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. x Yes o No

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

o Yes x No

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

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

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

See Notes to Consolidated Financial Statements

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

See Notes to Consolidated Financial Statements

4

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

(Thousands of Dollars)

See Notes to Consolidated Financial Statements

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

See Notes to Consolidated Financial Statements

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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, 2007, and Dec. 31, 2006; the results of its operations and changes in common stockholders’ equity for the three months ended March 31, 2007 and 2006; and its cash flows for the three months ended March 31, 2007 and 2006. 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, 2006, appropriately represent, in all material respects, the current status of accounting policies, and are incorporated herein by reference.

Income Taxes — Consistent with prior periods and upon adoption of Financial Accounting Standard Board (FASB) Interpretation No. 48 – “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109”, Xcel Energy records interest and penalties related to income taxes as interest charges in the Consolidated Statements of Income.

Reclassifications — Certain amounts in the Consolidated Statements of Cash Flows have been reclassified from prior-period presentation to conform to the 2007 presentation. The reclassifications reflect to the presentation of unbilled revenue, recoverable purchased natural gas and electric energy costs and regulatory assets and liabilities and share-based compensation expense as separate items rather than components of other assets and other liabilities within net cash provided by operating activities. In addition, activity related to derivative transactions have been combined into net realized and unrealized hedging and derivative transactions. These reclassifications did not affect total net cash provided by (used in) operating, investing or financing activities within the Consolidated Statements of Cash Flows.

2.          Recently Issued Accounting Pronouncements

Fair Value Measurements (SFAS 157) — In September 2006, the FASB issued Statement of Financial Accounting Standard (SFAS) 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS 157 also emphasizes that fair value is a market-based measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Fair value measurements are disclosed by level within that hierarchy. SFAS 157 is effective for financial statements issued for fiscal years beginning after Nov. 15, 2007. Xcel Energy is evaluating the impact of SFAS 157 on its financial condition and results of operations and does not expect the impact of adoption to be material.

The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115 (SFAS 159) —  In February 2007, the FASB issued SFAS 159, which provides companies with an option to measure, at specified election dates, many financial instruments and certain other items at fair value that are not currently measured at fair value. A company that adopts SFAS 159 will report unrealized gains and losses on items, for which the fair value option has been elected, in earnings at each subsequent reporting date. This statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. This statement is effective for fiscal years beginning after Nov. 15, 2007. Xcel Energy is evaluating the impact of SFAS 159 on its financial condition and results of operations and does not expect the impact of adoption to be material.

3.          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 2007 and 2006 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.

Regulated Utility Segments

Cheyenne Light, Fuel and Power Company (Cheyenne), which was sold in 2005, had an impact on Xcel Energy’s financial statements in 2006 relating to tax adjustments.

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Nonregulated Subsidiaries— All Other Segments

Seren Innovations Inc., NRG Energy, Inc., e prime, Xcel Energy International, Utility Engineering, and Quixx, which were all sold in 2006 or earlier, continue to have activity and balances reflected on Xcel Energy’s financial statements as reported in the tables below.

Summarized Financial Results of Discontinued Operations

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

4.              Income Taxes

Corporate-Owned Life Insurance (COLI) — In April 2004, Xcel Energy filed a lawsuit against the U.S. government in the U.S. District Court for the District of Minnesota to establish its right to deduct the interest expense that had accrued during tax years 1993 and 1994 on policy loans related to its COLI policies that insured certain lives of Public Service Company of Colorado (PSCo). These policies are owned by PSR Investments, Inc. (PSRI), a wholly owned subsidiary of PSCo.

After Xcel Energy filed this suit, the Internal Revenue Service (IRS) sent two statutory notices of deficiency of tax, penalty and interest for 1995 through 1999. Xcel Energy has filed U.S. Tax Court petitions challenging those notices. Xcel Energy anticipates the dispute relating to its interest expense deductions will be resolved in the refund suit that is pending in the Minnesota Federal District Court and the Tax Court petitions will be held in abeyance pending the outcome of the refund litigation. In the third quarter of 2006, Xcel Energy also received a statutory notice of deficiency from the IRS for tax years 2000 through 2002 and timely filed a Tax Court petition challenging the denial of the COLI interest expense deductions for those years.

On May 5, 2006, Xcel Energy filed a second motion for summary judgment. On Aug. 18, 2006, the U.S. government filed a second motion for summary judgment. On Feb. 14, 2007, the Magistrate Judge issued a report to the District Court Judge concerning both motions. In the report, the Magistrate Judge recommended both motions be denied due to fact issues in dispute. Both parties filed objections to the recommendations. On March 23, 2007, Xcel Energy received a decision from the District Court Judge essentially

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adopting the Magistrate Judge’s recommendation denying both sides’ motions for summary judgment and reconfirming the July 24, 2007, trial date.

Xcel Energy believes that the tax deduction for interest expense on the COLI policy loans is in full compliance with the tax law. Accordingly, PSRI has not recorded any provision for income tax or related interest or penalties, and has continued to take deductions for interest expense on policy loans on its income tax returns for subsequent years. The litigation could take two to three years to reach final resolution. Defense of Xcel Energy’s position may require significant cash outlays, which may or may not be recoverable in a court proceeding. The ultimate resolution of this matter is uncertain and could have a material adverse effect on Xcel Energy’s financial position, results of operations and cash flows.

Should the IRS ultimately prevail on this issue, tax and interest payable through March 31, 2007, would reduce earnings by an estimated $437 million. Xcel Energy has received formal notification that the IRS will seek penalties. If penalties (plus associated interest) also are included, the total estimated exposure through March 31, 2007, is estimated to be approximately $520 million. If COLI interest expense deductions were no longer available, first quarter 2007 earnings would have decreased by $12 million, after tax, or 3 cents per share.

Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (FIN 48) — In July 2006, the FASB issued FASB Interpretation No. (FIN) 48. FIN 48 prescribes how a company should recognize, measure, present and disclose uncertain tax positions that the company has taken or expects to take in its income tax returns. FIN 48 requires that only income tax benefits that meet the “more likely than not” recognition threshold be recognized or continue to be recognized on its effective date. As required, Xcel Energy adopted FIN 48 as of Jan. 1, 2007 and the initial derecognition amounts were reported as a cumulative effect of a change in accounting principle. The cumulative effect of the change, which is reported as an adjustment to the beginning balance of retained earnings, was not material. Following implementation, the ongoing recognition of changes in measurement of uncertain tax positions will be reflected as a component of income tax expense.

Xcel Energy files a consolidated federal income tax return; state tax returns based on income in its major operating jurisdictions of Colorado, Minnesota, Texas, and Wisconsin, and various other state income-based tax returns.

Xcel Energy has been audited by the IRS through tax year 2003, with a limited exception for 2003 research tax credits. The IRS commenced an examination of Xcel Energy’s federal income tax returns for 2004 and 2005 (and research credits for 2003) in the third quarter of 2006, and that examination is anticipated to be complete by March 31, 2008. As of March 31, 2007, the IRS had not proposed any material adjustments. However, Xcel Energy is currently in litigation with the federal government to establish its right to deduct interest expense on COLI policy loans incurred since 1993 (see discussion of COLI above). All COLI tax benefits continue to be recognized in full. As of March 31,2007, Xcel Energy’s 2000 through 2002 federal income tax returns remain open under applicable statutes of limitations.

Xcel Energy is also currently under examination by the state of Colorado for years 1993 through 1996 and 2000 through 2004, the state of Minnesota for years 1998 through 2000, and the state of Wisconsin for years 2002 through 2005. No material adjustments have been proposed as of March 31, 2007. As of March 31, 2007, Xcel Energy’s earliest open tax years in which an audit can be initiated by state taxing authorities in its major operating jurisdictions are as follows:

•       Colorado -1993

•       Minnesota - 1998

•       Texas-2002, and

•       Wisconsin - 2002

The amount of unrecognized tax benefits was $47.3 million and  $50.1 million on Jan. 1, 2007 and March 31, 2007, respectively. Of these amounts, $43.2 million and $45.9 million were offset against the tax benefits associated with net operating loss and tax credit carryovers as of Jan. 1, 2007 and March 31, 2007, respectively.

Included in the unrecognized tax benefit balance was $17.4 million and $18.0 million of tax positions on Jan. 1, 2007 and March 31, 2007, respectively, which if recognized would affect the annual effective tax rate. In addition, the unrecognized tax benefit balance included $29.9 million and $32.1 million of tax positions on Jan. 1, 2007 and March 31, 2007, respectively, for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The change in the unrecognized tax benefit balance from Jan. 1, 2007 to March 31, 2007, was due to the addition of similar uncertain tax positions relating to first quarter activity.

Xcel Energy’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS and state tax audits progress. However, at this time due to the nature of the audit process, it is not reasonably possible to estimate a range of the possible change.

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The interest expense liability related to unrecognized tax benefits on Jan. 1, 2007, was not material due to net operating loss and tax credit carryovers. The change in the interest expense liability from Jan. 1, 2007, to March 31, 2007, was not material. No amounts were accrued for penalties.

5.          Rate Matters

NSP-Minnesota

Pending and Recently Concluded Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Midwest Independent Transmission System Operator, Inc. (MISO) Long-Term Transmission Pricing — In October 2005, MISO filed a proposed change to its Transmission and Energy Markets Tariff (TEMT) to regionalize future cost recovery of certain high voltage (345 kilovolts (KV)) transmission projects to be constructed for reliability improvements. The proposal, called the Regional Expansion Criteria Benefits phase I (RECB I) proposal, would recover 20 percent of eligible transmission costs from all transmission service customers in the MISO 15 state region, with 80 percent recovered on a sub-regional basis. The proposal would exclude certain projects that had been planned prior to the October 2005 filing, and would require new generators to fund 50 percent of the cost of network upgrades associated with their interconnection. In February 2006, the FERC generally approved the RECB I proposal, but set the 20 percent limitation on regionalization for additional proceedings. Various parties filed requests for rehearing. On Nov. 29, 2006, the FERC issued an order on rehearing upholding the February 2006 order and approving the 20 percent limitation. On Dec. 13, 2006, the Public Service Commission of Wisconsin (PSCW) filed an appeal of the RECB I order.

In addition, in October 2006, MISO filed additional changes to its TEMT to regionalize future recovery of certain transmission projects (230 KV and above) constructed to provide access to lower cost generation supplies. The filing, known as Regional Expansion Criteria Benefits phase II (RECB II), would provide regional recovery of 20 percent of the project costs and sub-regional recovery of 80 percent, based on a benefits analysis. MISO proposed that the RECB II tariff be effective April 1, 2007. Initial comments were filed at the FERC on Dec. 22, 2006. The date FERC will take initial action is not known.

Transmission service rates in the MISO region presently use a rate design in which the transmission cost depends on the location of the load being served. Costs of existing transmission facilities are not regionalized. MISO is required to file a replacement rate methodology in August 2007, to be effective Feb. 1, 2008. It is possible MISO will propose to regionalize the recovery of the costs of existing transmission facilities.

On March 15, 2007, the FERC issued orders separately upholding the Nov. 29, 2006 order accepting the RECB I pricing proposal, and approving most aspects of the RECB II proposal. However, the FERC ordered MISO to re-examine the cost allocation for existing facilities, new reliability improvements and economic projects in the Aug. 2007 compliance filing.

Proposals to regionalize transmission costs could shift the costs of Northern States Power Co., a Minnesota corporation (NSP-Minnesota) and Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin) transmission investments to other MISO transmission service customers, but would also shift the costs of transmission investments of other participants in MISO to NSP-Minnesota and NSP-Wisconsin.

Revenue Sufficiency Guarantee Charges — On April 25, 2006, the FERC issued an order determining that MISO had incorrectly applied its TEMT regarding the application of the revenue sufficiency guarantee (RSG) charge to certain transactions. The FERC ordered MISO to resettle all affected transactions retroactive to April 1, 2005. The RSG charges are collected from certain MISO customers and paid to others. On Oct. 26, 2006, the FERC issued an order granting rehearing in part and reversed the prior ruling requiring MISO to issue retroactive refunds and ordered MISO to submit a compliance filing to implement prospective changes. In late November 2006, however, certain parties filed further requests for rehearing challenging the reversal regarding refunds.

On March 15, 2007, the FERC issued orders separately denying rehearing of the Oct. 26, 2006 order and rejecting certain aspects of the MISO compliance filings submitted on Nov. 26 and 27, 2006. The FERC ordered MISO to submit a revised compliance filing . As a result of the FERC order, Xcel Energy reduced the $6.1 million reserve to $1.9 million as of March 31, 2007.

Pending and Recently Concluded Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)

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 (ROE), a projected common equity to total capitalization ratio 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.

On Sept. 1, 2006, the MPUC issued a written order granting an electric revenue increase of approximately $131 million for 2006 based on an authorized ROE of 10.54 percent. The scheduled rate increase will be reduced in 2007 to $115 million to reflect the return of Flint Hills Resources, a large industrial customer, to the NSP-Minnesota system. The MPUC approved the wholesale margin settlement in which NSP-Minnesota returns most margins from unused generating capacity back to customers through the Fuel clause

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adjustment (FCA). NSP-Minnesota is allowed to earn an incentive on sales related to ancillary service obligations. The MPUC Order became effective in November 2006, and final rates were implemented on Feb. 1, 2007.

On March 13, 2007, a citizen intervenor submitted a brief asking that the Minnesota Court of Appeals remand to the MPUC with direction to; determine the correct amount of income tax collected in rates but not paid to taxing authorities; order the refund or credit to ratepayers of that part of taxes collected in rates but not paid; order the refund to ratepayers of the amount of interim rates collected in January and February of 2006 in violation of the previous merger order and provide other equitable relief. NSP-Minnesota and the MPUC submitted reply briefs on April 26, 2007.

NSP-Minnesota Natural Gas Rate Case — In November 2006, NSP-Minnesota filed a request with the MPUC to increase Minnesota natural gas rates by $18.5 million, which represents an increase of 2.4 percent. The request is based on 11.0 percent ROE, a projected equity ratio of 51.98 percent and a natural gas rate base of $439 million. Interim rates, subject to refund, were set at a $15.9 million increase and went into effect on Jan. 8, 2007.

On March 9, 2007, various intervenors filed testimony in the Minnesota natural gas rate case.

•                     The Minnesota Department of Commerce (MDOC) recommended a rate increase of $8.5 million based on a ROE of 9.71 percent.

•                     The Office of Attorney General (OAG) recommended a ROE of 9.26 percent.

On April 10, 2007, Xcel Energy filed its rebuttal testimony and revised its requested relief to $16.8 million. The revised requested was caused primarily by an updated ROE estimate of 10.75 percent and an update to the sales forecast.

On April 24, 2007 the MDOC filed surrebuttal testimony recommending a rate increase of $10.9 million based on an updated ROE of 9.5 percent. The OAG filed surrebuttal testimony that continued to recommend a 9.26 percent ROE and made reference to the fact that Xcel Energy’s consolidated taxes are significantly lower than those requested for recovery, but made no specific recommendations on this issue.

The remainder of the schedule for the Minnesota natural gas rate case is listed below:

North Dakota Gas Rate Case — In December 2006, NSP-Minnesota filed a request with the North Dakota Public Service Commission (NDPSC) to increase North Dakota natural gas rates by $2.8 million, an increase of 3.0 percent. The request is based on 11.3 percent return on equity, a projected equity ratio of 51.59 percent and a natural gas rate base of $46.6 million. Interim rates, subject to refund, were set at a $2.2 million increase and went into effect on Feb. 13, 2007. On April 24, 2007, NSP-Minnesota and the NDPSC staff filed a settlement agreement under which NSP-Minnesota would receive a $2.3 million rate increase, an increase in residential customer charge from $15.69 to $18.60 and a residential rate through Dec. 31, 2009. A decision is expected in the summer of 2007.

MISO Day 2 Market Cost Recovery — On Dec. 20, 2006, the MPUC issued an order ruling that NSP-Minnesota may recover all MISO Day 2 costs, except Schedules 16 and 17, through its FCA. NSP-Minnesota is refunding Schedule 16 and 17 costs recovered through the FCA in 2005 ($2.2. million) to customers through the FCA in equal monthly installments beginning March 2007. NSP-Minnesota is recovering 50 percent of Schedule 16 and 17 costs starting in 2006 in the final rates established in the 2005 electric rate case. NSP-Minnesota is allowed to defer 100 percent of the Schedule 16 and 17 costs not included in rates for a three-year period before starting the amortization. The MPUC ruling on Schedules 16 and 17 costs will have no impact on net income in 2007. On April 9, 2007, the OAG filed an appeal of the MPUC order to the Minnesota Court of Appeals. NSP-Minnesota plans to intervene in the appeal and urge the court to uphold the MPUC order. The date for a court decision in the appeal is not known.

Transmission Cost Recovery — Since December 2004, NSP-Minnesota has recovered certain transmission costs related to wind generation projects through a Renewable Cost Recovery (RCR) rider. In November 2006, the MPUC approved the replacement of the RCR rider with a Transmission Cost Recovery (TCR) rider pursuant to 2005 legislation. The TCR mechanism would allow recovery of incremental transmission investments between rate cases. On Oct. 27, 2006, NSP-Minnesota filed for approval of recovery of $14.7 million in 2007 under the TCR tariff. The RCR rate factors will remain in effect until the TCR factors are implemented. On March 8, 2007, the MPUC voted to approve the recommendation of the MDOC to allow recovery of $13.1 million in 2007, but ruled $1.6 million of costs should be allocated to wholesale transmission service customers. This ruling will reduce recovery in Minnesota electric rates by $1.6 million in 2007.

Fixed Bill Complaint — In January 2007, the OAG filed a complaint with the MPUC regarding the fixed monthly gas payment programs of NSP-Minnesota and another unaffiliated natural gas utility. This program generally allows customers to elect a fixed monthly payment for natural gas service that will not change for one year regardless of changes in natural gas costs or consumption due to weather. The complaint seeks termination of the program or modification, and seeks interim relief that would allow customers to exit the program. The MPUC has sought comments on the appropriate procedures for addressing the complaint. NSP-Minnesota filed comments seeking to address this complaint through discussions with the OAG, rather than litigation. On April 19, 2007, the MPUC determined that there was sufficient evidence to open an investigation and opened separate dockets for each utility. The MPUC postponed its decision on the OAG’s request for interim relief pending filings from both utilities that identify the amount of stranded costs that would occur if participants were allowed to exit the fixed bill programs prior to the end of the program year. It is expected that the matter will come back before the MPUC during the second quarter to address the issue of interim relief.

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Mercury Cost Recovery — On Dec. 29, 2006, NSP-Minnesota requested approval of a Mercury Emissions Reduction Rider tariff and associated rate adjustments. The request is designed to recover approximately $5.4 million during 2007 from Minnesota electric retail customers for costs associated with implementing both the mercury and other environmental improvement portions of the Mercury Emissions Reduction Act of 2006. NSP-Minnesota expects the MPUC to act upon this request in the second quarter of 2007.

Annual Automatic Adjustment Report for 2005 — On Sept. 2, 2006 NSP-Minnesota filed its annual automatic adjustment report for the period from July 1, 2005 through June 30, 2006, which is the basis for the MPUC review of charges that flow through the FCA mechanism. The MDOC filed comments on April 18, 2007 noting that NSP-Minnesota had not demonstrated the reasonableness of its cost assignment of certain market energy charges from the MISO Day 2 market between daily sales of excess generation and native energy needs. The MDOC indicated that NSP-Minnesota could provide additional support for its methodology in its reply comments, which are due on May 18, 2007.

NSP-Wisconsin

Pending and Recently Concluded Regulatory Proceedings — FERC

Wholesale Rate Case Application — On July 31, 2006, NSP-Wisconsin filed a rate case at the FERC requesting a base rate increase of approximately $4 million, or 15 percent, for its ten wholesale municipal electric sales customers. NSP-Wisconsin’s wholesale customers are currently served under a bundled full requirements tariff, with rates based on embedded costs, and a monthly fuel cost adjustment clause (FCAC). NSP-Wisconsin proposes to unbundle transmission service and revise the FCAC to reflect current FERC regulatory policies, the advent of MISO operations and the MISO Day 2 energy market. In August 2006, all ten customers filed a joint protest of the rate case, requesting the increase be suspended until March 1, 2007, and the request be set for litigated hearings. On Sept. 28, 2006, the FERC issued an order accepting the filing, suspending the effective date of the rates to March 1, 2007, and setting the filing for hearing and settlement judge procedures. In February 2007, NSP-Wisconsin reached a settlement with customers that provides for full cost recovery of MISO Day 2 and renewable energy costs through the FCAC and a $2.4 million base rate increase. On April 13, 2007, a motion was approved to implement the settlement rate increase on an interim basis, effective March 1, 2007. Approval of the settlement is pending final FERC action.

Pending and Recently Concluded Regulatory Proceedings — Public Service Commission of Wisconsin (PSCW)

MISO Cost Recovery — On June 29, 2006, the PSCW opened a proceeding to address the proper amount of MISO Day 2 deferrals that the state’s utilities should be allowed to recover and the proper method of rate recovery.

On Sept. 1, 2006, NSP-Wisconsin detailed its calculation methodology and reported that, as of June 30, 2006, it had deferred approximately $6.2 million. PSCW staff and intervenors filed testimony in December 2006, arguing that the various methodologies used by the utilities to calculate the deferrals were inconsistent, and to varying degrees incorrect. Further, the testimony argued that some or all of the deferred costs are being recovered in current rates and were, therefore, inappropriately deferred and the utilities should be required to write off balances that were inappropriately deferred.

On Feb. 13, 2007 a hearing was held. Initial briefs and reply briefs were filed on March 13, 2007, and April 3, 2007, respectively, and a decision is pending before the PSCW. The potential impact on NSP-Wisconsin is unknown at this time but could be material. NSP-Wisconsin currently anticipates that the ultimate decision on the amount of costs to be recovered in rates could be delayed until its next general rate case to be filed on June 1, 2007.

As of March 31, 2007, NSP-Wisconsin has deferred approximately $11.7 million of MISO Day 2 costs.

Fuel Cost Recovery Rulemaking — On June 22, 2006, the PSCW opened a rulemaking docket to address potential revisions to the electric fuel cost recovery rules. Wisconsin statutes prohibit the use of automatic adjustment clauses by large investor-owned electric public utilities. Instead, the statutes authorize the PSCW to approve, after a hearing, a rate increase for these utilities to allow for the recovery of costs caused by an emergency or extraordinary increase in the cost of fuel. In opening this rulemaking, the PSCW recognized the increased volatility of fuel and energy costs, citing events such as the implementation of the MISO Day 2 Market, increased demand on some fuels, increased transportation costs of some fuels, and the effects of hurricanes on the availability of some fuels. On Sept. 7, 2006, Wisconsin’s large investor-owned utilities, including NSP-Wisconsin, jointly filed proposed revisions to the rules. The utilities’ proposal incorporates a plan year forecast and an after-the-fact reconciliation to eliminate regulatory lag, and ensure recovery of prudently incurred costs. On Nov. 3, 2006, a coalition of customer and intervenor groups submitted a counter proposal that included only minor revisions to the existing rules. On Feb. 1, 2007, the utilities filed a revised proposal to reflect input from the PSCW staff. Attorneys for the customer intervenors and the utilities filed legal analyses of the utilities’ proposed rule changes on March 7, 2007 and March 15, 2007, respectively. A decision on this matter is pending. At this time it is not certain what, if any, changes to the existing rules will be recommended by the PSCW.

PSCo

Pending and Recently Concluded Regulatory Proceedings — Colorado Public Utilities Commission (CPUC)

Natural Gas Rate Case — On Dec. 1, 2006, PSCo filed with the CPUC, a request to increase natural gas rates by $41.9 million, representing an overall increase of 2.96 percent, primarily related to capital investments and rising operating costs. The request assumes a common equity ratio of 60.17 percent and a ROE of 11 percent. The jurisdictional rate base is approximately $1.1 billion.

On April 6, 2007, the CPUC staff and the Colorado Office of Consumer Council (OCC) filed answer testimony to PSCo’s requested increase in revenue requirements. The CPUC staff recommended an overall revenue increase of $30.5 million, based on a 10 percent ROE and a 60.17 percent common equity ratio. The CPUC staff recommended one significant adjustment to PSCo’s request

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associated with the ROE request. The CPUC staff also raised policy concerns regarding PSCo’s partial decoupling proposal, but concluded that they neither supported nor opposed decoupling.

The OCC recommended an overall revenue decrease of $4.8 million related to three major adjustments. First, they recommended an ROE of 9 percent assuming a 60.17 percent common equity ratio. Second, they proposed a consolidated income tax adjustment, the effect of which is a revenue requirement decrease of $11.9 million. Third, they proposed an adjustment to depreciation and amortization expense, resulting in a revenue requirement decrease of $10.5 million. The OCC also recommended the disallowance of annual incentive compensation costs of $1.2 million, the revision of the weather normalization of test-year revenues, the rejection of PSCo’s partial decoupling proposal, and policy changes regarding PSCo’s line extension policy.

Rebuttal and cross-answer testimony is due on May 11, 2007, with hearings scheduled to begin on June 4, 2007. It is anticipated that the CPUC will act on the request such that the rates ultimately approved will become effective in the third quarter of 2007.

SPS

Pending and Recently Concluded Regulatory Proceedings — FERC

Wholesale Rate Complaints — In November 2004, Golden Spread Electric, Lyntegar Electric, Farmer’s Electric, Lea County Electric, Central Valley Electric and Roosevelt County Electric, wholesale cooperative customers of Southwestern Public Service Co., a New Mexico corporation (SPS), filed a rate complaint at the FERC. The complaint alleged that SPS’ rates for wholesale service were excessive and that SPS had incorrectly calculated monthly fuel cost adjustments contained in SPS’ wholesale rate schedules. Among other things, the complainants asserted that SPS was not properly calculating the fuel costs that are eligible for recovery to reflect fuel costs recovered from certain wholesale sales to other utilities, and that SPS had inappropriately allocated average fuel and purchased power costs to other of SPS’ wholesale customers, effectively raising the fuel costs charges to complainants. Cap Rock Energy Corporation (Cap Rock), another full-requirements customer, Public Service Company of New Mexico (PNM) and Occidental Permian Ltd. and Occidental Power Marketing, L.P. (Occidental) intervened in the proceeding.

On May 24, 2006, a FERC administrative law judge (ALJ) issued an initial recommended decision in the proceeding. The FERC will review the initial recommendation and issue a final order. SPS and others have filed exceptions to the ALJ’s initial recommendation. The FERC’s order may or may not follow any of the ALJ’s recommendation. In the recommended decision, the ALJ found that SPS should recalculate its wholesale fuel and purchased economic energy cost adjustment clause (FCAC) billings for the period beginning Jan. 1, 1999, to reduce the fuel and purchased power costs recovered from the complaining customers by allocating incremental fuel costs incurred by SPS in making wholesale sales of system firm capacity and associated energy to other firm customers at market-based rates during this period based on the view that such sales should be treated as opportunity sales.

SPS believes the ALJ erred on significant and material issues that contradict FERC policy or rules of law. Specifically, SPS believes, based on FERC rules and precedent, that it has appropriately applied its FCAC tariff to the proper classes of customers. These market-based sales were of a long-term duration under FERC precedent and were made from SPS’ entire system. Accordingly, SPS believes that the ALJ erred in concluding that these transactions were opportunity sales, which require the assignment of incremental costs.

The FERC has approved system average cost allocation treatment in previous filings by SPS for sales having similar service characteristics and previously accepted for filing certain of the challenged agreements with average fuel cost pricing.

Moreover, SPS believes that the ALJ’s recommendation constituted a violation of the Filed Rate Doctrine in that it effectively results in a retroactive amendment to the SPS FERC-approved FCAC tariff provisions. Under existing regulations, the FERC may modify a previously approved FCAC on a prospective basis. Accordingly, SPS believes it has applied its FCAC correctly and has sought review of the recommended decision by the FERC by filing a brief on the exceptions.

SPS has evaluated all sales made from Jan. 1, 1999, to Dec. 31, 2005. While SPS believes it should ultimately prevail in this proceeding; however, if the FERC were to adopt the majority of the ALJ’s recommendations, SPS’ refund exposure could be approximately $50 million. FERC action is pending. Additionally, SPS has entered into settlement discussions with the wholesale cooperative customers. During the three months ended March 31, 2007, SPS recognized an additional accrual based upon current estimates of  this potential liability.

Wholesale Power Base Rate Application — On Dec. 1, 2005, SPS filed 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 the $2.5 million power rate increase became 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 and an agreement in principle has been reached for base rates for the full-requirements customers and PNM. One other wholesale customer has not settled. On Sept. 7, 2006, the offer of settlement with respect to the full-requirements customer was filed for approval and on Sept. 19, 2006, the offer of settlement with respect to PNM was filed for approval. Subsequent to filing rebuttal testimony, on March 29, 2007, SPS and the remaining wholesale customer entered into settlement negotiations. The current hearing schedule has been postponed.

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Pending and Recently Concluded Regulatory Proceedings —  Public Utility Commission of Texas (PUCT)

Texas Retail Base Rate And Fuel Reconciliation Case — On May 31, 2006, SPS filed a Texas retail electric rate case requesting an increase in annual revenues of approximately $48 million, or 6.0 percent. The rate filing was based on a historical test year, an electric rate base of $943 million, a requested ROE of 11.6 percent and a common equity ratio of 51.1 percent.

In addition, SPS submitted a fuel reconciliation filing, which requested approval of approximately $957 million of Texas-jurisdictional fuel and purchased power costs for 2004 through 2005. The combined case was transferred to the Texas Office of Administrative Hearing. As a part of the fuel reconciliation case, fuel and purchased energy costs, which are recovered in Texas through a fixed-fuel and purchased energy recovery factor as a part of SPS’ retail electric rates, were reviewed.

On March 27, 2007, SPS and various intevernors filed a unanimous stipulation agreement related to the Texas retail rate case as well as the fuel reconciliation portion of the proceeding. The agreement includes the following terms:

•                     The settlement provides for an annual base rate increase of $23 million, or approximately 3 percent.

•                     The settlement is a “black box” agreement, with no stipulated ROE or capital structure.

•                     The settlement disallows approximately $27 million of SPS’ 2004 and 2005 fuel expense.

•                     An additional $2.3 million will be deducted from the company’s next fuel reconciliation filing to be made in 2008, associated with the 2006-2007 fuel reconciliation period.

•                     All of SPS’ existing long-term firm and interruptible capacity wholesale sales will be assigned system average cost for purposes of Texas retail ratemaking, except for sales to El Paso Electric (EPE), which will be determined by the PUCT separately.

•                     If the PUCT determines incremental fuel cost assignment related to the EPE contract is appropriate, the settlement provides that the fuel disallowance is limited to an annual amount of $6.3 million per year, from the date of the PUCT’s order through 2008.

•                     The settlement also creates standards for cost assignment that would apply to future wholesale sale transactions, and establishes margin sharing of market based wholesale demand revenues.

•                     If SPS files a general rate case in 2008, the settlement would allow for an interim rate increase associated with a purchased power agreement with Lea Power Partners of approximately $1.5 million per month from the date of commercial operations. Interim rates would be subject to a true-up based on the outcome of the rate case proceeding and actual capacity costs incurred.

An estimated settlement allowance and reserve was established in 2006 and prior periods, which approximated the settled amounts of previously deferred or recovered fuel expense; therefore, no additional expense associated with the fuel reconciliation portions of the settlement was recognized in the quarter. On March 27, 2007, the ALJ approved SPS’ request to implement the $23 million base rate increase, effective April 2007, on an interim basis until the PUCT acts on the stipulation. It is expected that the PUCT will consider the settlement at the same time as it considers the EPE wholesale cost assignment, which is likely to occur in the second quarter of 2007.

Pending and Recently Concluded Regulatory Proceedings — New Mexico Public Regulation Commission (NMPRC)

New Mexico Fuel Factor Continuation Filing — On Aug. 18, 2005, SPS filed with the NMPRC requesting continuation of the use of SPS’ fuel and purchased power cost adjustment clause (FPPCAC) and current monthly factor cost recovery methodology. This filing was required by NMPRC rule. Testimony has been filed in the case by staff and intervenors objecting to SPS’ assignment of system average fuel costs to certain wholesale sales and the inclusion of certain purchased power capacity and energy payments in the FPPCAC. The testimony also proposed limits on SPS’ future use of the FPPCAC. Related to these issues some intervenors have requested disallowances for past periods, which in the aggregate total approximately $45 million. Other issues in the case include the treatment of renewable energy certificates and sulfur dioxide allowance credit proceeds in relation to SPS’ New Mexico retail fuel and purchased power recovery clause. A hearing was held in April 2006, and the hearing examiner’s recommended decision and a NMPRC decision is expected in the second quarter of 2007. During the three months ended March 31, 2007, SPS recognized an additional accrual based upon current estimates of  this potential liability.

6. Commitments and Contingent Liabilities

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, 2006 and Notes 4, 5 and 7 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.

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 believes it will recover some portion of these costs through

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insurance 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.

Site Remediation — Xcel Energy must pay all or a portion of the cost to remediate sites where past activities of its subsidiaries and some other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including the following categories of sites:

•       Sites of former manufactured gas plants (MGPs) operated by Xcel Energy subsidiaries or predecessors; and

•       Third-party sites, such as landfills, to which Xcel Energy is alleged to be a potentially responsible party (PRP) that sent hazardous materials and wastes.

Xcel Energy records a liability when enough information is obtained to develop an estimate of the cost of environmental remediation and revises the estimate as information is received. The estimated remediation cost may vary materially.

To estimate the cost to remediate these sites, assumptions are made when facts are not fully known. For instance, assumptions may be made about the nature and extent of site contamination, the extent of required cleanup efforts, costs of alternative cleanup methods and pollution-control technologies, the period over which remediation will be performed and paid for, changes in environmental remediation and pollution-control requirements, the potential effect of technological improvements, the number and financial strength of other PRPs and the identification of new environmental cleanup sites.

Estimates are revised as facts become known. At March 31, 2007, the liability for the cost of remediating these sites was estimated to be $29.4 million, of which $4.0 million was considered to be a current liability. Some of the cost of remediation may be recovered from:

•       Insurance coverage;

•       Other parties that have contributed to the contamination; and

•       Customers.

Neither the total remediation cost nor the final method of cost allocation among all PRPs of the unremediated sites has been determined. Estimates have been recorded for Xcel Energy’s future costs for these sites.

Manufactured Gas Plant Sites

Ashland Manufactured Gas Plant Site — NSP-Wisconsin was named a PRP for creosote and coal tar contamination at a site in Ashland, Wis. The Ashland site includes property owned by NSP-Wisconsin, which was previously an MGP facility, and two other properties: an adjacent city lakeshore park area, on which an unaffiliated third party previously operated a sawmill, and an area of Lake Superior’s Chequemegon Bay adjoining the park.

On Sept. 5, 2002, the Ashland site was placed on the National Priorities List (NPL). A determination of the scope and cost of the remediation of the Ashland site is not currently expected until late 2007 or 2008 following the submission of the remedial investigation report and feasibility study in 2007. NSP-Wisconsin continues to work with the Wisconsin Department of Natural Resources (WDNR) to access state and federal funds to apply to the ultimate remediation cost of the entire site. In November 2005, the Environmental Protection Agency (EPA) Superfund Innovative Technology Evaluation Program (SITE) accepted the Ashland site into its program. As part of the SITE program, NSP-Wisconsin proposed and the EPA accepted a site demonstration of an in situ, chemical oxidation technique to treat upland ground water and contaminated soil. The field work for the demonstration study was completed in February 2007, and the EPA is scheduled to complete its assessment this summer. In 2006, NSP-Wisconsin spent $2.0 million in the development of the work plan, the interim response action and other matters related to the site.

The WDNR and NSP-Wisconsin have each developed several estimates of the ultimate cost to remediate the Ashland site. The estimates vary significantly, between $4 million and $93 million, because different methods of remediation and different results are assumed in each. The EPA and WDNR have not yet selected the method of remediation to use at the site. Until the EPA and the WDNR select a remediation strategy for the entire site and determine NSP-Wisconsin’s level of responsibility, NSP-Wisconsin’s liability for the cost of remediating the Ashland site is not determinable. NSP-Wisconsin has recorded a liability of $25.0 million for its potential liability for remediating the Ashland site and for external legal and consultant costs. Since NSP-Wisconsin cannot currently estimate the cost of remediating the Ashland site, that portion of the recorded liability related to remediation is based upon the minimum of the estimated range of remediation costs, using information available to date and reasonably effective remedial methods.

On Oct. 19, 2004, the WDNR filed a lawsuit in Wisconsin state court for reimbursement of past oversight costs incurred at the Ashland site between 1994 and March 2003 in the approximate amount of $1.4 million. The lawsuit has been stayed. NSP-Wisconsin has recorded an estimate of its potential liability. All costs paid to the WDNR are expected to be recoverable in rates.

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In addition to potential liability for remediation and WDNR oversight costs, NSP-Wisconsin may also have liability for natural resource damages (NRD) at the Ashland site. NSP-Wisconsin has indicated to the relevant natural resource trustees its interest in engaging in discussions concerning the assessment of natural resources injuries and in proposing various restoration projects in an effort to fully and finally resolve all NRD claims. NSP-Wisconsin is not able to estimate its potential exposure for NRD at the site, but has recorded an estimate of its potential liability based upon the minimum of its estimated range of potential exposure.

NSP-Wisconsin has deferred, as a regulatory asset, the costs accrued for the Ashland site based upon an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for MGP-related environmental remediation from its customers. The PSCW has consistently authorized recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site, and has authorized recovery of similar remediation costs for other Wisconsin utilities. External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin biennial retail rate case process.

In addition, in 2003, the Wisconsin Supreme Court rendered a ruling that reopens the possibility that NSP-Wisconsin may be able to recover a portion of the remediation costs from its insurance carriers. Any insurance proceeds received by NSP-Wisconsin will operate as a credit to ratepayers.

Fort Collins Manufactured Gas Plant Site — Prior to 1926, Poudre Valley Gas Co., a predecessor of PSCo, operated an MGP in Fort Collins, Colo., not far from the Cache la Poudre River. In 1926, after acquiring the Poudre Valley Gas Co., PSCo shut down the MGP site and has sold most of the property. An oily substance similar to MGP byproducts was discovered in the Cache la Poudre River. On Nov. 10, 2004, PSCo entered into an agreement with the EPA, the city of Fort Collins and Schrader Oil Co., under which PSCo performed remediation and monitoring work. PSCo has substantially completed work at the site, with the exception of ongoing maintenance and monitoring. In May 2005, PSCo filed a natural gas rate case with the CPUC requesting recovery of cleanup costs at the Fort Collins MGP site spent through March 2005, which amounted to $6.2 million, to be amortized over four years. PSCo reached a settlement agreement with the parties in the case. The CPUC approved the settlement agreement on Jan. 19, 2006 and the final order became effective on Feb. 3, 2006, with rates effective Feb. 6, 2006. In November 2006, PSCo filed a natural gas rate case with the CPUC requesting recovery of additional clean-up costs at the Fort Collins MGP site spent through September 2006, plus unrecovered amounts previously authorized from the last rate case, which amounted to $10.8 million to be amortized over four years. The total amount PSCo is requesting be recovered from customers is $13.1 million.

In April 2005, PSCo brought a contribution action against Schrader Oil Co. and related parties alleging Schrader Oil Co. released hazardous substances into the environment and these releases caused MGP byproducts to migrate to the Cache La Poudre River, thereby substantially increasing the scope and cost of remediation. PSCo requested damages, including a portion of the costs PSCo incurred to investigate and remove contaminated sediments from the Cache la Poudre River. On Dec. 14, 2005, the court denied Schrader’s request to dismiss the PSCo suit. On Jan. 3, 2006, Schrader filed a response to the PSCo complaint and a counterclaim against PSCo for its response costs under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA) and under the Resource Conservation and Recovery Act (RCRA). Schrader has alleged as part of its counterclaim an “imminent and substantial endangerment” of its property as defined by RCRA. In September 2006, PSCo filed a Motion For Partial Summary Judgment to dismiss Schrader’s RCRA claim. PSCo believes the allegations with respect to PSCo are without merit and will vigorously defend itself.

Third Party and Other Environmental Site Remediation

Asbestos Removal — Some of our facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. Xcel Energy has recorded an estimate for final removal of the asbestos as an asset retirement obligation. See additional discussion of asset retirement obligations in Note 14 to the Xcel Energy Annual Report on Form 10-K for the year ended Dec. 31, 2006. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Cunningham Station Groundwater — Cunningham Station is a natural gas-fired power plant constructed in the 1960s by SPS and has 28 water wells installed on its water rights. The well field provides water for boiler makeup, cooling water and potable water. Following an acid release in 2002, groundwater samples revealed elevated concentrations of inorganic salt compounds not related to the release. The contamination was identified in wells located near the plant buildings. The source of contamination is thought to be leakage from ponds that receive blow down water from the plant. In response to a request by the New Mexico Environment Department (NMED), SPS prepared a corrective action plan to address the groundwater contamination. Under the plan submitted to the NMED, SPS agreed to control leakage from the plant blow down ponds through construction of a new lined pond, additional irrigation areas to minimize percolation, and installation of additional wells to monitor groundwater quality. On June 23, 2005, NMED issued a letter approving the corrective action plan. The action plan is subject to continued compliance with New Mexico regulations and oversight by the NMED. SPS is evaluating implementation of a similar project at Maddox Station. These actions for Cunningham and Maddox are estimated to cost approximately $4.2 million through 2008 and will be capitalized or expensed as incurred.

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Construction and liner installation of the new pond has been completed. A permit application for discharges from the pond has been submitted to the NMED. It is expected that the pond will be ready to be placed into service when the NMED issues Cunningham a permit. The permitting process for Maddox has begun.

Other Environmental Requirements

Clean Air Interstate Rule — In March 2005, the EPA issued the Clean Air Interstate Rule (CAIR)  to further regulate SO2 and nitrogen oxide (NOx) emissions. The objective of CAIR is to cap emissions of SO2 and NOx in the eastern United States, including Minnesota, Texas and Wisconsin, which are within Xcel Energy’s service territory. Xcel Energy generating facilities in other states are not affected. CAIR addresses the transportation of fine particulates, ozone and emission precursors to nonattainment downwind states. CAIR has a two-phase compliance schedule, beginning in 2009 for NOx and 2010 for SO2, with a final compliance deadline in 2015 for both emissions. Under CAIR, each affected state will be allocated an emissions budget for SO2 and NOX that will result in significant emission reductions. It will be based on stringent emission controls and forms the basis for a cap-and-trade program. State emission budgets or caps decline over time. States can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.

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 the CAIR. El Paso Electric Co. joined in the request for reconsideration. 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 March 15, 2006, the EPA denied the petition for reconsideration. On June 27, 2006, Xcel Energy and the other parties filed a petition for review of the denial of the petition for reconsideration, as well as a petition for review of the Federal Implementation Plan, with the United States Court of Appeals for the District of Columbia Circuit. Pursuant to the court’s scheduling order, briefing is expected to be finalized in September 2007.

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, Xcel Energy currently believes that with the installation of low NOx burners on Harrington 3 in 2006, there are capital investments estimated at $23 million remaining for NOx controls in the SPS region. Annual purchases of SO₂ allowances are estimated in the range of $12 million to $26 million each year, beginning in 2012, for phase I, based on allowance costs and fuel quality as of December 2006.

In addition, Minnesota and Wisconsin will be included in CAIR, and Xcel Energy has generating facilities in these states that will be impacted. Preliminary estimates of capital expenditures associated with compliance with CAIR in Minnesota and Wisconsin range from $30 million to $40 million. Xcel Energy is not challenging CAIR in these states.

These cost estimates represent one potential scenario on complying 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.

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.

Clean Air Mercury Rule — In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR), which regulates mercury emissions from power plants for the first time. The EPA’s CAMR  uses a national cap-and-trade system, where compliance may be achieved by either adding mercury controls or purchasing allowances or a combination of both and is designed to achieve a 70 percent reduction in mercury emissions. It affects all coal- and oil-fired generating units across the country that are greater than 25 MW. Compliance with this rule occurs in two phases, with the first phase beginning in 2010 and the second phase in 2018. States will be allocated mercury allowances based on coal type and their baseline heat input relative to other states. Each electric generating unit will be allocated mercury allowances based on its percentage of total coal heat input for the state. Similar to the CAIR states can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.

Xcel Energy continues to evaluate the strategy for complying with CAMR. NSP-Minnesota currently estimates that it can comply through capital investments in emission controls or purchase of emission “allowances” from other utilities making reductions on their systems. Estimating the cost of compliance with CAMR is difficult because technologies specifically designed for control of mercury are in the early stages of development and there is no established market on which to base the cost of mercury allowances. NSP-Minnesota’s preliminary analysis for phase I compliance suggests capital costs of approximately $21.9 million for the mercury control equipment and continuous monitoring equipment at A.S. King, Sherburne County (Sherco) and Black Dog generating facilities. The analysis indicates increased operating and maintenance expenses of approximately $22.9 million, beginning in 2010. Additional costs

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will be incurred to meet phase II requirements in 2018. Recent testing indicates that NSP-Wisconsin facilities will be low mass mercury emitters: therefore, compliance with CAMR is not expected to require mercury controls or purchases of allowances. In February 2007, the Colorado Air Quality Control Commission passed a mercury rule. The rule was based on a negotiated rule that was agreed upon by participating environmental groups, utilities, local government coalitions, and the CAPCD. The rule requires controls to be installed at Pawnee Station in 2012 and all other Colorado units by 2014. Xcel Energy is evaluating the emission controls required to meet the new rule and is currently unable to provide a capital cost estimate. SPS continues to evaluate the strategy for complying with CAMR and estimates capital costs of $14.5 million for mercury control equipment.

Minnesota Mercury Legislation — On May 2, 2006, the Minnesota Legislature enacted the Mercury Emissions Reduction Act of 2006 (Act) providing a process for plans, implementation and cost recovery for utility efforts to curb mercury emissions at certain power plants. For Xcel Energy, the Act covers units at the A. S. King and Sherco generating facilities. Under the Act, Xcel Energy must install, maintain and operate continuous mercury emission monitoring systems or other monitoring methods approved by the Minnesota Pollution Control Agency (MPCA) at these units by July 1, 2007. The information obtained will be used to establish a baseline from which to measure mercury emission reductions. Mercury emission reduction plans must be filed by utilities by Dec. 31, 2007 (dry scrubbed units) and Dec. 31, 2009 (wet scrubbed units) that propose to implement technologies most likely to reduce emissions by 90 percent. Implementation would occur by Dec. 31, 2009 for one of the dry scrubbed units, Dec. 31, 2010 for the remaining dry scrubbed unit and Dec. 31, 2014 for wet scrubbed units. The cost of controls will be determined as part of the engineering analysis portion of the mercury reduction plans and is  currently estimated at $21.5 million for the mercury control and continuous monitoring equipment and increased operating and maintenance expenses of approximately $22.9 million, beginning in 2010. These costs are also included above as part of the total cost estimate to comply with CAMR. Utilities subject to the Act may also submit plans to address non-mercury pollutants subject to federal and state statutes and regulations, which became effective after Dec. 31, 2004. Cost recovery provisions of the Act also apply to these other environmental initiatives. On Sept. 15, 2006, NSP-Minnesota filed a request with the MPUC for deferred accounting of up to $6.3 million of certain environmental improvement costs that are expected to be recoverable under the Act. On Jan. 11, 2007, the MPUC approved this request for deferred accounting with a cap of $6.3 million.

Regional Haze Rules — On June 15, 2005, the EPA finalized amendments to the July 1999 regional haze rules. These amendments apply to the provisions of the regional haze rule that require emission controls, known as BART, for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze. Xcel Energy generating facilities in several states will be subject to BART requirements. Some of these facilities are located in regions where CAIR is effective. CAIR has precedence over BART. Therefore, BART requirements will be deemed to be met through compliance with CAIR requirements.

The EPA required states to develop implementation plans to comply with 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. On May 30, 2006, the Colorado Air Quality Control Commission promulgated BART regulations requiring certain major stationary sources to evaluate and install, operate and maintain BART technology or an approved BART alternative to make reasonable progress toward meeting the national visibility goal. On Aug. 1, 2006, PSCo submitted its BART alternatives analysis to the CAPCD. As set forth in its analysis, PSCo estimates that implementation of the BART alternatives will cost approximately $211 million in capital costs, which includes approximately $62 million in environmental upgrades for the existing Comanche Station project, which are included in the capital budget. Xcel Energy expects the cost of any required capital investment will be recoverable from customers. Emissions controls are expected to be installed between 2008 and 2012.

Minnesota has also begun implementing its BART strategy as the first step toward the December 2007 deadline. NSP-Minnesota submitted its BART alternatives analysis for Sherco units 1 and 2 on Oct. 26, 2006. The expected cost associated with the range of alternatives for additional emission controls for SO₂ and NOx is a capital investment of $7 million to $617 million. NSP- Minnesota supports the alternative with the associated cost estimate of $7 million; however, NSP-Minnesota has not yet received a response from the MPCA concerning its preferred alternative. Xcel Energy expects that the costs of any required capital investment will be recoverable from customers. All BART issues are addressed by the voluntary capacity upgrades noted below.

Voluntary Capacity Upgrade and Emissions Reduction Filing — On Jan. 2, 2007, NSP-Minnesota made a filing to the MPUC for a major emissions reduction project at the Sherco Units 1, 2 and 3 to reduce emissions and expand capacity by installing NOx controls (low NOx burners, overfire air and Selective Catalytic Reduction), installing mercury control systems, replacing the wet scrubbers on units 1 and 2 with semi-dry scrubbers, retrofitting different sections of the turbines on all three units, replacing generators and other associated equipment on all three units, and installing additional cooling capacity. The projected cost of this project is approximately $905 million and encompasses the BART capital investment of $7 million to $617 million noted above. NSP-Minnesota’s investments are subject to the MPUC approval of a cost recovery mechanism.

Federal Clean Water Act — The federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure that these structures reflect the “best technology available” for minimizing adverse environmental impacts. In July 2004, the EPA published phase II of the rule, which applies to existing cooling water intakes at steam-electric power plants. Several lawsuits were filed against the EPA in the United States Court of Appeals for the Second Circuit challenging the phase II rulemaking. On Jan. 25, 2007, the court issued its decision and remanded virtually every aspect of the rule to the EPA for reconsideration. The EPA

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announced on March 20, 2007, it will suspend the deadlines and refer any implementation to each state’s best professional judgment until the EPA is able to fully respond to the court-ordered remands. As a result, the rule’s compliance requirements and associated deadlines are currently unknown. 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.

PSCo Notice of Violation — On July 1, 2002, PSCo received a Notice of Violation (NOV) from the EPA alleging violations of the New Source Review (NSR) requirements of the Clean Air Act (CAA) at the Comanche and Pawnee plants in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process. PSCo believes it has acted in full compliance with the CAA and NSR process. It believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position. As required by the CAA, the EPA met with Xcel Energy in September 2002 to discuss the NOV.

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.

Arandell vs. e prime, Xcel Energy, NSP-Wisconsin et al. —  In February 2007, a complaint was filed alleging that NSP-Wisconsin, Xcel Energy and e prime, among others, engaged in fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. The plaintiffs seek a declaration that contracts for natural gas entered into between Jan. 1, 2000 and Oct. 31, 2002 are void, that they are entitled to repayment for amounts paid for natural gas during that time period, and that treble damages are appropriate. The case was filed in the Wisconsin State Court (Dane County), and then removed to U.S. District Court for the Western District of Wisconsin. The plaintiffs have filed a motion to remand the matter to state court. NSP-Wisconsin, together with the other defendants, intend to oppose the motion for remand and seek dismissal of all claims.

Heartland Regional Medical Center vs. e prime, Xcel Energy et al. — In March 2007, a complaint was filed in the Circuit Court of Buchanan County, Missouri on behalf of a purported class of natural gas purchasers alleging that defendants, including e prime and Xcel Energy, engaged in a conspiracy and falsely reported natural gas trades in an effort to artificially raise natural gas prices. The complaint alleges restraint of trade, price manipulation, and violation of Missouri’s antitrust laws. e prime and Xcel Energy deny the allegations and, together with the other defendants, intend to seek dismissal of all claims.

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 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. On Jan. 19, 2005, Xcel Energy filed a motion for summary judgment. On July 26, 2005, the court issued an order granting Xcel Energy’s motion for summary judgment in part with respect to claims for interference with ERISA benefits, breach of contract for nonpayment of stock options and unjust enrichment. The court denied Xcel Energy’s motion in part with respect to the allegations of nonpayment of deferred compensation benefits. Plaintiffs and Xcel Energy filed additional cross motions for summary judgment, with oral arguments presented on Feb. 24, 2006.

On May 17, 2006, the court granted Xcel Energy’s motion for summary judgment in full and denied the plaintiff’s motion for summary judgment in full. Plaintiffs have appealed to the Eighth Circuit Court of Appeals. Oral arguments were presented Jan. 11, 2007.

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 U.S. District Court for the Southern District of 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 natural 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. In October 2004, Xcel Energy and four other utility companies filed a motion to dismiss the lawsuit, contending, among other reasons, that the lawsuit is an attempt to usurp the policy-setting role of the U.S. Congress and the president. On Sept. 19, 2005, the judge granted the defendants’ motion to dismiss on constitutional grounds. Plaintiffs filed an appeal to the Second Circuit Court of Appeals. Oral arguments were presented on June 7, 2006 and a decision on the appeal is pending.

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Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al. — On Nov. 19, 2003, a class action complaint filed in the U.S. District Court for the Eastern District of California by Texas-Ohio Energy, Inc. was served on Xcel Energy naming e prime as a defendant. The lawsuit, filed on behalf of a purported class of large wholesale natural gas purchasers, alleges that e prime falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California. The case has been conditionally transferred by the Multi-District Litigation (MDL) Panel to U.S. District Judge Pro, in Nevada, who is the judge assigned to western area wholesale natural gas marketing litigation. In an order entered April 8, 2005, Judge Pro granted the defendants’ motion to dismiss based on the filed rate doctrine. On May 9, 2005, plaintiffs filed an appeal of this decision to the 9th Circuit Court of Appeals and oral arguments on the appeal were heard on Feb. 13, 2007.

Fairhaven Power Company vs. Encana Corporation et al. — On Sept. 14, 2004, a class action complaint was filed in the U.S. District Court for the Eastern District of California by Fairhaven Power Co. and subsequently served on Xcel Energy. The lawsuit, filed on behalf of a purported class of natural gas purchasers, alleges that Xcel Energy falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California and engaged in a conspiracy with other sellers of natural gas to inflate prices. This case has been consolidated with Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al. and assigned to U.S. District Judge Pro. Defendants filed a motion to dismiss, which was granted on Dec. 19, 2005. The plaintiffs subsequently appealed and the appeal is pending.

Utility Savings and Refund Services LLP vs. Reliant Energy Services Inc. — On Nov. 29, 2004, a class action complaint was filed in the U.S. District Court for the Eastern District of California by Utility Savings and Refund Services LLP and subsequently served on Xcel Energy. The lawsuit, filed on behalf of a purported class of natural gas purchasers, alleges that Xcel Energy falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California and engaged in a conspiracy with other sellers of natural gas to inflate prices. This case has been consolidated with Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al. and assigned to U.S. District Judge Pro. Defendants filed a motion to dismiss, which was granted on Dec. 19, 2005. Plaintiffs subsequently appealed and the appeal is pending.

Abelman Art Glass vs. Ercana Corporation et al. — On Dec. 13, 2004, a class action complaint was filed in the U.S. District Court for the Eastern District of California by Abelman Art Glass and subsequently served on Xcel Energy. The lawsuit, filed on behalf of a purported class of natural gas purchasers, alleges that Xcel Energy falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California and engaged in a conspiracy with other sellers of natural gas to inflate prices. This case has been consolidated with Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al and assigned to U.S. District Judge Pro. Defendants filed a motion to dismiss, which was granted on Dec. 19, 2005. Plaintiffs subsequently appealed to the 9^th Circuit Court of Appeals and oral arguments on the appeal were heard on Feb. 13, 2007.

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, inc. in the U.S. District Court for the Northern District of Oklahoma 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 natural gas sellers to inflate prices through alleged false reporting of natural 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, 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 was conditionally transferred to U.S. District Court Judge Pro. Judge Pro granted the motion to dismiss, and Sinclair appealed to the Ninth Circuit Court of Appeals. Sinclair’s appeal has been stayed pending the Ninth Circuit’s disposition of the Abelman Art Glass and Texas-Ohio appeals.

Ever-Bloom Inc. vs. Xcel Energy Inc. and e prime et al. — On June 21, 2005, a class action complaint was filed in the U.S. District Court for the Eastern District of California by Ever-Bloom, Inc. The lawsuit names as defendants, among others, Xcel Energy and e prime. The lawsuit, filed on behalf of a purported class of natural gas purchasers, alleges that defendants falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California, purportedly in violation of the Sherman Act. This matter has been stayed pending the outcome of cases on appeal to the Ninth Circuit Court of Appeals.

Learjet, Inc. vs. e prime and Xcel Energy et al. — On Nov. 4, 2005, a purported class action complaint was filed in State Court for Wyandotte County of Kansas on behalf of all natural gas producers in Kansas. The lawsuit alleges that e prime, Xcel Energy and other named defendants conspired to raise the market price of natural gas in Kansas by, among other things, inaccurately reporting price and volume information to the market trade publications. On Dec. 7, 2005, the state court granted the defendants motion to remove this matter to the U.S. District Court in Kansas. Plaintiffs have filed a motion for remand, which was denied on Aug. 3, 2006. Plaintiffs in this matter and in the J.P. Morgan Trust case, discussed below, have moved the judicial panel on MDL for a separate MDL docket to be set up in Kansas Federal Court. Xcel Energy’s motion to dismiss the complaint is pending.

J.P. Morgan Trust Company vs. e prime and Xcel Energy Inc. et al. — On Oct. 17, 2005, J.P. Morgan Trust Company, 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 raise natural gas prices. The lawsuit was removed to the U.S.

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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 to state court filed by plaintiffs has been denied. A motion to dismiss plaintiff’s case was granted in December 2006. Plaintiff subsequently filed a motion to amend the judgment and defendents filed an opposition to that motion in February 2007.

Breckenridge Brewery vs. e prime and Xcel Energy Inc. et al. — In May, 2006, Breckenridge Brewery, a Colorado corporation, filed a complaint in Colorado State District Court for the City and County of Denver alleging that the defendants, including e prime and Xcel Energy, unlawfully prevented full and free competition in the trading and sale of natural gas, or controlled the market price of natural gas, and engaged in a conspiracy in constraint of trade. Notice of removal to federal court on behalf of Xcel Energy Inc. and e prime, inc. was filed in June 2006. On July 6, 2006, the Colorado State District Court granted an enlargement of time within which to file a pleading in response to the complaint.

Plaintiffs filed a motion to remand the matter to state court, which was denied in October 2006, and the matter has been transferred to U.S. District Court Judge Pro, in Nevada.

Missouri Public Service Commission vs. e prime, inc. and Xcel Energy Inc. — On Oct. 24, 2006, the Missouri Public Utilities Commission filed a complaint in State Court for Jackson County of Missouri alleging that e prime, Xcel Energy and 21 other defendants falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices. The complaint further alleges that such conduct constitutes a violation of the Missouri Antitrust Law, fraud and unjust enrichment. This matter has been removed to U.S. District Court, and plaintiffs have indicated they intend to file a motion to remand to state court. Xcel Energy and e prime deny plaintiffs’ allegations and intend to vigorously defend themselves in this action.

Payne et al. vs. PSCo et al. — In late October 2003, there was a wildfire in Boulder County, Colorado. There was no loss of life, but there was property damage associated with this fire. On Oct. 28, 2005, an action against PSCo relating to this fire was filed in Boulder County District Court. There are 22 plaintiffs, including individuals, the City of Jamestown and two companies, and three co-defendants, including PSCo. Plaintiffs asserted that a tree falling into PSCo distribution lines may have caused the fire. The matter was ultimately settled in March 2007 and  the settlement did not have a material effect on Xcel Energy’s financial results.

Comanche 3 Permit Litigation — On Aug. 4, 2005, Citizens for Clean Air and Water in Pueblo and Southern Colorado and Clean Energy Action filed a complaint against the Colorado Air Pollution Control Division alleging that the Division improperly granted permits to PSCo under Colorado’s Prevention of Significant Deterioration program for the construction and operation of Comanche 3. PSCo intervened in the case. On June 20, 2006, the court ruled in PSCo’s favor and held that the Comanche 3 permits had been properly granted and plaintiffs’ claims to the contrary were without merit. Plaintiffs have appealed this decision. On Nov. 22, 2006, plaintiffs filed their opening briefs. PSCo’s response was filed Dec. 22, 2006. The Colorado Court of Appeals is expected to rule on the appeal in 2007.

Fru-Con Construction Corporation vs. Utility Engineering (UE) et al. — On March 28, 2005, Fru-Con Construction Corporation (Fru-Con) commenced a lawsuit in U.S. District Court for the Eastern District of California against UE and the Sacramento Municipal Utility District (SMUD) for damages allegedly suffered during the construction of a natural gas-fired, combined-cycle power plant in Sacramento County. Fru-Con’s complaint alleges that it entered into a contract with SMUD to construct the power plant and further alleges that UE was negligent with regard to the design services it furnished to SMUD. UE denies this claim and intends to vigorously defend itself. Because this lawsuit was commenced prior to the April 8, 2005, closing of the sale of UE to Zachry, Xcel Energy is obligated to indemnify Zachry for damages related to this case up to $17.5 million. Pursuant to the terms of its professional liability policy, UE is insured up to $35 million. On June 1, 2005, UE filed a motion to dismiss Fru-Con’s complaint. A hearing concerning this motion was held on July 18, 2005, with the court taking the matter under advisement. On Aug. 4, 2005, the court granted UE’s motion to dismiss. Because SMUD remains a defendant in this action, the court has not entered a final judgment subject to an appeal with respect to its order to dismiss UE from the lawsuit.

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 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 making rent payments. NSP-Minnesota had made rent payments for 45 years. Depositions of key witnesses took place in February, March and April of 2006. The parties entered into meaningful settlement negotiations in May 2006, and in August 2006 reached an oral settlement of the dispute. The parties are negotiating over the final form of the settlement documents and it is expected that the action will be formally dismissed in the near future.

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Siewert vs. Xcel Energy — Plaintiffs, the owners and operators of a Minnesota dairy farm, brought an action against NSP-Minnesota alleging negligence in the handling, supplying, distributing and selling of electrical power systems; negligence in the construction and maintenance of distribution systems; and failure to warn or adequately test such systems. Plaintiffs allege decreased milk production, injury, and damage to a dairy herd as a result of stray voltage resulting from NSP-Minnesota’s distribution system. Plaintiffs’ expert report on the economic damage to their dairy farm states that the total present value of plaintiffs’ loss is $6.8 million. Trial is scheduled to commence in January 2008. NSP-Minnesota denies these allegations and will vigorously defend itself in this matter.

Hoffman vs. Northern States Power Company — On March 15, 2006, a purported class action complaint was filed in Minnesota State District Court in 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 alleged 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 filed a motion for dismissal on the pleadings, which was heard on Aug. 16, 2006. In November 2006, the court issued an order denying NSP-Minnesota’s motion. On Nov. 28, 2006, pursuant to a motion by NSP-Minnesota, the court certified the issues raised in NSP-Minnesota’s original motion as important and doubtful. This certification permits NSP-Minnesota to file an appeal, and it has done so.

Comer vs. Xcel Energy Inc. et al. — On April 25, 2006, Xcel Energy received notice of a purported class action lawsuit filed in U.S. 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’ CO2 “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 loss resulting from the hurricane. Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims. On July 19, 2006, Xcel Energy filed a motion to dismiss the lawsuit in its entirety.

Qwest vs. Xcel Energy Inc. — On June 24, 2004, an employee of PSCo, was injured when a pole, owned by Qwest malfunctioned. The employee is seeking damages of approximately $7 million. On Sept. 6, 2005, an action against Qwest relating to incident was filed in Denver District Court by the employee. On April 18, 2006, Qwest filed a third party complaint against PSCo based on terms in a joint pole use agreement between Qwest and PSCo. Pursuant to this agreement, Qwest has asserted that PSCo had an affirmative duty to properly train and instruct its employees on pole safety, including testing the pole for soundness before climbing. PSCo filed a counterclaim on May 15, 2006, against Qwest asserting Qwest had a duty to PSCo and an obligation under the contract to maintain its poles in a safe and serviceable condition. This case is still in the discovery phase and set for a 7 day jury trial beginning May 14, 2007.

MGP Insurance Coverage Litigation — In October 2003, NSP-Wisconsin initiated discussions with its insurers regarding the availability of insurance coverage for costs associated with the remediation of four former MGP sites located in Ashland, Chippewa Falls, Eau Claire, and LaCrosse, Wis. In lieu of participating in discussions, on Oct. 28, 2003, two of NSP-Wisconsin’s insurers, St. Paul Fire & Marine Insurance Co. and St. Paul Mercury Insurance Co., commenced litigation against NSP-Wisconsin in Minnesota state district court. On Nov. 12, 2003, NSP-Wisconsin commenced suit in Wisconsin state circuit court against St. Paul Fire & Marine Insurance Co. and its other insurers. Subsequently, the Minnesota court enjoined NSP-Wisconsin from pursuing the Wisconsin litigation. Although the Wisconsin action has not been dismissed, the January 2007 trial date was adjourned and has not been rescheduled.

NSP-Wisconsin has entered into confidential settlements with St. Paul Mercury Insurance Company, St. Paul Fire and Marine Insurance Company and the Phoenix Insurance Company (St. Paul Companies), Associated Electric & Gas Insurance Services Limited, Fireman’s Fund Insurance Company, INSCO, Ltd. (on its own behalf and on behalf of the insurance companies subscribing per Britamco, Ltd.), Allstate Insurance Company, Admiral Insurance Company; certain underwriters at Lloyd’s, London and certain London Market Insurance Companies (London Market Insurers), and Compagnie Europeene D’ Assurances Industrielles S.A. These insurers have been dismissed from the Minnesota and Wisconsin actions. These settlements are not expected to have a material effect on Xcel Energy’s financial results.

NSP-Wisconsin has reached settlements in principle with General Reinsurance Corporation and First State and Twin City Fire Insurance Companies. These settlements are not expected to have a material effect on Xcel Energy’s financial results.

On Oct. 6, 2006, the trial court issued a memorandum and order on various summary judgment motions. The court ruled that Minnesota law on allocation applies and ordered dismissal, without prejudice, of 15 carriers whose coverage would not be triggered under such an allocation method. The court denied the insurers’ motions for summary judgment on the sudden and accidental and absolute pollution exclusions; late notice; legal expenses and costs; certain specific lost policies; and miscellaneous coverage issues under several individual policies. The court granted the motions of Fidelity and Casualty Insurance Company and Continental Insurance Company related to certain specific lost policies. On Oct. 13, 2006, the trial court denied NSP-Wisconsin’s request for leave to file a motion for reconsideration of the court’s allocation decision. The Nov. 6, 2006 trial date was also adjourned to allow for additional discovery and potential motions in light of the Minnesota Supreme Court’s recent allocation decision in Wooddale Builders, Inc. v. Maryland Casualty Company, 722 N. W.2d 283 (Minn. 2006). The insurers have moved for summary judgement based upon

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Wooddale Builders. At the court’s request, the parties have submitted additional briefs on the choice of law issue. A hearing on these issues has been scheduled for May 21, 2007. The trial has been set for a four-week period commencing on July 16, 2007. The PSCW has established a deferral process whereby clean-up costs associated with the remediation of former MGP sites are deferred and, if approved by the PSCW, recovered from ratepayers. Carrying charges associated with these clean-up costs are not subject to the deferral process and are not recoverable from ratepayers. Any insurance proceeds received by NSP-Wisconsin will operate as a credit to ratepayers, therefore, these lawsuits are not expected to have a material effect on Xcel Energy’s financial results.

Other Contingencies

•       Tax Matters — See Note 4 to the consolidated financial statements for discussion of exposures regarding the tax deductibility of corporate-owned life insurance loan interest; and

•       Guarantees — See Note 7 to the consolidated financial statements for discussion of exposures under various guarantees.

7. Short-Term Borrowings and Other Financing Instruments

Short-Term Borrowings

At March 31, 2007, Xcel Energy and its subsidiaries had approximately $734.5 million of short-term debt outstanding at a weighted average interest rate of 5.43 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, 2007, Xcel Energy had issued guarantees of up to $75.2 million with $17.5 million of 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, 2007, was approximately $111.1 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. Debt Exchange

On March 30, 2007, Xcel Energy settled an exchange offer for up to $350 million aggregate principal amount of its 7 percent Senior Notes, Series due 2010 (the Old Notes). Xcel Energy accepted approximately $241.4 million aggregate principal amount of its Old Notes in exchange for approximately $254.0 million aggregate principal amount of a new series of 5.613 percent senior notes due April 1, 2017 (the New Notes). The $12.6 million non-cash increase in the aggregate principal amount was a result of financing the premium associated with the exchange. In addition, Xcel Energy paid the following amounts in cash: (i) approximately $4.8 million to certain investors as an early participation payment for Old Notes validly tendered prior to 5:00 p.m., New York City time, on March 13, 2007 and accepted for exchange; (ii) approximately $57,000 in cash in lieu of New Notes; and (iii) accrued and unpaid interest to, but not including, the settlement date with respect to the Old Notes accepted for exchange.

The New Notes were issued only to holders of Old Notes that certified certain matters to Xcel Energy, including their status as either “qualified institutional buyers,” as that term is defined in Rule 144A under the Securities Act of 1933, or persons other than “U.S. persons,” as that term is defined in Rule 902 under the Securities Act of 1933. The New Notes were issued with a registration rights agreement.

In accordance with the Emerging Issues Task Force Issue No. 96-19 (EITF 96-19), Debtor’s Accounting for a Modification or Exchange of Debt Instruments, this transaction was accounted for as an exchange. As such, the fees paid to the bondholders have been associated with the replacement debt instruments and, along with the existing unamortized discount, will be amortized as an adjustment of interest expense over the remaining term of the replacement debt instruments. Also, as required by EITF 96-19, the fees paid to third parties were expensed as incurred and $1.7 million was included in interest charges and other financing costs in the Consolidated Statements of Income.

9. Derivative Valuation and Financial Impacts

Xcel Energy and its subsidiaries use a number of different derivative instruments in connection with their utility operations, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. These derivative instruments are utilized in connection with various commodity prices, certain energy related products, including emission allowances and renewable energy credits, and interest rates. All derivative instruments not qualifying for the normal purchases and normal sales exception, as

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defined by SFAS 133-”Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS 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 specific regulation. 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 permits the classification of fair value to be recorded within Other Comprehensive Income, to the extent effective. The designation of a fair value hedge permits a derivative instrument’s gains or losses to offset the related results of the hedged item in the Consolidated Statements of Income.

Xcel Energy records the fair value of its derivative instruments in its Consolidated Balance Sheets as separate line items identified as Derivative Instruments Valuation in both current and noncurrent assets and liabilities.

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.

Qualifying hedging relationships are designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), or a hedge of a recognized asset, liability or firm commitment (fair value hedge). The types of qualifying hedging transactions in which Xcel Energy and its subsidiaries are currently engaged are discussed below.

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 or deferred as a regulatory asset or liability.

As of March 31, 2007, 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 purchase or sale of energy or energy-related products, the use of natural gas to generate electric energy or gas purchased for resale.

As of March 31, 2007, Xcel Energy had no amounts in Accumulated 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.

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.

As of March 31, 2007, Xcel Energy had net gains of approximately $0.1 million in Accumulated Other Comprehensive Income related to interest rate cash flow hedge contracts that are expected to be recognized in earnings during the next 12 months.

Gains or losses on hedging transactions for the sales of energy or energy-related products are recorded as a component of revenue, hedging transactions for fuel used in energy generation are recorded as a component of fuel costs, hedging transactions for gas purchased for resale are recorded as a component of gas costs and interest rate hedging transactions are recorded as a component of interest expense. Certain utility subsidiaries are allowed to recover in electric or gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility. There was an immaterial amount of ineffectiveness in the first quarter of 2007.

The impact of qualifying cash flow hedges on Xcel Energy’s Accumulated Other Comprehensive Income, included in the Consolidated Statements of Stockholders’ Equity and Comprehensive Income, is detailed in the following table:

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Fair Value Hedges

The effective portion of the change in the fair value of a derivative instrument qualifying as a fair value hedge is offset 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 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 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from SFAS 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 133, as amended. None of the contracts entered into within the commodity trading operations qualify for a normal designation.

Normal purchases and normal sales contracts are accounted for as executory contracts.

10. 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: