Xcel Energy - 10-Q quarterly report FY

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the transition period from                to

Commission File Number: 1-3034

Xcel Energy Inc.

(Exact name of registrant as specified in its charter)

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. ýYes o No

Indicate by check mark whether the registrant is a shell company (as defind in Rule 12b-2 of the Exchange Act).

o Yes ýNo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

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

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, 2006, and Dec. 31, 2005; the results of its operations and changes in common stockholders’ equity for the three months ended March 31, 2006 and 2005; and its cash flows for the three months ended March 31, 2006 and 2005. 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.

1. Significant Accounting Policies

Except to the extent updated or described below, the significant accounting policies 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, 2005 appropriately represent, in all material respects, the current status of accounting policies, and are incorporated herein by reference.

Statement of Financial Accounting Standards (SFAS) No. 123 (Revised 2004) — “Share Based Payment” (SFAS No. 123R) —In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123R related to equity-based compensation. This statement replaces the original SFAS No. 123 — “Accounting for Stock-Based Compensation.”  Under SFAS No. 123R, companies are no longer allowed to account for their share-based payment awards using the intrinsic value method, which did not require any expense to be recorded on stock options granted with an equal to or greater than fair market value exercise price. Instead, equity-based compensation arrangements will be measured and recognized based on the grant-date fair value using an option-pricing model (such as Black-Scholes or Binomial) that considers at least six factors identified in SFAS No. 123R. An expense related to the difference between the grant-date fair value and the purchase price would be recognized over the vesting period of the options. Under previous guidance, companies were allowed to initially estimate forfeitures or recognize them as they actually occurred. SFAS No. 123R requires companies to estimate forfeitures on the date of grant and to adjust that estimate when information becomes available that suggests actual forfeitures will differ from previous estimates. Revisions to forfeiture estimates will be recorded as a cumulative effect of a change in accounting estimate in the period in which the revision occurs.

Previous accounting guidance allowed for compensation expense related to share-based payment awards to be reversed if the target was not met. However, under SFAS No. 123R, compensation expense for share-based payment awards that expire unexercised due to the company’s failure to reach a certain target stock price cannot be reversed. Any accruals made for Xcel Energy’s restricted stock unit award that was granted in 2004 and is based on a total shareholder return (TSR) cannot be reversed if the target is not met. Implementation of SFAS No. 123R is required for annual periods beginning after June 15, 2005. Xcel Energy adopted the provisions in the first quarter of 2006. Since stock options had vested and other awards were recorded at their fair values prior to implementation of SFAS No. 123R, implementation did not have a material impact on net income or earnings per share. Proforma net income under SFAS No. 123R for the quarter ended March 31, 2005 would not have been materially different than what was recorded.

Since the vesting of our 2004 restricted stock units is predicated on the achievement of a market condition, the achievement of a TSR, the fair value used to calculate the expense related to this award is based on the stock price on the date of grant adjusted for the uncertainty surrounding the achievement of the TSR. Since the vesting of the 2005 and 2006 restricted stock units is predicated on the achievement of a performance condition, the achievement of an earnings per share or environmental measures target, fair values used to calculate the expense on these plans are based on the stock price on the date of grant. The performance share plan awards have been historically settled partially in cash and therefore do not qualify as an equity award, but are accounted for as a liability award. As a liability award, the fair value on which expense is based is remeasured each period based on the current stock price, and final expense is based on the market value of the shares on the date the award is settled. Compensation expense related to share-based awards of approximately $4.7 million and $1.6 million was recorded in the first quarter of 2006 and 2005, respectively. As of March 31, 2006, there was approximately $20.9 million of total unrecognized compensation cost related to non-vested share-based compensation awards. Total unrecognized compensation expense will be adjusted for future changes in estimated forfeitures. We expect to recognize that cost over a weighted-average period of 2.3 years.

There have been no material changes to our outstanding stock options in the first quarter of 2006.

See Note 9 to the consolidated financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2005 for a description of Xcel Energy’s stock-based plans.

Metro Emissions Reduction Project (MERP) Accounting - Allowance for funds used during construction (AFDC) is an amount capitalized as a part of construction costs representing the cost of financing the construction. Generally these costs are recovered from customers as the related property is depreciated. The Minnesota Public Utilities Commision (MPUC) has approved a more current recovery of the financing costs related to the MERP. The in-service plant costs, including the financing costs during construction, are recovered from customers through a MERP rider resulting a lower recognition of AFDC.

Reclassifications – Certain items in the statements of income, balance sheets and the statements of cash flows have been reclassified from prior-period presentation to conform to the 2006 presentation. These reclassifications had no effect on net income or earnings per share. The reclassifications were primarily related to the presentation of Quixx Corp., a former subsidiary of Xcel Energy’s non-regulated subsidiary, Utility Engineering (UE), that partners in cogeneration projects, as discontinued operations. In addition, fees collected from customers on behalf of governmental agencies were reclassified to

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be presented net of the related payments made to the agencies.

In addition, in our Consolidated Statements of Cash Flows for the three months ended March 31, 2005, we have revised the presentation of the proceeds from the sale of Cheyenne Light, Fuel and Power Company (CLF&P) and the presentation of the Xcel Energy International release of restricted cash placed in escrow to support Xcel Energy customary indemnity obligations under the sales agreement,  after determining that the proceeds from the sale of CLF&P and the release of restricted cash at Xcel Energy International should have been classified as cash flows from investing activities. This revision decreased 2005 operating cash flows used in discontinued operations by $83.4 million from those previously reported and increased investing cash flows provided by discontinued operations by the same amount.

2. Discontinued Operations

A summary of the subsidiaries presented as discontinued operations is discussed below. Results of operations for divested businesses and the results of businesses held for sale are reported for all periods presented on a net basis as discontinued operations. In addition, the assets and liabilities of the businesses divested and held for sale in 2006 and 2005 have been reclassified to assets and liabilities held for sale in the accompanying Consolidated Balance Sheets.

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. Assets held for sale are not depreciated. Amounts previously reported for 2005 have been restated to conform to the 2006 discontinued operations presentation.

Regulated Utility Segments

During 2004, Xcel Energy reached an agreement to sell its regulated electric and natural gas subsidiary, CLF&P. The sale was completed on Jan. 21, 2005.

Nonregulated Subsidiaries — All Other Segment

Utility Engineering -In March 2005, Xcel Energy agreed to sell UE to Zachry Group, Inc. (Zachry). In April 2005, Zachry acquired all of the outstanding shares of UE. Xcel Energy recorded an insignificant loss in the first quarter of 2005 as a result of the transaction. In August 2005, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Quixx, which was not included in the sale of UE to Zachry.

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 subsidiary.

On May 25, 2005, Xcel Energy reached an agreement to sell Seren’s California assets to WaveDivision Holdings, LLC, which was completed in November 2005. In July 2005, Xcel Energy reached an agreement to sell Seren’s Minnesota assets to Charter Communications, which was completed in January 2006. An estimated after-tax impairment charge, including disposition costs of $143 million, or 34 cents per share, was recorded in 2004. Based on the sales agreements reached in 2005, the estimate was adjusted to reflect a total asset impairment of $140 million.

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. Cash flows from receipt of NRG-related deferred income tax benefits occurred in 2004 and 2005. Approximately $399 million of remaining deferred tax benefits related to NRG are classified as a component of discontinued operations assets listed below.

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. Rates and Regulation

Midwest Independent Transmission System Operator, Inc. (MISO) Operations —Two of Xcel Energy’s regulated utility subsidiaries, Northern States Power Company, a Minnesota corporation (NSP-Minnesota) and Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin), are members of the MISO. The MISO is a regional transmission organization (RTO) that provides transmission tariff administration services for electric transmission systems, including those of NSP-Minnesota and NSP-Wisconsin. In 2002, NSP-Minnesota and NSP-Wisconsin received all required regulatory approvals to transfer functional control of their high voltage (100 kilovolts and greater) transmission systems to the MISO. The MISO exercises functional control over the operations of these facilities and the facilities of certain neighboring electric utilities.

On April 1, 2005, MISO initiated a regional Day 2 wholesale energy market pursuant to its transmission and energy markets tariff. While it is anticipated the Day 2 market will provide efficiencies through 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 the Day 2 market. NSP-Minnesota and NSP-Wisconsin have requested recovery of these costs within their respective jurisdictions.

The Minnesota Public Utilities Commission (MPUC) has ordered jurisdictional investor-owned utilities in the state to participate with the Minnesota Department of Commerce and other parties in a proceeding that will evaluate suitability of recovery of some of the MISO  Day 2 energy market costs in the variable Fuel Cost Adjustment (FCA). The Minnesota utilities and other parties are currently active in this effort and expect to provide a final report to the MPUC in June 2006.

The Public Service Commission of Wisconsin (PSCW) has authorized Wisconsin utilities, including NSP-Wisconsin, to defer costs and benefits associated with the start up of the MISO Day 2 energy market, pending its investigation of appropriate cost recovery mechanisms over the longer term. Similar to the MPUC, the PSCW is reviewing which costs should be recovered through base rates and which costs should be subject to the fuel cost recovery mechanism. As of March 31, 2006 NSP-Wisconsin had deferred approximately $6.8 million in MISO Day 2 costs.

On March 16, 2006, the Federal Energy Regulatory Commission (FERC) dismissed complaints filed by Wisconsin Public Service Corp. et al. (WPS) asking the FERC to order MISO and the PJM Interconnection, Inc. (PJM) to establish a joint and

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common wholesale energy market (JCM) for the two neighboring RTOs. Xcel Energy opposed the WPS complaints, arguing that MISO and PJM are completing projects shown to be cost beneficial to market participants, and a full JCM could substantially increase market operations costs with limited benefits in terms of energy savings. In dismissing the complaints, the FERC ruled that the progress by MISO and PJM toward the JCM was satisfactory.

MISO and its stakeholders are developing proposals to establish ancillary service markets within its footprint. The proposals would increase the market efficiency by providing a reduced allocation of generation contingency reserves for market participants and by creating economic market opportunities to obtain alternative sources of generating reserves. The proposed implementation of these market design improvements is scheduled for phase-in over the course of 2007, subject to project actions by MISO.

FERC Transmission Rate Case (PSCo and SPS ) — On Sept. 2, 2004, Xcel Energy filed on behalf of Public Service Company of Colorado (PSCo) and Southwestern Public Service Company (SPS) an application to increase wholesale transmission service and ancillary service rates within the Xcel Energy joint open access transmission tariff. PSCo and SPS requested an increase in annual transmission service and ancillary services revenues of $6.1 million. On Feb. 6, 2006, the parties in the proceeding submitted an uncontested offer of settlement that contains a $1.6 million rate increase for PSCo, a formula transmission service rate for PSCo, a 10.5 percent rate of return on common equity, and the phased inclusion of PSCo’s 345 KV tie line costs in wholesale transmission service rates;  the settlement results in a $1.1 million stated rate increase for SPS effective June 2005, and SPS can file a further rate increase effective October 1, 2006. On April 5, 2006, the FERC issued an order approving the uncontested settlement.

Other Regulatory Matters – NSP-Minnesota

NSP-Minnesota Electric Rate Case – In November 2005, NSP-Minnesota requested an electric rate increase of $168 million or 8.05 percent. This increase was based on a requested 11 percent return on common equity, a projected common equity ratio to total capitalization of 51.7 percent and a projected electric rate base of $3.2 billion. On Dec. 15, 2005, the MPUC authorized an interim rate increase of $147 million, subject to refund, which became effective on Jan. 1, 2006. In March 2006, the MPUC approved a new depreciation order, which lowered decommissioning accruals for 2006 from anticipated levels. As a result, interim rates are being recorded at an annual level of approximately $119 million. Due to the seasonality of sales, the rate increase will not be recognized ratably throughout 2006. Evidentiary hearings concluded on April 27, 2006. The anticipated procedural schedule is as follows:

•                  May 24^th– Initial Briefs

•                  June 6^th– Reply Briefs

•                  July 6^th– Administrative Law Judge Report

•                  September 5^th– MPUC Order

On April 13, 2006, intervenors filed testimony regarding the Minnesota electric rate case. In its testimony, the Minnesota Department of Commerce proposed an increase in annual revenues of approximately $90 million, a return on equity of 10.64 percent and a proposed equity ratio of 51.37 percent, resulting in an overall return on rate base of 8.81 percent. The primary adjustments related to return on equity, nuclear decommissioning expense, adjustments to fuel expense and an increase in sales volumes. On the latter two issues the Department of Commerce indicated that the recommendations may change if NSP-Minnesota is able to supply additional information in its rebuttal testimony.

The Office of Attorney General also filed testimony. It proposed two adjustments related to income taxes and wholesale margins that would result in a decrease in 2006 annual revenues of approximately $20 million. On March 30, 2006, NSP-Minnesota filed rebuttal testimony reducing the requested rate increase to $156 million.

On April 24, 2006, NSP-Minnesota reached a settlement agreement regarding the treatment of wholesale electric sales margins. The settlement is with five intervenor groups, including the Office of Attorney General and a large industrial customer group.

The settlement resolves recommendations of most parties regarding the treatment of wholesale electric sales margins. Significant components of the settlement agreement are as follows:

•                  No credit to base electric rates for wholesale electric sales margins;

•                  Wholesale electric sales margins derived from excess generation capacity will be flowed through the fuel clause adjustment as an offset to fuel and energy costs;

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•                  80 percent of wholesale margins derived from the sales from NSP-Minnesota’s ancillary services obligations (e.g. spinning reserves) will be flowed through the fuel clause adjustment as an offset to fuel and energy costs and NSP-Minnesota will retain 20 percent; and

•                  25 percent of proprietary margins, sales that do not arise from the use of NSP-Minnesota generating assets, will be flowed through the fuel clause adjustment as an offset to fuel and energy costs, and 75 percent will be retained by NSP-Minnesota.

The settlement agreement is pending approval by the MPUC and will be considered in the MPUC’s determination of NSP-Minnesota’s overall requested increase.

Other Regulatory Matters – NSP-Wisconsin

NSP-Wisconsin 2006 Fuel Cost Recovery – NSP-Wisconsin’s electric fuel costs for March 2006 were significantly lower than authorized in the 2006 Wisconsin rate case and outside the established fuel monitoring range under the Wisconsin “Fuel Rules.”  Based on preliminary data, March fuel costs for the Wisconsin retail jurisdiction were approximately $2.1 million, or 20 percent, lower than authorized. March year-to-date fuel costs were approximately $1.9 million, or 6 percent, lower than authorized, resulting in a year-to-date over recovery of $1.9 million. NSP-Wisconsin anticipates the Public Serivce Commission of Wisconsin (PSCW) will open a proceeding by mid may to determine if a rate reduction (fuel credit factor) should be implemented. At the time a notice is issued to open the proceeding, rates will likely be declared subject to refund from that point forward, pending a determination of final rates.

Wisconsin Energy Efficiency and Renewables Law – On March 17, 2006 Governor Doyle signed into law the legislative proposal containing the Governor’s Task Force recommendations on energy efficiency and renewables (2005 Act 141). The bill sets a renewable portfolio standard (RPS) of 10 percent by 2015. NSP-Wisconsin anticipates it will be able to meet the RPS with its pro-rata share of existing and planned renewable generation on the NSP system.

Other Regulatory Matters – PSCo

PSCo Electric Rate Case –  On April 14, 2006, PSCo filed with the Colorado Public Utilities Commission (CPUC) to increase electricity rates by $210 million annually, beginning Jan. 1, 2007. The rate request is based on a return on equity of 11 percent, an equity ratio of 59.9 percent and electric rate base of $3.4 billion. A decision is expected by the end of 2006.

The general rate case filing reflects the increased costs of doing business since PSCo’s last electric rate case was filed in 2001, including more than $1 billion in investment, not reflected in current rates, in electricity generation, transmission and distribution infrastructure in Colorado. The filing also reflects the start of construction of a new, third unit at the Comanche Generating Station in Pueblo, Colo., which will help meet continued growing demand for electricity.

PSCo Renewable Portfolio Standards —In November 2004, an amendment to the Colorado statutes was passed by referendum requiring implementation of a renewable energy portfolio standard for electric service. The 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. These incremental costs are expected to be recovered from customers.

During 2006, the CPUC determined that compliance with the renewable energy portfolio standard should be measured through the acquisition of renewable energy credits either with or without the accompanying renewable energy; that the utility purchaser owns the renewable energy credits associated with existing contracts where the power purchase agreement is silent on this issue; that Colorado utilities should be required to file implementation plans, thereby rejecting the proposal to use an independent plan administrator; and the methods utilities should use for determining the budget available for renewable resources. The CPUC issued proposed rules on Jan. 27, 2006. Final rules are expected to become effective in the second of quarter 2006.

PSCo Renewable Energy Standard Adjustment (RESA) – On December 1, 2005, PSCo filed with the CPUC to implement a new 1 percent rider that would apply to each customer’s total electric bill, providing approximately $22 million in annual revenue. The revenues collected under the RESA will be used to acquire sufficient solar resources to meet the on-site solar system requirements in the Colorado statutes. On Feb. 14, 2006, PSCo and the other parties to the case filed a stipulation agreeing to reduce the RESA rider to 0.60 percent and to provide monthly reports. The CPUC approved the stipulation and agreement on February 22, 2006. The RESA rider became effective March 1, 2006.

PSCo Quality of Service Plan – PSCo was required to make a filing regarding the future of its quality of service plan (QSP), which expires at the end of 2006. In its initial filing, PSCo proposed a service quality monitoring and reporting plan. After reviewing the responses of the CPUC staff and other intervenors, PSCo negotiated a new QSP plan that will extend through calendar year 2010. The plan establishes performance measures and provides for associated bill credits for regional electric

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distribution system reliability, electric service continuity and restoration thresholds, customer complaints and telephone response times. If the performance thresholds are not met, the annual bill credit exposures are approximately $7 million for regional reliability and $1 million each for the continuity, reliability, customer complaints and telephone response time thresholds. Each of PSCo’s nine operating regions has its own calculated reliability metric and the bill credits would be apportioned among the regions. PSCo must fail to meet the operating threshold two years in a row before paying reliability bill credits. The bill credit levels would not escalate. If the credits are required to be paid, the stated amounts would be grossed up for taxes. The proposed plan is pending CPUC approval.

Other Regulatory Matters – SPS

SPS Wholesale Rate Complaints - In November 2004, several wholesale cooperative customers of SPS filed a $3 million rate complaint at the FERC requesting that the FERC investigate SPS’ wholesale power base rates and fuel cost adjustment clause calculations. In December 2004, the FERC accepted the complaint filing and ordered SPS base rates subject to refund, effective Jan. 1, 2005. Also in November 2004, SPS filed revisions to its wholesale fuel cost adjustment clause. The FERC set the proposed rate changes into effect on Jan. 1, 2005, subject to refund, and consolidated the proceeding with the wholesale cooperative customers’ complaint proceeding. The FERC set the consolidated proceeding for hearing and settlement judge procedures, which were terminated when the parties could not reach a settlement. Hearings were held in February and March 2006. Post hearing briefs are being submitted to the FERC Administrative Law Judge.

On Sept. 15, 2005, Public Service Company of New Mexico (PNM) filed a separate complaint at the FERC in which it contended that its demand charge under an existing interruptible power supply contract with SPS is excessive and that SPS has overcharged PNM for fuel costs under three separate agreements through erroneous fuel clause calculations.  PNM’s arguments mirror those that it made as an intervenor in the cooperatives’ complaint case, and SPS believes that they have little merit.  SPS submitted a response to PNM’s complaint in October 2005.  In November 2005, the FERC accepted PNM’s complaint, set it for hearing, suspended hearings and set the matter for settlement judge procedures. PNM and SPS have held several rounds of settlement discussions. On April 18, 2006, the settlement judge determined that the settlement procedures should be terminated and the matter set for hearing.

SPS  Wholesale Power Base Rate Application – On Dec. 1, 2005, SPS filed, as amended, for a $2.5 million increase in wholesale power rates to certain electric cooperatives. On Jan. 31, 2006, the FERC conditionally accepted the proposed rates for filing, and set the $2.5 million power rate increase to become effective on July 1, 2006, subject to refund. The FERC also set the rate increase request for hearing and settlement judge procedures. The case is presently in the settlement judge procedures.

SPP Energy Imbalance Service - On June 15, 2005, Southwest Power Pool, Inc. (SPP), of which SPS is a member, filed proposed tariff provisions to establish an Energy Imbalance Service (EIS) wholesale energy market for the SPP region, using a phased approach toward the development of a fully-functional locational marginal pricing energy market with appropriate financial transmission rights, to be effective March 1, 2006. On Sept. 19, 2005, the FERC issued an order rejecting the SPP EIS proposal and providing guidance and recommendations to SPP; however, the FERC did not require SPP to implement a full Day 2 market similar to MISO. On Jan. 6, 2006, SPP filed its revised EIS tariff, On March 20, 2006, the FERC issued an order conditionally accepting the proposed market, suspending the implementation until Oct. 1, 2006. The FERC found the proposal lacking, particularly with respect to the hiring of an external market monitor, the loss compensation mechanisms and the lack of several standard forms for service. The FERC directed SPP to implement safeguards for the first six months of the imbalance markets including a two tier cap, a market readiness certification and price correction authority. SPP and market participants are currently engaging in a series of technical conferences in order to comply with the FERC’s order. SPS has not yet requested New Mexico Public Regulation Commission (NMPRC) or Public Utility Commission of Texas (PUCT) approval regarding accounting and ratemaking treatment of EIS costs.

Texas Energy Legislation - The 2005 Texas Legislature passed a law, effective June 18, 2005, establishing statutory authority for electric utilities outside of the electric reliability council of Texas in the SPP or the Western Electricity Coordinating Council to have timely recovery of transmission infrastructure investments. After notice and hearing, the PUCT may allow recovery on an annual basis of the reasonable and necessary expenditures for transmission infrastructure improvement costs and changes in wholesale transmission charges under a tariff approved by the FERC. The PUCT will initiate a rulemaking for this process that is expected to take place in the first half of 2006.

New Mexico Fuel Review - On Jan. 28, 2005, the NMPRC accepted the staff petition for a review of SPS’s fuel and purchased power cost. The staff requested a formal review of SPS’s fuel and purchased power cost adjustment clause (FPPCAC) for the period of Oct. 1, 2001 through August 2004. The hearing in the fuel review case was held April 22, 2006.

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New Mexico Fuel Factor Continuation Filing – On Aug. 18, 2005, SPS made a filing with the NMPRC requesting to continue the use of SPS’s FPPCAC. This filing was required at this time by the NMPRC. The filing requests that the FPPCAC continue the current monthly factor cost recovery methodology. Testimony has been filed in the case by staff and intervenors objecting to SPS’s  assignment of system average fuel costs to certain wholesale sales and the inclusion of ineligible purchased power capacity and energy payments in the FPPCAC. The testimony also proposed limits on SPS’s future use of the FPPCAC. Related to these issues some intervenors have requested disallowances for past periods, which in the aggregate total approximately $40 million. Other issues in the case include the treatment of renewable energy certificates and sulfur dioxide allowance credit proceeds in relation to SPS’s New Mexico retail fuel and purchased power recovery clause. The Hearing was held on April 18 – 23, 2006, and a NMPRC decision is expected in late 2006.

4. 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. New and changing federal and state environmental mandates can also create added financial liabilities for Xcel Energy and its subsidiaries, which are normally recovered 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.

Regional Haze Rules — The U.S. Environmental Protection Agency (EPA) has required states to develop implementation plans to comply with regional haze rules that require emission controls, known as best available retrofit technology (BART), by December 2007. States are required to identify the facilities that will have to reduce emissions under BART and then set BART emissions limits for those facilities. Colorado is the first state in Xcel Energy’s region to earnestly begin its BART rule development as the first step toward the December 2007 deadline. Xcel Energy is actively involved in the stakeholder process in Colorado and will also be involved as other states in its service territory begin their process. On March 16, 2006, the Colorado Air Quality Control Commission approved a final BART rule to improve regional haze in national parks and wilderness areas. The rule establishes a date of Aug. 1, 2006 by which each BART-eligible source in Colorado must perform and submit an analysis of the need for additional emission controls for sulfur dioxide (SO2) and/or nitrogen oxide (NOx). Several PSCo plants are required to perform such an analysis and may eventually be required to install additional emission controls. The cost of controls will be determined as part of the engineering analyses and is not currently estimable. If required, controls must be installed by 2013.

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

Xcel Energy and SPS advocated that West Texas should be excluded from CAIR, because it does not contribute significantly to nonattainment with the fine particulate matter National Ambient Air Quality Standard in any downwind jurisdiction. On July 11, 2005, SPS, the City of Amarillo, Texas and Occidental Permian LTD filed a lawsuit against the EPA and a request for reconsideration with the agency to exclude West Texas from CAIR. El Paso Electric Co. joined in the request for reconsideration. On March 15, 2006, the EPA denied the petition for reconsideration. Xcel Energy still has the option to continue to litigate the decision.

Under CAIR’s cap-and-trade structure, SPS can comply through capital investments in emission controls or purchase of emission “allowances” from other utilities making reductions on their systems. Based on the preliminary analysis of various scenarios of capital investment and allowance purchase, capital investments could range from $30 million to $300 million and allowance purchases or increased operating and maintenance expenses could range from $20 million to $30 million per year, beginning in 2011 based on the cost of allowances on Feb. 15, 2006. This does not include other costs that SPS will have to incur to comply with EPA’s new mercury emission control regulations, which will apply to SPS’ plants.

These cost estimates represent one potential scenario to comply with CAIR, if West Texas is not excluded. There is uncertainty concerning implementation of CAIR. States are required to develop implementation plans within 18 months of the issuance of the new rules and have a significant amount of discretion in the implementation details. Legal challenges to CAIR rules could alter their requirements and/or schedule. The uncertainty associated with the final CAIR rules makes it difficult to project the ultimate amount and timing of capital expenditures and operating expenses.

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While Xcel Energy expects to comply with the new rules through a combination of additional capital investments in emission controls at various facilities and purchases of emission allowances, it is continuing to review the alternatives. Xcel Energy believes the cost of any required capital investment or allowance purchases will be recoverable from customers.

Polychlorinated Biphenyl (PCB) Storage and Disposal — In August 2004, Xcel Energy received notice from the EPA contending SPS violated PCB storage and disposal regulations with respect to storage of a drained transformer and related solids. The EPA contended the fine for the alleged violation was approximately $1.2 million. Xcel Energy contested the fine and submitted a voluntary disclosure to the EPA. On April 17, 2006, SPS received a notice of determination from the EPA stating that the voluntary disclosure had been reviewed and that SPS had met all conditions of the EPA’s audit policy. Accordingly, the EPA will mitigate 100 percent of the gravity-based penalty for the disclosed violation, and no economic penalty will be assessed.

Minnesota Mercury Legislation ¾ The Minnesota legislature is considering legislation that could require the installation of additional mercury emission control equipment at several coal-fired generating facilities in Minnesota. Most versions of this legislation include full and timely cost recovery provisions for affected utilities.

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.

Sinclair Oil Corporation vs. e prime inc and Xcel Energy, Inc. - On July 18, 2005, Sinclair Oil Corporation filed a lawsuit against Xcel Energy and its former subsidiary e prime. In the U.S. District Court for the Northern District of Oklahoma, Sinclair Oil Corporation is alleging liability and damages for purported misreporting of price information for natural gas to trade publications in an effort to artificially increase natural gas prices. The complaint also alleges that e prime and Xcel Energy engaged in a conspiracy with other gas sellers to inflate prices through alleged false reporting of gas prices. In response, e prime and Xcel Energy filed a motion with the Multi-District Litigation (MDL) Panel to have the matter transferred to U.S. District Judge Pro in Nevada, who is the judge assigned to western area wholesale natural gas marketing litigation, and filed a second motion to dismiss the lawsuit. In response to this motion, this matter has been conditionally transferred to U.S. District Court Judge Pro. Sinclair subsequently filed a motion with the MDL Panel to vacate this transfer. On Feb. 15, 2006, the MDL Panel denied plaintiffs’ remand motions. e prime and Xcel Energy previously filed a motion to dismiss with the District Court in Oklahoma based upon pre-emption and the filed rate doctrine, and will shortly file the identical motion with Judge Pro.

J.P. Morgan Trust Company vs. e prime and Xcel Energy Inc. et al. – On Oct. 17, 2005, J.P. Morgan, in its capacity as the liquidating trustee for Farmland Industries Liquidating Trust, filed an amended complaint in Kansas state court adding defendants, including Xcel Energy and e prime, to a previously filed complaint alleging that the defendants inaccurately reported natural gas trades to market trade publications in an effort to artificially increase natural gas prices. The lawsuit was removed to the U.S. District Court in Kansas and subsequently transferred to U.S. District Court Judge Pro, in Nevada pursuant to an order from the MDL Panel. A motion to remand this case to state court has been filed by plaintiffs and on March 2, 2006, Judge Pro granted plaintiffs’ motion for remand, but vacated this order on March 8, 2006, and will give the matter further consideration. This case is in the early stages, there has been no discovery and e prime and Xcel Energy intend to vigorously defend themselves against these claims.

Metropolitan Airports Commission vs. Northern States Power Company — On Dec. 30, 2004, the Metropolitan Airports Commission (MAC) filed a complaint in Minnesota state district court in Hennepin County asserting that NSP-Minnesota is required to relocate facilities on MAC property at the expense of NSP-Minnesota. MAC claims that approximately $7.1 million charged by NSP-Minnesota over the past five years for relocation costs should be repaid. Both parties asserted cross motions for partial summary judgment on a separate and less significant claim concerning legal obligations associated with rent payments allegedly due and owing by NSP-Minnesota to MAC for the use of its property for a substation that serves the MAC. A hearing regarding these cross motions was held in January 2006. In February 2006, the Court granted MAC’s motion on this issue, finding that there was a valid lease and that the past course of action between the parties required NSP-Minnesota to continue such payments. NSP-Minnesota had made rent payments for 45 years. Depositions of key witnesses took place in February, March, and April of 2006. Trial has been set for August 2006, and additional summary judgment motions are likely prior to trial.

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Hoffman vs. Northern States Power Company – On March 15, 2006 a purported class action complaint was filed in Minnesota state district court, Hennepin County, on behalf of NSP-Minnesota’s residential customers in Minnesota, North Dakota and South Dakota for alleged breach of a contractual obligation to maintain and inspect the points of connection between NSP-Minnesota’s wires and customers’ homes within the meter box. Plaintiffs claim NSP-Minnesota’s breach results in an increased risk of fire and is in violation of tariffs on file with the MPUC. Plaintiffs seek injunctive relief and damages in an amount equal to the value of inspections plaintiffs claim NSP-Minnesota was required to perform over the past six years. NSP-Minnesota denies plaintiffs allegations and tariff interpretations and will vigorously defend against such claims.

Comer vs. Xcel Energy Inc. et al. – On April 25, 2006 Xcel Energy received notice of a purported class action lawsuit filed in United States District Court for the Southern District of Mississippi. The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ carbon dioxide emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.”  Plaintiffs allege in support of their claim, several legal theories, including negligence, and public and private nuisance and seek damages related to the hurricane. Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims.

Other Contingencies

The circumstances set forth in Notes 13, 14 and 15 to the consolidated financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2005 and Notes 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 include unresolved contingencies that are material to Xcel Energy’s financial position:

•             Tax Matters — See Note 14 to the consolidated financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2005 for discussion of exposures regarding the tax deductibility of corporate-owned life insurance loan interest; and

•             Guarantees — See Note 5 to the accompanying consolidated financial statements for discussion of exposures under various guarantees.

5. Short-Term Borrowings and Other Financing Instruments

Short-Term Borrowings

At March 31, 2006, Xcel Energy and its subsidiaries had approximately $649.7 million of short-term debt outstanding at a weighted average interest rate of 4.87 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, 2006, Xcel Energy had issued guarantees of up to $71.5 million with no known exposure under these guarantees. In addition, Xcel Energy provides indemnity protection for bonds issued for itself and its subsidiaries. The total amount of bonds with this indemnity outstanding as of March 31, 2006, was approximately $132.4 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.

6. Derivative Valuation and Financial Impacts

Xcel Energy and its subsidiaries use a number of different derivative instruments in connection with their utility commodity price, interest rate, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133, are recorded at fair value. The presentation of these derivative instruments is dependent on the designation of a qualifying hedging relationship. The adjustment to fair value of derivative instruments not designated in a qualifying hedging relationship is reflected in current earnings or as a regulatory balance. This classification is dependent on the applicability of any regulatory mechanism in place. This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations. The designation of a cash flow hedge

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against the change in the fair value of the underlying asset, liability or firm commitment being hedged. That is, fair value hedge accounting allows the gains or losses of the derivative instrument to offset, in the same period, the gains and losses of the hedged item.

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 Income. The results of these transactions are recorded on a net basis within Operating Revenues on the Consolidated Statements of Income.

Xcel Energy and its subsidiaries also enter into certain commodity-based derivative 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 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 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. In addition, normal purchases and normal sales contracts must have a price based on an underlying that is clearly and closely related to the asset being purchased or sold. An underlying is a specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event, such as a scheduled payment under a contract.

Xcel Energy evaluates all of its contracts when such contracts are entered to determine if they are derivatives and, if so, if they qualify to meet the normal designation requirements under SFAS No. 133, as amended. None of the contracts entered into within the commodity trading operations qualify for a normal designation.

In 2003, as a result of FASB Statement 133 Implementation Issue No. C20, Xcel Energy began recording several long-term power purchase agreements at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During the first quarter of 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts will no longer be adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory balances.

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

7.     Detail of Interest and Other Income (Expense) - Net

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

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

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 as a consequence of past or future terrorist attacks;

•             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;

•             State, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and natural gas markets; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

•             Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;

•             Nuclear regulatory policies and procedures, including operating regulations and spent nuclear fuel storage;

•             Social attitudes regarding the utility and power industries;

•             Risks associated with the California power and other western markets;

•             Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;

•             Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;

•             Risks associated with implementations of new technologies;

•             Other business or investment considerations that may be disclosed from time to time in Xcel Energy’s SEC filings or in other publicly disseminated written documents; and

•             The other risk factors listed from time to time by Xcel Energy in reports filed with the SEC, including Risk Factors in Item 1A of Xcel Energy’s Annual Report on Form 10-K for the year ended December 31, 2005 and Exhibit 99.01 to this report on Form 10-Q for the quarter ended March 31, 2006.

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RESULTS OF OPERATIONS

Summary of Financial Results

The following table summarizes the earnings contributions of Xcel Energy’s business segments on the basis of GAAP. Continuing operations consist of the following:

•             regulated utility subsidiaries, operating in the electric and natural gas segments; and

•             several nonregulated subsidiaries and the holding company, where corporate financing activity occurs.

Discontinued operations consist of the following:

•             Quixx, which was classified as held for sale in the third quarter of 2005 based on a decision to divest this investment;

•             UE, which was sold in April 2005;

•             Seren, a portion of which was sold in November 2005 with the remainder sold in January 2006; and

•             CLF&P, which was sold in January 2005.

Prior-year financial statements have been reclassified to conform to the current year presentation and classification of certain operations as discontinued. See Note 2 to the consolidated financial statements for a further discussion of discontinued operations.

(a) Not a reportable segment. Included in All Other segment results in Note 10 to the consolidated financial statements. Other utility results, included in the earnings contribution table above, include certain subsidiaries of the utility operating companies that conduct non-utility activities. The largest of these other utility businesses is PSR Investments, Inc., a subsidiary of PSCo that owns and manages life insurance policies for PSCo employees and retirees.

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The following table summarizes significant components contributing to the changes in the first quarter of 2006 earnings per share compared with the same period in 2005, which are discussed in more detail later.

Utility Segment Results

Earnings for the first quarter of 2006 increased compared with the same period in 2005 primarily due to stronger utility margins, partially offset by higher operating and maintenance expenses. The stronger utility margins reflect a natural gas rate increase in Colorado, an electric and natural gas rate increase in Wisconsin and an interim electric rate increase in Minnesota. Warmer than normal weather during the first quarter partially offset these positive developments.

The following summarizes the estimated impact of weather on regulated utility earnings per share, based on estimated temperature variations from historical averages (excluding the impact on commodity trading operations):

Other Results — Holding Company and Other Costs

Financing Costs and Preferred Dividends – Holding company results include interest expense and preferred dividend costs, which are incurred at the Xcel Energy and intermediate holding company levels and are not directly assigned to individual subsidiaries.

Discontinued Operations

Discontinued - Utility Segments – During 2004, Xcel Energy reached an agreement to sell its regulated electric and natural gas subsidiary, CLF&P. The sale was completed in January 2005.

Discontinued – All Other – In March 2005, Xcel Energy agreed to sell its non-regulated subsidiary, UE to Zachry.

In August 2005, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Quixx Corp., a former subsidiary of UE that partners in cogeneration projects, that was not included in the sale of UE to Zachry.

On Sept. 27, 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Seren, a wholly owned broadband communications services subsidiary. Seren delivers cable television, high-speed Internet and telephone service. In November 2005, Xcel Energy sold Seren’s California assets to WaveDivision Holdings, LLC. In January 2006, Xcel Energy sold Seren’s Minnesota assets to Charter Communication.

Income Statement Analysis — First Quarter 2006 vs. First Quarter 2005

Electric Utility, Short-term Wholesale and Commodity Trading Margins

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost

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changes in fuel and purchased power. Due to fuel and purchased energy cost-recovery mechanisms for retail customers in several states, most fluctuations in these costs do not materially affect electric utility margin.

Xcel Energy has two distinct forms of wholesale sales: short-term wholesale and commodity trading. Short-term wholesale refers to energy-related purchase and sales activity, and the use of certain financial instruments associated with the fuel required for, and energy produced from, Xcel Energy’s generation assets or the energy and capacity purchased to serve native load. Commodity trading is not associated with Xcel Energy’s generation assets or the energy and capacity purchased to serve native load. Short-term wholesale and commodity trading activities are considered part of the electric utility segment.

Short-term wholesale and commodity trading margins reflect the estimated impact of regulatory sharing of realized margins, if applicable. Commodity trading revenues are reported net of related costs (i.e., on a margin basis) in the Consolidated Statements of Income. Commodity trading costs include purchased power, transmission, broker fees and other related costs.

The following table details the revenue and margin for base electric utility, short-term wholesale and commodity trading activities.

Short-term wholesale and commodity trading margins increased approximately $10 million during the first quarter of 2006. The increase is primarily due to strong commodity trading results, driven by market price movements.

The following summarizes the components of the changes in base electric utility revenue and base electric utility margin for the three months ended March 31:

Base Electric Utility Revenue

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Natural Gas Margin

Nonregulated Operating Margins

The following table details the change in nonregulated revenue and margin, included in continuing operations.

Non-Fuel Operating Expense and Other Costs

Other Operating and Maintenance Expenses – Utility – Other operating and maintenance expenses for the first quarter of 2006 increased by approximately $33 million, or 8.1 percent, compared with the same period in 2005. The increase is primarily due to increased uncollectible receivable and employee benefit costs, partially offset by lower nuclear plant maintenance costs due to the refueling and ten year inspection outage in Monticello in 2005, with no comparable outage in 2006. For more information see the following table: