognize in earnings during the next 12 months net losses from Other Comprehensive Income related to interest cash flow hedge contracts of approximately $0.4 million.

 

Gains or losses on hedging transactions for the sales of energy or energy-related products are recorded as a component of revenue, hedging transactions for fuel used in energy generation are recorded as a component of fuel costs, hedging transactions for gas purchased for resale are recorded as a component of gas costs and interest rate hedging transactions are recorded as a component of interest expense. Certain Utility Subsidiaries are allowed to recover in electric or gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility. There was no hedge ineffectiveness in the first quarter of 2005.

 

The impact of the components of hedges on Xcel Energy’s Other Comprehensive Income, included in the Consolidated Statements of Stockholders’ Equity, are detailed in the following tables:

 

		Three months ended March 31,
(Millions of Dollars)		2005			2004
Accumulated other comprehensive income related to cash flow hedges at Jan. 1		$	0.1		$	8.1
After-tax net unrealized losses related to derivatives accounted for as hedges		8.4			(2.9		)
After-tax net realized gains on derivative transactions reclassified into earnings		(6.6		)	(2.6		)
Accumulated other comprehensive income related to cash flow hedges at March 31		$	1.9		$	2.6

 

Fair Value Hedges

 

Xcel Energy enters into interest rate swap instruments that effectively hedge the fair value of fixed rate debt. Changes in the fair value of hedges designated as fair value hedges are recognized in earnings as offsets to the changes in fair values of related hedged assets, liabilities or firm commitments.

 

The fair value of all interest rate swaps is determined through counterparty valuations, internal valuations and broker quotes. There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented.

 

Derivatives Not Qualifying for Hedge Accounting

 

Xcel Energy and its subsidiaries have commodity trading operations that enter into derivative instruments. These derivative instruments are accounted for on a mark-to-market basis in the Consolidated Statements of Operations. The results of these transactions are recorded on a net basis within Operating Revenues on the Consolidated Statements of Operations.

 

Xcel Energy and its subsidiaries also enter into certain commodity-based derivative transaction, not included in trading operations, which do not qualify for hedge accounting treatment. These derivative instruments are accounted for on a mark-to-market basis in accordance with SFAS No. 133.

 

Normal Purchases or Normal Sales Contracts

 

Xcel Energy’s utility subsidiaries enter into contracts for the purchase and sale of various commodities for use in their business operations. SFAS No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the definition of a derivative may be exempted from SFAS No. 133 as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that meet these requirements are documented and exempted from the accounting and reporting requirements of SFAS No. 133.

 

Xcel Energy evaluates all of its contracts within the regulated and nonregulated operations when such contracts are entered to determine if they are derivatives and, if so, if they qualify and meet the normal designation requirements under SFAS No. 133. None

 

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of the derivative contracts entered into within the commodity trading operations qualify for a normal designation.

 

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

 

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

 

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

 

		Three months ended March 31,
(Thousands of Dollars)		2005			2004
Interest income		3,066			3,574
Equity income in unconsolidated affiliates		2,378			846
Other nonoperating income		1,263			997
Minority interest income		111			17
Loss on the sale of assets		(121		)	(379		)
Interest expense on corporate-owned life insurance, net of increase in cash surrender value		(4,695		)	(3,726		)
Other nonoperating expense		(1,510		)	(1,750		)
Total interest and other income, net of nonoperating expenses		$	492		$	(421	)

 

9. Common Stock and Equivalents

 

Xcel Energy has common stock equivalents consisting of convertible senior notes and stock options. The dilutive impacts of common stock equivalents affected earnings per share as follows for the three months ending March 31, 2005 and 2004:

 

		Three months ended March 31, 2005								Three months ended March 31, 2004
(Amounts in thousands, except per share amounts)		Income			Shares		Per-share Amount			Income			Shares		Per-share Amount
Income from continuing operations		$	125,882							$	149,132
Less: Dividend requirements on preferred stock		(1,060		)						(1,060		)
Basic earnings per share:
Income from continuing operations		124,822			401,116		$	0.31		148,072			398,583		$	0.37
Effect of dilutive securities:
$230 million convertible debt		2,811			18,654					2,803			18,654
$57.5 million convertible debt		703			4,663					701			4,663
Stock options		—			16					—			21
Diluted earnings per share:
Income from continuing operations and assumed conversions		$	128,336		424,449		$	0.30		$	151,576		421,921		$	0.36

 

10. Benefit Plans and Other Postretirement Benefits

 

Components of Net Periodic Benefit Cost

 

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

 

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11. Segment Information

 

Xcel Energy has the following reportable segments: Regulated Electric Utility, Regulated Natural Gas Utility and All Other. Commodity trading operations performed by regulated operating companies are not a reportable segment. Commodity trading results are included in the Regulated Electric Utility segment.

 

(Thousands of Dollars)		Regulated Electric Utility			Regulated Natural Gas Utility			All Other			Reconciling Eliminations			Consolidated Total
Three months ended March 31, 2005
Operating revenues from external customers		$	1,539,165		$	836,969		$	23,555		$	—		$	2,399,689
Intersegment revenues		358			1,125			—			(1,483		)	—
Total revenues		$	1,539,523		$	838,094		$	23,555		$	(1,483	)	$	2,399,689
Income (loss) from continuing operations		$	75,389		$	51,265		$	10,270		$	(11,042	)	$	125,882
Three months ended March 31, 2004
Operating revenues from external customers		$	1,473,600		$	762,808		$	25,240		$	—		$	2,261,648
Intersegment revenues		283			3,456			—			(3,739		)	—
Total revenues		$	1,473,883		$	766,264		$	25,240		$	(3,739	)	$	2,261,648
Income (loss) from continuing operations		$	105,325		$	48,234		$	5,556		$	(9,983	)	$	149,132

 

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

 

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,” “projected,” “possible,” “potential” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to:

 

•             Economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures;

 

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

 

•             Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where Xcel Energy has a financial interest;

 

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

 

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

 

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

 

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

 

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

 

•             Increased competition in the utility industry or additional competition in the markets served by Xcel Energy and its subsidiaries;

 

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