UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

[X]

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2004

or

[  ]

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.

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. [X] Yes   [  ] No

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). [X] Yes   [  ] No

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

TABLE OF CONTENTS

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PART I – FINANCIAL INFORMATION

XCEL ENERGY INC. AND SUBSIDIARIES

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

See Notes to Consolidated Financial Statements

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

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

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 June 30, 2004, and Dec. 31, 2003; the results of its operations and stockholders’ equity for the three and six months ended June 30, 2004 and 2003; and its cash flows for the six months ended June 30, 2004 and 2003. Due to the seasonality of Xcel Energy’s electric and natural gas sales and variability of nonregulated operations, such interim 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 consolidated financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2003. 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. 46 (FIN No. 46) — On Jan. 1, 2004, Xcel Energy adopted FIN No. 46, as revised, which requires an enterprise’s consolidated financial statements to include variable interest entities for which the enterprise is determined to be the primary beneficiary. Historically, consolidation has been required only for entities in which an enterprise has a majority voting or controlling interest. As a result, Xcel Energy consolidated a portion of its affordable housing investments made primarily through Eloigne, which were previously accounted for under the equity method. The consolidation had no impact on net income or earnings per share. No other arrangements were determined to be material variable interests requiring disclosure or consolidation under FIN No. 46.

As of June 30, 2004, the assets of the affordable housing investments consolidated as a result of FIN No. 46, as revised, were approximately $143 million and long-term liabilities were approximately $77 million, including long-term debt of $76 million. Investments of $52 million, previously reflected as a component of investments in unconsolidated affiliates, have been consolidated with the entities’ assets initially recorded at their carrying amounts as of Jan. 1, 2004. The long-term debt is collateralized by the affordable housing projects and is nonrecourse to Xcel Energy.

Change in Accounting Principle — Inventory — Effective Jan. 1, 2004, Public Service Company of Colorado (PSCo) changed its method of accounting for the cost of stored natural gas for its local distribution operations from the last-in-first-out (LIFO) pricing method to the average cost pricing method. This change in accounting was approved by the Colorado Public Utilities Commission (CPUC) and was accounted for as a cumulative effect in accordance with the CPUC authorization. The average cost method has historically been used for pricing stored natural gas by both Northern States Power Company, a Minnesota corporation (NSP-Minnesota), and Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin), as well as by PSCo for natural gas stored for use in its electric utility operations.

The cumulative effect of this change in accounting principle resulted in an increase to gas storage inventory and a corresponding decrease to the deferred gas cost accounts of approximately $36 million as of Jan. 1, 2004. Of this amount, $33 million related to current gas storage inventory and $3 million related to long-term gas storage inventory. As gas costs are 100 percent recoverable for PSCo’s local gas distribution operations under PSCo’s gas cost adjustment mechanism, the cumulative effect of this change had no impact on net income or earnings per share. Prior period financial statements were not restated since the CPUC authorized this change effective Jan. 1, 2004. Under the gas cost adjustment mechanism, the decrease in the cost of gas will reduce rates to retail gas customers in Colorado during 2004.

Reclassifications – Certain items in the statements of operations and balance sheets have been reclassified from prior period presentation to conform to the 2004 presentation. These reclassifications had no effect on net income or earnings per share. The reclassifications were primarily related to organizational changes, such as the divestiture of NRG Energy, Inc. (NRG) and other discontinued operations.

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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 2003 have been restated to conform to the 2004 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). As a result of this agreement, CLF&P is classified as held for sale. The sale is pending regulatory approval and is expected to be completed during 2004.

During 2003, Xcel Energy completed the sale of two subsidiaries in its regulated natural gas utility segment, Black Mountain Gas Co. (BMG) and Viking Gas Transmission Co. (Viking), including Viking’s interest in Guardian Pipeline, LLC. As a result, a gain of 5 cents per share was recorded in the first quarter of 2003, related to the sale of Viking. The BMG sale was completed in the third quarter of 2003.

NRG

Until December 2003, NRG was a wholly owned subsidiary of Xcel Energy. Prior to NRG’s bankruptcy filing in May 2003, Xcel Energy accounted for NRG as a consolidated subsidiary. However, as a result of NRG’s bankruptcy filing, Xcel Energy no longer had the ability to control the operations of NRG. Accordingly, effective as of the bankruptcy filing date, Xcel Energy ceased the consolidation of NRG and began accounting for its investment in NRG using the equity method in accordance with Accounting Principles Board Opinion No. 18 — “The Equity Method of Accounting for Investments in Common Stock.” In December 2003, NRG emerged from bankruptcy, and Xcel Energy relinquished its entire ownership interest in NRG. See additional discussion at Note 3.

Nonregulated Subsidiaries — All Other Segment

Xcel Energy International and e prime — During 2003, the board of directors of Xcel Energy approved management’s plan to exit businesses conducted by Xcel Energy International, Inc. (Xcel Energy International) and e prime, Inc. (e prime). Xcel Energy International’s operations primarily include power generation projects in Argentina. e prime provided energy-related products and services, which included natural gas commodity trading and marketing and energy consulting. The assets held for sale are valued on an asset-by-asset basis at the lower of carrying amount or fair value less costs to sell. In applying those provisions, management considered cash flow analyses, bids and offers related to those assets and businesses. In accordance with the provisions of Statements of Financial Accounting Standards (SFAS) No. 144 – “Accounting for the Impairment or Disposal of Long-Lived Assets”, assets held for sale will not be depreciated commencing with their classification as such.

The exit of all business conducted by e prime was completed in 2004. Xcel Energy also completed the sale of one of its Argentina subsidiaries, Hidroelectrica del Sur S.A. (HDS). The sale price of HDS was immaterial and approximated the book value of Xcel Energy’s investment in HDS.

On June 3, 2004, Xcel Energy Argentina Inc. (Xcel Argentina), a wholly owned subsidiary of Xcel Energy International, closed on the sale of the stock of Corporacion Independiente de Energia S.A. (CIESA), which has as its primary asset Central Piedra Buena S.A., a 620 megawatt gas/oil-fired facility in Bahia Blanca, Argentina to Bell Investments and Albanesi S.A. The sale also included the stock of IPC Operations Limited, an energy services company with operations in Buenos Aires, Argentina. The total purchase price was estimated at approximately $26 million, including certain adjustments subject to finalization in the third quarter. Approximately $15 million of the purchase price has been placed in escrow, which is expected to remain in place until the first quarter of 2005, to support Xcel Argentina’s customary indemnity obligations under the purchase agreement. In addition to the purchase price, Xcel Argentina also received approximately $21 million at closing as a redemption of its capital investment from CIESA. The sale resulted in an after-tax gain of $6.1 million, or approximately 1 cent per share, in the second quarter of 2004. The gain includes the realization of $6.9 million of tax benefits related to the now-realizable tax loss from disposition of Xcel Argentina assets.

Xcel Energy International is in the process of marketing its remaining assets and operations to prospective buyers and expects to exit the businesses held for sale during 2004.

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Summarized Financial Results of Discontinued Operations

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

3. NRG Bankruptcy Settlement

In May 2003, NRG filed for bankruptcy to restructure its debt. At the time of the filing, NRG was a subsidiary of Xcel Energy. NRG’s filing included its plan of reorganization and a settlement among NRG, Xcel Energy and members of NRG’s major creditor constituencies.

In December 2003, NRG emerged from bankruptcy. As part of the reorganization, Xcel Energy completely relinquished its ownership interest in NRG. As part of the overall settlement, Xcel Energy agreed to pay $752 million to NRG to settle all claims of NRG against Xcel Energy, and claims of NRG creditors against Xcel Energy. In return for such payments, Xcel Energy received, or was granted, voluntary and involuntary releases from NRG and its creditors.

On Feb. 20, 2004, Xcel Energy paid $400 million to NRG. On April 30, 2004, Xcel Energy paid $328.5 million. The remaining $23.5 million payment was paid on May 28, 2004. Xcel Energy met these cash requirements with cash on hand, including tax refund proceeds associated with the NRG bankruptcy, and/or borrowings under its revolving credit facility.

4. Tax Matters — Corporate-Owned Life Insurance

PSCo’s wholly owned subsidiary, PSR Investments, Inc. (PSRI), owns and manages permanent life insurance policies on some of PSCo’s employees, known as corporate-owned life insurance (COLI). 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 IRS has challenged the deductibility of such interest expense deductions and has disallowed the deductions taken in tax years 1993 through 1999.

After consultation with tax counsel, Xcel Energy contends that the IRS determination is not supported by relevant tax law. Based upon this assessment, management continues to believe 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. 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

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operations. Defense of Xcel Energy’s position may require significant cash outlays, which may or may not be recoverable in a court proceeding.

The total disallowance of interest expense deductions for the period of 1993 through 1999, as proposed by the IRS, is approximately $279 million. Additional interest expense deductions for the period 2000 through 2003 are estimated to total approximately $300 million. Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2003, would reduce earnings by an estimated $254 million after tax. At June 30, 2004, Xcel Energy estimates its annual earnings for 2004 would be reduced by an estimated $35 million, after tax, which represents 8 cents per share using 2003 share levels, if COLI interest expense deductions were no longer available.

5. Rates and Regulation

Market Based Rate Authority Rule Proposal – On April 14, 2004, the Federal Energy Regulatory Commission (FERC) initiated a new proceeding on future market-based rates authorizations and issued interim requirements for FERC jurisdictional electric utilities that have been granted authority to make wholesale sales at market-based rates. NSP-Minnesota, NSP-Wisconsin, PSCo and Southwestern Public Service Company (SPS) currently have wholesale market-based rate authorization from the FERC. The FERC adopted a new interim method to assess generation market power and modified measures to mitigate market power where it is found. The FERC recently upheld and clarified the interim requirements on rehearing in an order issued July 8, 2004. The assessments will be made of all initial market-based rate applications and triennial reviews on an interim basis. An assessment will be made of whether the utility is a pivotal supplier based on a control area’s annual peak demand and whether it complies with market share requirements on a seasonal basis. If an applicant is determined to have generation market power, the applicant has the opportunity to propose its own mitigation plan or may implement default mitigation established by the FERC. The default mitigation limits prices for sales of power to cost-based rates within areas where an applicant is found to have market power. Xcel Energy is reviewing the new interim requirements to determine what, if any, impact they will have on the wholesale market-based rate authority of the utility subsidiaries. Xcel Energy is required to file an updated market power analysis using the new interim market power screens on or before Feb. 7, 2005. As a related matter, in addition to the triennial update filing, PSCo and SPS were required by the FERC, in its orders addressing the merger to form New Century Energies, Inc. in 1997, to file a supplemental market power analysis six months prior to the completion of the intertie transmission line between their systems to address the competitive impacts of that project. PSCo and SPS filed the required supplemental analysis on July 20, 2004.

Department of Energy Blackout Report – On April 6, 2004, the U.S. Department of Energy issued its final report regarding the Aug. 14, 2003 electric blackout in the eastern United States, which did not affect the electric systems of the Xcel Energy regulated utilities. The report recommends 46 specific changes to current statutes, rules or practices in order to improve the reliability of the infrastructure used to transmit electric power. The recommendations include the establishment of mandatory reliability standards and financial penalties for noncompliance. On April 14, 2004, FERC issued a policy statement requiring electric utilities, including the Xcel Energy utility subsidiaries, to submit a report on vegetation management practices and indicating the FERC’s intent to make North American Electric Reliability Council (NERC) reliability standards mandatory. The Xcel Energy utility subsidiaries submitted the required report on their vegetation management practices to the FERC in June 2004. Implementation of the blackout report recommendations and the FERC policy statement could increase future transmission costs, but the extent of this effect cannot be determined at this time.

Generation Interconnection Rules - On June 25, 2004, the FERC issued an order rejecting in part the April 2004 Xcel Energy utility subsidiaries’ compliance filing to FERC Order No. 2003-A, a FERC rule requiring all jurisdictional electric utilities to adopt uniform interconnection procedures and a standard form interconnection agreement for new generators of 20 megawatts or more. The Xcel Energy utility subsidiaries had proposed very limited modifications to the pro forma procedure mandated by the FERC to facilitate compliance by PSCo with Colorado state least cost planning (LCP) rules, which require PSCo to analyze its loads and resource needs and select the least cost resource portfolio taking into account both generation and transmission costs. Xcel Energy argued the limited variations were necessary for PSCo to comply with both Order No. 2003-A and the Colorado LCP rules. The FERC accepted the portions of the compliance filing adopting the pro forma process and agreement, but rejected the variations as contrary to Order No. 2003-A. On July 26, 2004, the Xcel Energy utility subsidiaries requested rehearing of the FERC order. The 2003 PSCo LCP proposal is pending before the CPUC and is expected to be supplemented to address the bid evaluation process.

Midwest ISO Transmission and Energy Markets Tariff – On March 31, 2004, the Midwest Independent Transmission System Operator, Inc. (Midwest ISO) regional transmission organization filed its proposed transmission and energy markets tariff (TEMT), which would establish regional wholesale energy markets using locational marginal cost pricing and financial transmission rights. NSP-Minnesota and NSP-Wisconsin are Midwest ISO members, and their generation plants and transmission systems would operate subject to the tariff if it is approved by the FERC. The Midwest ISO proposed a Dec. 1, 2004 effective date.

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On May 26, 2004, the FERC issued an initial procedural order regarding the TEMT. The FERC found that certain pre-Order 888 “grandfathered” agreements (GFAs) for transmission service could negatively affect implementation of the TEMT, so FERC delayed the effective date of the energy market to March 1, 2005. FERC also set the issue of the GFAs for an expedited hearing process. NSP-Minnesota and NSP-Wisconsin submitted compliance filings regarding their approximately 50 GFAs on June 25, 2004. Approximately 10 GFAs were disputed, and hearings were held June 30, 2004 and July 1, 2004. The other GFAs are not disputed. The primary disputed issues related to responsibility for Midwest ISO TEMT charges that might be billed for loads served under the GFAs. Proposed findings of fact and legal memoranda were filed regarding the disputed GFAs on July 5, 2004. The Administrative Law Judges (ALJ) submitted their recommendations to the FERC on July 28, 2004, recommending that NSP-Minnesota and NSP-Wisconsin generally be found to be the entity financially responsible for TEMT costs for loads served under their GFAs. The ALJ order is subject to further FERC consideration, and Xcel Energy plans to contest the ALJ recommendation. FERC is expected to issue a final decision later in 2004. Xcel Energy also submitted a request for rehearing of the May 26, 2004 order, alleging the expedited hearing process violates both the U.S. Constitution and the federal Administrative Procedure Act.

Implementation of a wholesale regional market using the locational marginal cost pricing and financial transmission rights is expected to provide a benefit to NSP-Minnesota and NSP-Wisconsin through a reduction in overall power costs. However, Xcel Energy opposes certain aspects of the TEMT as proposed, and believes the Midwest ISO should implement the new market mechanisms only after it demonstrates that it will protect reliability. Xcel Energy cannot at this time estimate the total financial impact of the new market structure.

Private Fuel Storage – NSP-Minnesota is part of a consortium of private parties working to establish a private facility for interim storage of spent nuclear fuel. In 1997, Private Fuel Storage, LLC filed a license application with the Nuclear Regulatory Commission (NRC) for a temporary storage site for spent nuclear fuel on the Skull Valley Indian Reservation in Utah. Most issues raised by opponents were favorably resolved or dismissed, however, the likelihood of certain aircraft crashes into the proposed facility was deemed sufficiently credible to be addressed. On May 11, 2004, the NRC issued a safety evaluation report documenting its evaluation of aircraft crash consequences on casks at the proposed private storage facility. The report concluded that an accidental aircraft or ordnance impact at the proposed facility does not pose a credible hazard to public health and safety. The next step is the Atomic Safety and Licensing Board (ASLB) hearings scheduled to begin on August 9, 2004. If successful during these hearings, the ASLB could forward their recommendation in late 2004, and a license could be issued in early 2005.

Minnesota Service Quality Investigation – On Nov. 14, 2003, NSP-Minnesota submitted a proposed service quality plan and an update regarding certain service quality settlement agreement provisions already implemented by NSP-Minnesota. Among other provisions, the proposed service quality plan contains underperformance payments for the failure to meet certain reliability and customer service metrics. On March 10, 2004, the Minnesota Public Utilities Commission (MPUC) issued an order approving the settlement, but modifying it to include an annual independent audit of NSP-Minnesota’s service outage records and requiring additional under-performance payments for any future finding of inaccurate data by an independent auditor. Both state agencies and NSP-Minnesota have the option under the settlement to void the agreement in the event of a significant modification by the MPUC. On May 13, 2004, the MPUC declined to act on both NSP-Minnesota’s Petition for Clarification of the MPUC’s March 10th order and that of another party’s Petition for Reconsideration. On June 2, 2004, NSP-Minnesota submitted a compliance tariff implementing the terms of the MPUC order, including modifications to the settlement. NSP-Minnesota indicated that, if approved by the MPUC, it would accept the terms of the order; if rejected or modified by the MPUC, it would reject the terms of the order. The MPUC is expected to consider this compliance filing later in 2004.

NSP-Minnesota Combustion Turbine Proposal — In November 2003, NSP-Minnesota proposed investing approximately $164 million in generating capacity in Minnesota and South Dakota to ensure adequate electric capacity for its Upper Midwest customers. NSP-Minnesota has received all regulatory approvals for a $100-million project to add two combustion turbines at its Blue Lake peaking plant in Shakopee, Minn., and for a $64-million project to add one turbine at its Angus Anson peaking plant in Sioux Falls, S.D.

Each of the three new turbines would be fired by natural gas and would have a summer capacity of approximately 160 megawatts. Currently, the Blue Lake plant has four units fired by oil and a net dependable capacity of 174 megawatts; the Angus Anson plant has two units that can be fired by either natural gas or oil and a net dependable capacity of 226 megawatts.

As of June 30, 2004, all required state regulatory approvals for these projects have been received, including a certificate of need for the Blue Lake project from the MPUC, a site permit from the Minnesota Environmental Quality Board, air quality permits from the Minnesota Pollution Control Agency, the amended facility permit for the Anson project from the South Dakota Public Utilities Commission and air quality permits from the South Dakota Department of Environment and Natural Resources. Construction on the projects has begun. The projects also require approval by Midwest ISO with regard to interconnection and transmission service

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requests, which is pending.

NRG Tax Complaint — In November 2003, an NSP-Minnesota customer filed a complaint with the MPUC alleging that ratepayers are entitled to a share of the tax benefits attributable to NRG. The customer subsequently supplemented this complaint with sufficient signatures from customers to warrant a formal complaint process by the MPUC. NSP-Minnesota has responded to the complaint, arguing that the requested treatment is not allowed by law and is inconsistent with the MPUC’s directives to ensure full separation of NSP-Minnesota and NRG. The Minnesota Department of Commerce has filed comments recommending denial of the complaint. The Office of the Attorney General indicated that the MPUC should credit Minnesota ratepayers with that portion of the NSP-Minnesota rate that was allocated for tax payments, but never paid as such, applying the credit in a future rate proceeding. NSP-Minnesota is preparing a response against this recommendation. The MPUC is expected to consider this matter later this year.

NSP-Wisconsin Fuel Cost Recovery Filing – On Aug. 2, 2004 NSP-Wisconsin filed an application with the Public Service Commission of Wisconsin (PSCW) to reopen its 2004 rate case for the limited purpose of resetting 2005 electric fuel monitoring costs, and to authorize an increase in Wisconsin retail electric rates to recover forecast increases in fuel and wholesale market purchased energy costs. In its application NSP-Wisconsin indicated an increase of $17.3 million is necessary to avoid under- recovering its 2005 fuel costs based on the most recent forecast. NSP-Wisconsin is requesting the PSCW approve new electric base rates effective Jan. 1, 2005.

PSCo Least-Cost Resource Plan – On April 30, 2004, PSCo filed its 2003 least-cost resource plan (LCP) with the CPUC. PSCo has identified that it needs to provide for 3,600 megawatts of capacity through 2013 to meet load growth and replace expiring contracts. The LCP identifies the resources necessary to meet PSCo’s estimated load requirements. Of the amount needed, PSCo believes 2,000 megawatts will come from new resources, and 1,600 megawatts will come from entering new contracts with existing suppliers whose contracts expire during the resource acquisition period.

As part of its resource plan, PSCo is seeking the waiver of certain CPUC rules, which would allow it to build a new 750 megawatt coal-fired unit at its existing Comanche power plant site located in Pueblo, Colorado. PSCo plans to own 500 megawatts of this new facility. Two of PSCo’s wholesale customers have options to participate in the ownership of the remaining 250 megawatts, and PSCo is in discussions with them regarding the plant’s development.

On April 30, 2004, PSCo also filed an application requesting a certificate of public convenience and necessity for the new coal unit. PSCo also filed a separate application for a specific regulatory plan to address the impacts of purchased capacity contracts on its capital structure and to accelerate the recovery of the costs of financing the new power plant and related transmission prior to commercial operations. The CPUC has consolidated these three applications and has scheduled hearings in November 2004. A decision is expected in late 2004 or early 2005. The procedural schedule is as follows:

The CPUC is expected to decide in a separate docket PSCo’s request for approval of a 500 megawatt renewable energy solicitation with a hearing scheduled for August 2004.

PSCo Capacity Cost Adjustment - In October 2003, PSCo filed an application to recover incremental capacity costs through a purchased capacity cost adjustment (PCCA) rider. The PCCA will recover purchased capacity payments to power suppliers that are not included in the determination of PSCo’s base electric rates determined in its 2002 general rate case or other recovery mechanisms. In May 2004, the CPUC granted the PSCo PCCA application, in part with new rates effective June 1, 2004. Primary provisions of the CPUC ruling include a capped PCCA recovery for the period June 1, 2004 through Dec. 31, 2006 at PSCo’s current predicted capacity payments for a group of specific contracts, which will provide recovery of $20.4 million in 2004, $33.5 million in 2005 and $19.8 million in 2006. In addition, the CPUC excluded seven of the existing contracts from incremental recovery under the PCCA calculation. However, PSCo expects that the capacity costs from these contracts will be eligible for recovery through base rates when PSCo files its next general rate case. The energy costs from these contracts are eligible for recovery through the PSCo electric commodity adjustment clause.

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On July 16, 2004, PSCo filed an Application for Rehearing, Reargument and Reconsideration (ARRR) asking the CPUC to grant rehearing on its decision specifying that the PCCA recovery be limited to budget estimates of purchased capacity costs, instead asking for full recovery of actual purchased capacity payments. Second, the ARRR requests that the CPUC modify its decision to allow PSCo to reflect the relationship of the Air Quality Improvement Rider (AQIR) to the 2004 PCCA rider eliminating the actual amount of double recovery of purchased capacity expense that results from the interaction of PSCo’s AQIR and the PCCA. The existing CPUC decision assumes a double recovery, which is $750,000 greater than the actual amount.

PSCo Electric Department Earning Test Proceedings – As a part of PSCo’s annual electric earnings test, the CPUC has opened a docket to consider whether PSCo’s cost of debt has been adversely affected by the financial difficulties at NRG and, if so, whether any adjustments to PSCo’s cost of capital are appropriate. In its earnings test for 2002, PSCo did not earn above its allowed authorized return on equity and, accordingly, has not recorded any refund obligations. There was no earnings test for 2003.

On May 28, 2004, the CPUC staff and the Office of Consumer Counsel (OCC) filed testimony recommending the CPUC order the use of a pro forma regulatory adjustment to the cost of debt, on $600 million of debt issued by PSCo in September 2002, reducing the cost of debt in this and future proceedings. The CPUC staff recommendation would result in an exclusion of interest costs of $12 million and the OCC recommendation would result in an exclusion of $17 million. PSCo does not anticipate its 2002 earnings will be above its allowed authorized return on equity with these recommended changes in the cost of debt. Hearings are scheduled in October 2004.

PSCo Quality of Service Plan- The PSCo quality of service plan (QSP) provides for bill credits to Colorado retail customers, if PSCo does not achieve certain operational performance targets. During the second quarter of 2004, PSCo filed its calendar year 2003 operating performance results for electric service unavailability, phone response time, customer complaints, accurate meter reading and gas leak repair time measures. PSCo did not achieve the 2003 performance targets for the electric service unavailability measure or the customer complaint measure. Additionally, PSCo filed revisions to its previously filed 2002 electric QSP results for the service unavailability measure. Based on the revised results, PSCo did not achieve the 2002 performance targets for the electric service unavailability measure, creating a bill credit obligation for 2002 and increasing the maximum bill credit obligation for subsequent years’ performance.

As of Dec. 31, 2003, PSCo had accrued an aggregate estimated bill credit obligation of $6.4 million for the 2002 and 2003 calendar years. Based on the updated information and filings discussed above, during the second quarter of 2004, PSCo increased its estimated bill credit liability for these years to $13.4 million. The CPUC’s final approval of the achieved performance measures for 2002 and 2003 is pending. For calendar year 2004, PSCo has evaluated its year to date performance under the QSP and has recorded an additional liability of $5.4 million for the six months ended June 30, 2004. Under the electric QSP, the estimated maximum potential bill credit obligation for calendar 2004 performance is approximately $15.2 million, assuming none of the performance targets are met.

CPUC Reliability Inquiry — The CPUC staff and the Colorado OCC each submitted final reports to the CPUC based on the results of an informal investigation of the reliability of PSCo’s electric distribution system. The staff report recommends that the CPUC review the existing QSP to ensure that the plan provides adequate incentives for PSCo to provide reliable electric service throughout its Colorado service territory. In addition, the staff recommends that the CPUC review the results of PSCo’s 2004 action plan to address certain localized reliability problems that occurred in 2003. The OCC’s consultant recommended that the CPUC initiate an independent performance assessment of PSCo’s electric distribution system and related business practices. PSCo is preparing a response to the final reports of the staff and the OCC. The CPUC is expected to issue a final order regarding the reliability investigation within the next few months.

PSCo Electric Trading Docket - As part of the settlement of the 2002 PSCo general rate case, the parties agreed that PSCo would initiate a docket regarding the status of electric trading after 2004. The proceeding was initiated on Jan. 30, 2004. PSCo’s testimony proposed certain revisions to the business rules governing trading transactions; to continue electric trading on both a generation book and commodity book basis; to establish a defined trading benefit for electric retail customers and to begin trading natural gas as a risk mitigation measure in support of its electric trading. On July 8, 2004, the staff of the CPUC filed testimony regarding electric trading. The staff has raised issues related to the computer model used to allocate costs to trading transactions, PSCo’s ability to track transactions individually, instead of in aggregate for each hour and the allocation of system costs. The staff requested additional reporting through 2006. The proceeding is scheduled to be completed by the end of 2004.

SPS Texas Fuel Cost Recovery – Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor. In May 2004, SPS filed 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 to recover approximately $580

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million of Texas-jurisdictional fuel and purchased power costs for the two-year period. The proceeding has been set for hearing in December 2004, and a decision regarding SPS fuel and purchased power costs incurred through December 2003 is expected in the second quarter of 2005.

In November 2003, SPS submitted a fuel cost surcharge factor application in Texas to recover an additional $25 million of fuel cost under-recoveries accrued during June through September 2003. In February 2004, the parties in the proceeding submitted a unanimous settlement allowing SPS to collect net under-recoveries experienced through December 2003 of $22 million. The surcharge, which was approved by the Public Utility Commission of Texas (PUCT) in March 2004, went into effect May 2004 and will continue for 12 months.

In May 2004, SPS filed another fuel cost surcharge factor application in Texas to recover an additional $32 million of fuel cost recoveries accrued during January through March 2004. In June 2004, the parties in the proceeding submitted a unanimous settlement allowing SPS to collect the $32 million fuel cost under-recoveries surcharge factors for a 12-month period beginning November 2004. The unanimous settlement is pending review and approval by the PUCT.

6. 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.

Carbon Dioxide Emissions Lawsuit - On July 21, 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in federal district court in New York against five utilities, including Xcel Energy, to force reductions in carbon dioxide (CO₂) emissions. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. CO₂ is emitted whenever fossil fuel is combusted, such as in automobiles, industrial operations and coal- or gas-fired power plants. The lawsuits allege that CO₂ emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO₂ emissions. Xcel Energy is prepared to defend itself against the claims contained in the lawsuits. The ultimate financial impact of these lawsuits, if any, is not determinable at this time.

Ashland Manufactured Gas Plant Site (NSP-Wisconsin) - On July 2, 2004, the Wisconsin Department of Natural Resources (WDNR) sent NSP-Wisconsin an invoice for recovery of expenses incurred at the Ashland site between 1994 and March 2003 in the amount of $1.4 million. Failure to pay the invoice may result in referral to the Wisconsin Department of Justice for suit. NSP-Wisconsin is reviewing the invoice to determine whether all costs charged are appropriate. All appropriate insurance carriers have been notified of the WDNR’s invoice and will be invited to participate in any future efforts to address the WDNR’s actions. All costs paid are expected to be recoverable in rates.

Fort Collins Manufactured Gas Plant Site — Prior to 1926, Poudre Valley Gas Co., a predecessor of PSCo, operated a manufactured gas plant (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 gas site and, years later, sold most of the property. In the mid-1990s, contamination associated with MGP operations was discovered on the gas plant site, and PSCo paid for a portion of a partial cleanup. Recently, an oily substance similar to MGP by-products has been discovered in the Cache la Poudre River. PSCo is working with the Environmental Protection Agency (EPA), the Colorado Department of Public Health and Environment, the current site owner and the City of Fort Collins (owner of a former landfill property between the river and the plant site) to address the substance found in the river as well as other environmental issues found on the property. In early 2004, PSCo completed implementation of a work plan to further investigate the sources of contamination of the river at a cost of approximately $1.4 million. The work resulted in removal of contaminated sediments and delineation of the extent of contamination. PSCo is currently in discussions with the EPA, the city of Fort Collins and other stakeholders regarding possible next steps. The EPA has agreed to allow PSCo to take the lead in development and evaluation of alternatives and ultimately the design of the selected alternative to address the remaining contamination in the river. This process is expected to proceed in consultation with the EPA and other stakeholders and to follow the EPA’s national contingency plan. PSCo will likely perform future remediation work for which current cost estimates for the range of alternatives is approximately $7.5 million

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to $9 million. To date, PSCo has spent approximately $1.8 million on the project, including settlement costs negotiated with Fort Collins in 1998. The EPA has also conducted work over the past two years, incurring estimated costs of approximately $1 million to date, for which they will likely seek recovery from PSCo at a future date.

While PSCo has recorded a liability of $7.6 million at June 30, 2004, it lacks sufficient information at this time to determine its ultimate liability for clean up, if different, for this site. PSCo has deferred the costs recorded to date and believes that they will be recovered through future rates. Any costs that are not recoverable from customers will be expensed.

Federal Clean Water Act – The Federal Clean Water Act addresses the environmental impacts of cooling water intakes. In July 2004, the EPA published phase II of the rule that applies to existing cooling water intakes at steam-electric power plants. The rule will require Xcel Energy to perform additional environmental studies at 12 power plants in Minnesota, Wisconsin and Colorado to determine the impact the facilities may be having on aquatic organisms vulnerable to impingement or entrainment. If the studies determine the plants are not meeting the new performance standards established by the phase II rule, physical and/or operational changes may be required at these facilities. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the many uncertainties involved. Preliminary cost estimates range from less than $1 million at some facilities to more than $10 million at others depending on site-specific circumstances. Based on the limited information available, total cost to Xcel Energy is estimated at approximately $64 million. Actual costs may be significantly higher or lower depending on issues such as the resolution of outstanding third-party legal challenges to the rule.

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.

Bender, et al. vs. Xcel Energy – On July 2, 2004, five former NRG officers filed a lawsuit against Xcel Energy in the U.S. District Court for the District of Minnesota. The lawsuit alleges, among other things, that Xcel Energy violated the Employee Retirement Income Security Act of 1974 (ERISA) by refusing to make certain deferred compensation payments to the plaintiffs. The complaint also alleges interference with ERISA benefits, breach of contract related to the nonpayment of certain stock options and unjust enrichment. The complaint alleges damages of approximately $6 million. Xcel Energy believes the suit is without merit.

Nuclear Waste Disposal Litigation – The federal government has the responsibility to dispose of, or permanently store, domestic spent nuclear fuel and other high-level radioactive substances. The Nuclear Waste Policy Act requires the Department of Energy (DOE) to implement a program for nuclear substance management. This includes the siting, licensing, construction and operation of a repository for domestically produced spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive substances at a permanent storage or disposal facility. The federal government has designated the site as Yucca Mountain in Nevada. This designation has resulted in extensive litigation.

On July 9, 2004, the federal Court of Appeals for the District of Columbia issued its decision in consolidated cases challenging regulations and decisions on the federal nuclear waste program. The Court of Appeals rejected challenges by the state of Nevada and other intervenors with respect to the majority of the licensing regulations of the NRC, the congressional resolution selecting Yucca Mountain as the site of the permanent repository, and the DOE and presidential actions leading to the selection of Yucca Mountain. The Court of Appeals vacated the 10,000 year compliance period adopted by EPA regulations governing spent nuclear fuel disposal and incorporated in the NRC regulations governing Yucca Mountain licensing. Xcel Energy has not ascertained the impact of the decision on its nuclear operations and storage of spent nuclear fuel; however, the decision may result in additional delay and uncertainty around disposal of spent nuclear fuel.

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 for pre-trial purposes with other similar securities class actions and an amended complaint was filed. Two additional derivative actions were filed in the state trial court in Hennepin County, Minn. (Essmacher and McLain), against essentially the same defendants, focusing on allegedly wrongful energy trading activities and asserting breach of fiduciary duty for failure to establish adequate accounting controls, abuse of control and gross mismanagement. Considered collectively, the complaints seek compensatory damages, a return of

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compensation received, and awards of fees and expenses. In each of the cases, the defendants filed motions to dismiss the complaint or amended complaint for failure to make a proper pre-suit demand, or in the federal court case, to make any pre-suit demand at all, upon Xcel Energy’s board of directors. In an order dated Jan. 6, 2004, the Minnesota district court judge granted the defendants’ motion to dismiss both of the state court actions. In March 2004, plaintiffs filed notices of appeal related to this decision. In April 2004, plaintiffs withdrew their appeals. On July 12, 2004, the federal court issued an order granting the defendants’ motion to dismiss the shareholder derivative lawsuit. Plaintiffs have 30 days from the entry of judgment to appeal. It is unknown whether the plaintiffs will appeal this decision.

PSCo Colorado Wildfires - In late October 2003, there were two wildfires in Colorado, one in Boulder County and the other in Douglas County. There was no loss of life, but there was property damage associated with these fires. Parties have asserted that trees falling into Xcel Energy distribution lines may have caused one or both fires. Litigation was filed on Jan. 14, 2004, relating to the fire in Boulder County, in Boulder County District Court. There are now 46 plaintiffs, including individuals and insurance companies, and three co-defendants, including PSCo. The plaintiffs assert that they are seeking in excess of $35 million in damages. Xcel Energy believes it has insurance coverage to mitigate the liability in this matter. The ultimate financial impact to PSCo is not determinable at this time.

Department of Labor Audit — In 2001, Xcel Energy received notice from the Department of Labor (DOL) Employee Benefit Security Administration that it intended to audit the Xcel Energy pension plan. After multiple on-site meetings and interviews with Xcel Energy personnel, the DOL indicated on May 18, 2004, that it is prepared to take the position that Xcel Energy, as plan sponsor and through its delegate, the Pension Trust Administration Committee, breached its fiduciary duties under ERISA with respect to certain investments made in limited partnerships and hedge funds in 1997 and 1998.

The DOL has offered to conclude the audit at this time if Xcel Energy is willing to contribute to the plan the full amount of losses from the questioned investments, or approximately $7 million. Xcel Energy formally responded on July 19, 2004 with a letter to the DOL asserting that no fiduciary violations have occurred, and extend an offer to meet to discuss the matter further. If the DOL offer is put into effect, the requested contribution would affect cash flows only and not the net income of Xcel Energy.

Other Contingencies

NSP-Minnesota Natural Gas Customer Billing Errors – In July 2004, NSP-Minnesota made a filing with the MPUC that identified a number of natural gas customers in Minnesota and North Dakota that were over billed because of an incorrect setting on a wireless meter reading device installed on customer meters beginning in late 1998. The incorrect setting occurred when the wireless devices were attached to older meters, allowing them to be read remotely.

Based on analyses of past meter purchases and associated serial numbers, NSP-Minnesota believes the error may have affected approximately 3,200 older residential natural gas meters, but is still determining the number of potential additional residential and commercial natural gas customers that may also be affected. Of the field verifications completed to date, NSP-Minnesota has determined that approximately 12 percent of the devices were incorrectly set. While the problem resulted in some customers being charged for half of their natural gas usage, the verifications made to date indicate that the majority of those who received incorrect bills were charged for twice their actual natural gas usage. NSP-Minnesota is continuing to test meters and will make refunds, if overcharging is found. The number of customers affected and the total amount of refunds will not be known until NSP-Minnesota completes such testing, which is expected to be completed in August 2004. As of June 30, 2004, NSP-Minnesota had accrued $2.4 million based on information currently available. At this time, Xcel Energy is not aware of what action its state regulators may take relating to this matter.

Other Contingencies - The circumstances set forth in Notes 15, 17 and 18 to the consolidated financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2003 and Note 4 of 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.

7. Short-Term Borrowings and Other Financing Instruments

Short-Term Borrowings

At June 30, 2004, Xcel Energy and its subsidiaries had approximately $124 million of short-term debt outstanding at a weighted average interest rate of 2.94 percent.

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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 June 30, 2004, Xcel Energy had issued guarantees of up to $68 million with $1 million of exposure under these guarantees. In addition, Xcel Energy provides indemnity protection for bonds issued by itself and its subsidiaries. The total amount of bonds with this indemnity outstanding as of June 30, 2004, was approximately $108 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.

8. 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 offset related results of the hedged item in the statement of operations, to the extent effective. SFAS No. 133 – “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), as amended, requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.

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

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 June 30, 2004, 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 regulatory asset or liability. This classification is based on the regulatory recovery mechanisms in place. Amounts deferred in these accounts are recorded in earnings as the hedged purchase or sales transaction is settled. This could include the physical purchase or sale of electric energy, the use of natural gas to generate electric energy or gas purchased for resale. As of June 30, 2004, 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

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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 gains from Other Comprehensive Income related to interest rate cash flow hedge contracts of approximately $0.1 million.

Gains or losses on hedging transactions for the sales of electric energy 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 Xcel Energy 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 second quarter of 2004.

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 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 as a component of Operating Revenues on the Consolidated Statements of Operations.

Xcel Energy and its subsidiaries also enter into certain commodity-based transactions, not included in trading operations, which do not qualify for hedge accounting treatment. These derivative instruments are accounted for on a mark-to-market basis in the Consolidated Statement of Operations. The results of these transactions are recorded as a component of Operating Expenses on the Consolidated Statement of Operations.

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 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 the requirements of normal 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 of the contracts entered into within the 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).

9. Detail of Interest and Other Income (Expense), net

Interest and other income (expense), net is comprised of the following:

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10. Common Stock and Equivalents

Xcel Energy has common stock equivalents consisting of convertible senior notes and options. The dilutive impacts of common stock equivalents affected earnings per share as follows for the three and six months ending June 30, 2004 and 2003: