Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended March 31, 2010

or

Commission File Number: 1-3034

Xcel Energy Inc.

(Exact name of registrant as specified in its charter)

(612) 330-5500

 (Registrant’s telephone number, including area code)

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   x Yes o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

TABLE OF CONTENTS

This Form 10-Q is filed by Xcel Energy Inc. Xcel Energy Inc. wholly owns the following subsidiaries: Northern States Power Company, a Minnesota corporation (NSP-Minnesota); Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado, a Colorado corporation (PSCo); and Southwestern Public Service Company, a New Mexico corporation (SPS). Additional information on the wholly owned subsidiaries is available on various filings with the Securities and Exchange Commission (SEC).

2

Table of Contents

PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands, except per share data)

See Notes to Consolidated Financial Statements

3

Table of Contents

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

(amounts in thousands of dollars)

See Notes to Consolidated Financial Statements

4

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in thousands of dollars)

See Notes to Consolidated Financial Statements

5

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

See Notes to Consolidated Financial Statements

6

Table of Contents

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, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) as of March 31, 2010 and Dec. 31, 2009; the results of its operations and changes in stockholders’ equity for the three months ended March 31, 2010 and 2009; and its cash flows for the three months ended March 31, 2010 and 2009. All adjustments are of a normal, recurring nature, except as otherwise disclosed.  Management has also evaluated the impact of events occurring after March 31, 2010 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.  The Dec. 31, 2009 balance sheet information has been derived from the audited 2009 financial statements.  These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q.  Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations.  For further information, refer to the consolidated financial statements and notes thereto included in the Xcel Energy Annual Report on Form 10-K for the year ended Dec. 31, 2009, filed with the SEC on Feb. 26, 2010.  Due to the seasonality of Xcel Energy’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

1.     Summary of 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, 2009, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

Reclassifications — Conservation and demand side management program expenses for the three months ended March 31, 2009 were reclassified as a separate item from depreciation and amortization expenses within the consolidated statements of cash flows.  The reclassification did not have an impact on net cash provided by operating activities.

2.     Accounting Pronouncements

Recently Adopted

Consolidation of Variable Interest Entities — In June 2009, the Financial Accounting Standards Board (FASB) issued new guidance on consolidation of variable interest entities.  The guidance affects various elements of consolidation, including the determination of whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary.  These updates to the FASB Accounting Standards Codification (ASC or Codification) are effective for interim and annual periods beginning after Nov. 15, 2009.  Xcel Energy implemented the guidance on Jan. 1, 2010, and the implementation did not have a material impact on its consolidated financial statements.  For further information and required disclosures regarding variable interest entities, see Note 7 to the consolidated financial statements.

Fair Value Measurement Disclosures — In January 2010, the FASB issued Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements (Accounting Standards Update (ASU) No. 2010-06), which updates the Codification to require new disclosures for assets and liabilities measured at fair value.  The requirements include expanded disclosure of valuation methodologies for fair value measurements, transfers between levels of the fair value hierarchy, and gross rather than net presentation of certain changes in Level 3 fair value measurements.  The updates to the Codification contained in ASU No. 2010-06 were effective for interim and annual periods beginning after Dec. 15, 2009, except for requirements related to gross presentation of certain changes in Level 3 fair value measurements, which are effective for interim and annual periods beginning after Dec. 15, 2010.  Xcel Energy implemented the portions of the guidance required on Jan. 1, 2010, and the implementation did not have a material impact on its consolidated financial statements.  For further information and required disclosures, see Note 10 to the consolidated financial statements.

7

Table of Contents

3.            Selected Balance Sheet Data

4.     Discontinued Operations

Results of operations for divested businesses are reported, for all periods presented, as discontinued operations.  The majority of current and noncurrent assets related to discontinued operations are deferred tax assets associated with temporary differences and net operating loss (NOL) and tax credit carryforwards that will be deductible in future years.

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

8

Table of Contents

5.     Income Taxes

Corporate Owned Life Insurance (COLI) — In 2007, Xcel Energy and the U. S. government settled an ongoing dispute regarding PSCo’s right to deduct interest expense on policy loans related to its COLI program that insured lives of certain PSCo employees.  These COLI policies were owned and managed by P.S.R. Investments, Inc. (PSRI), a wholly owned subsidiary of PSCo.  Xcel Energy paid the U. S. government a total of $64.4 million in settlement of the U. S. government’s claims for tax, penalty, and interest for tax years 1993 through 2007.  Xcel Energy surrendered the policies to its insurer on Oct. 31, 2007, without recognizing a taxable gain.  As a result of the settlement, the lawsuit filed by Xcel Energy in the United States District Court has been dismissed and the Tax Court proceedings are in the process of being dismissed.

As part of the Tax Court proceedings, during the first quarter of 2010, Xcel Energy and the IRS (Internal Revenue Service) reached an agreement in principle after a two year financial reconciliation of Xcel Energy’s statements of account, dating back to tax year 1993.  This tax and interest analysis required a comprehensive review of all of Xcel Energy’s tax filings since 1993.  Upon completion of this review, PSRI recorded a net non-recurring adjustment of approximately $10 million (including $7.7 million tax expense and $2.3 million interest expense, net of tax), or $0.02 per share during the current period.  Xcel Energy anticipates that the Tax Court proceedings will be dismissed in 2010.

Medicare Part D Subsidy Reimbursements — In March 2010, the Patient Protection and Affordable Care Act was signed into law.  The law includes provisions to generate tax revenue to help offset the cost of the new legislation.  One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013.  Based on this provision, Xcel Energy is subject to additional taxes and is required to reverse previously recorded tax benefits in the period of enactment.  Xcel Energy expensed approximately $17 million, or $0.04 per share, of previously recognized tax benefits relating to Medicare Part D subsidies during the first quarter of 2010.  Xcel Energy does not expect the $17 million of additional tax expense to recur in future periods.  The 2010 effective tax rate will increase due to additional tax expense of approximately $4 million associated with current year retiree health care accruals.

Federal Audit — Xcel Energy files a consolidated federal income tax return.  In the first quarter of 2010, the IRS completed an examination of Xcel Energy’s federal income tax returns of tax years 2006 and 2007.  The IRS did not propose any material adjustments for those tax years.  The statute of limitations applicable to Xcel Energy’s 2006 federal income tax return expires on Aug. 28, 2010.

State Audits — Xcel Energy files consolidated 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.  As of March 31, 2010, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions are as follows:

The state of Texas has notified Xcel Energy of its intent to audit tax years 2006 and 2007.  The audit will commence in the second quarter of 2010.  There currently are no other state income tax audits in progress.  In 2009, Xcel Energy received a request for information from the state of Minnesota relating to tax years 2002 through 2007 in order to determine whether to undertake an audit of those years.  As of March 31, 2010, the state of Minnesota had not informed Xcel Energy of its intentions.

Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate (ETR).  In addition, the unrecognized tax benefit balance includes temporary tax positions 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 ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

9

Table of Contents

A reconciliation of the amount of unrecognized tax benefit in continuing operations is as follows:

A reconciliation of the amount of unrecognized tax benefit in discontinued operations is as follows:

The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards.  The amounts of tax benefits associated with NOL and tax credit carryforward as reported in continuing operations and discontinued operations were as follows:

The increase in the unrecognized tax benefit balance reported in continuing operations of $1.1 million from Dec. 31, 2009 to March 31, 2010 was due primarily to the addition of similar uncertain tax positions related to ongoing activity.  Xcel Energy’s amount of unrecognized tax benefits for continuing operations could significantly change in the next 12 months as the Texas audit begins and when the IRS and other state audits resume.  At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.  A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits reported in continuing operations is as follows:

A reconciliation of the beginning and ending amount of the receivable for interest related to unrecognized tax benefits reported in discontinued operations is as follows:

No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2010 or Dec. 31, 2009.

10

Table of Contents

6.     Rate Matters

Except to the extent noted below, the circumstances set forth in Note 16 to the consolidated financial statements included in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2009 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

NSP-Minnesota

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

Base Rate

NSP-Minnesota Gas Rate Case — In November 2009, NSP-Minnesota filed a request with the MPUC to increase Minnesota natural gas rates by $16.2 million for 2010, which represents a 2.8 percent overall increase in customer bills.  The overall request seeks an additional $3.45 million, effective Jan. 1, 2011, for recovery of pension funding costs necessary to comply with federal law.  In December 2009, the MPUC voted to approve an interim rate increase of $11.1 million, subject to refund.  Interim rates went into effect on Jan. 11, 2010.

The procedural schedule is listed below and a decision is expected in the fall of 2010.

·      Intervenor direct testimony on May 3, 2010;

·      NSP-Minnesota rebuttal testimony on June 2, 2010;

·      Surrebuttal testimony on June 15, 2010;

·      Evidentiary hearings on June 21 through 25, 2010;

·      Initial briefs on July 27, 2010;

·      Reply briefs and proposed findings on Aug. 19, 2010; and

·      Administrative law judge (ALJ) report on Oct. 1, 2010.

Electric, Purchased Gas and Resource Adjustment Clauses

Transmission Cost Recovery (TCR) Rider — The MPUC has approved a TCR rider, which allows annual adjustments to retail electric rates to provide recovery of incremental transmission investments between rate cases.  On April 1, 2010, the MPUC approved the 2010 TCR rider resulting in approximately $10.8 million in revenue, including initial costs associated with three of the four CapX 2020 transmission projects.  The MPUC did not allow 2010 recovery of $1.2 million in costs associated with the Brookings, S.D. transmission line because of uncertainty in cost allocation among utilities as the result of Midwest Independent Transmission System Operator, Inc. (MISO) tariff changes currently under development for filing with the Federal Energy Regulatory Commission (FERC) in July 2010.  The MPUC also expressed a desire to limit recovery based on initial project estimates and make adjustments in a rate case after a project is placed in service.  This approach to rider administration will not impact the 2010 TCR request.

Renewable Energy Standard (RES) Rider — The MPUC has approved a rider to recover the costs for utility-owned projects implemented in compliance with the Minnesota RES.  On April 1, 2010, the MPUC approved the 2010 RES rider that will result in $45.6 million in revenue.  As noted with the TCR rider above, the MPUC also expressed a desire to limit recovery based on initial project estimates and make adjustments in a rate case after a project is placed in service.  This approach to rider administration is not expected to have a material impact in 2010.

Annual Automatic Adjustment Report for 2007/2008 — In March 2010, the MPUC issued an order accepting the 2008 electric annual automatic adjustment report.  The order completes the MPUC review of NSP-Minnesota recovery of approximately $896 million of fuel and purchased energy costs for the period July 1, 2007 to June 30, 2008.  The MPUC had accepted the NSP-Minnesota 2008 natural gas report in 2009.

11

Table of Contents

NSP-Wisconsin

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

2009 Electric Fuel Cost Recovery — In April 2009, the PSCW initiated a fuel cost recovery proceeding under the Wisconsin fuel rules and set NSP-Wisconsin’s rates subject to refund with interest, pending a full review of 2009 fuel costs.  The PSCW has not yet completed its audit, but based on actual 2009 fuel costs, NSP-Wisconsin anticipates a $19.1 million fuel refund obligation.  In NSP-Wisconsin’s 2010 rate case decision, the PSCW authorized NSP-Wisconsin to apply $6.4 million of the 2009 fuel refund obligation to offset the 2010 Wisconsin retail electric rate increase.  The remainder, estimated at $12.7 million, was refunded to customers based on a per kilowatt hour credit applied to all sales from Feb. 16 through March 15, 2010.  Any difference between the final audited refund amount, including interest, and the actual amount refunded to customers will be deferred to NSP-Wisconsin’s next rate proceeding.

2010 Electric Fuel Cost Recovery — NSP-Wisconsin’s fuel and purchased power costs through March 2010 were approximately $1.8  million, or 4.5 percent lower than authorized in the 2010 electric rate case, which is outside the monthly and cumulative variance ranges for monitored fuel costs established by the PSCW.  Pursuant to the fuel rules, it is expected that during the second quarter of 2010, NSP-Wisconsin’s electric rates will be set subject to refund with interest at 10.4 percent, pending a full review of 2010 fuel costs.

PSCo

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

Base Rate

PSCo 2010 Electric Rate Case — In May 2009, PSCo filed with the CPUC a request to increase Colorado electric rates by $180.2 million, or 6.8 percent, effective in 2010.  The request was based on a 2010 forecast test year, an 11.25 percent return on equity (ROE), a rate base of $4.4 billion and an equity ratio of 58.05 percent.  In October 2009, PSCo filed rebuttal testimony and revised the requested rate increase to $177.4 million.

In November 2009, PSCo reached a settlement agreement with certain intervenors.  The settlement included an electric rate increase of approximately $136 million, effective Jan. 1, 2010.  The settlement was based on a 10.5 percent ROE and reflects PSCo’s actual capital structure.  The settlement was based on an historic test year, adjusted for 2010 known and measurable changes related to plant investment as well as certain operating costs.

In December 2009, the CPUC approved a rate increase of approximately $128.3 million.  The difference between the settlement rate increase and the approved amount was primarily related to adjustments related to rate base for non-major projects and an adjustment to interest on long-term debt.

In December 2009, due to the delay in Comanche Unit 3 coming online, the CPUC approved PSCo’s proposal to phase in the approved electric rate increase to reflect the actual cost of service.  This decision is not expected to have a material impact on PSCo or Xcel Energy’s financial results.  Under the plan, the following increases will be implemented:

·      A rate increase of $67 million was implemented on Jan. 1, 2010.  The adjustments to the rate increase, because of the delay of the in-service date of Comanche Unit 3, include reduced operating and maintenance expenses (O&M), property taxes, the impact of a delay in changes to jurisdictional allocators and depreciation expenses;

·      Base rates will increase to $121 million, once Comanche Unit 3 goes into service; and

·      Finally, base rates will increase to $128.3 million on Jan. 1, 2011 to reflect 2011 property taxes.

Several parties, including PSCo and the Office of Consumer Counsel (OCC), filed motions for reconsideration.  On April 19, 2010, the CPUC granted PSCo’s request to not include long-term debt interest in the working capital calculation, which increases the revenue deficiency recovered under the order by approximately $2.2 million, and denied all other requests for reconsideration.

Although PSCo had anticipated that Comanche Unit 3 would come online by the end of the first quarter of 2010, the testing of Comanche Unit 3 was initiated and has resulted in a noise that has been objectionable to some neighbors of the plant.  PSCo has arranged for the fabrication of baffles to be installed that are expected to mitigate the noise.  After the installation and testing of the corrective action, PSCo expects Comanche Unit 3 to go into service in the second quarter of 2010.

12

Table of Contents

Unreasonable Rates for Natural Gas Formal Complaint — In July 2009, the trial advocacy staff of the CPUC proposed a formal draft complaint against PSCo for unjust and unreasonable rates for natural gas service associated with earnings in excess of PSCo’s authorized return that occurred in 2008.  In January 2010, the CPUC opened a proceeding and assigned this matter to an ALJ.

The procedural schedule in the case has been set as follows:

·      Direct testimony of CPUC staff on May 10, 2010;

·      PSCo answer testimony on June 28, 2010;

·      Staff rebuttal testimony on July 19, 2010;

·      Surrebuttal testimony on Aug. 9, 2010; and

·      Hearings on Aug. 23 through Aug. 27, 2010.

PSCo filed certain information concerning its financial results for calendar year 2009 with the ALJ on April 19, 2010, and the CPUC staff is expected to file its direct case on May 10, 2010.

Renewable Energy Credit (REC) Sharing Settlement — In August 2009, PSCo filed an application seeking approval of treatment of margins associated with certain sales of Colorado RECs bundled with energy into California.  In January 2010, PSCo, the OCC, the CPUC staff, the Colorado governor’s energy office and Western Resource Advocates entered into a unanimous settlement in this case.  The settlement establishes a pilot program and defines certain margin splits during this pilot period.  The settlement provides that 10 percent of margins will go to carbon offsets, 40 percent of the first $10 million in margins, 35 percent of the next $20 million and 30 percent of all remaining margins will go to PSCo with all remaining margins going to Colorado retail customers as a credit toward renewable energy projects.  The unanimous settlement also clarified that margins associated with RECs bundled with Colorado energy would be shared 20 percent to PSCo and 80 percent to customers and margins associated with sales of stand-alone renewable energy credits without energy would be credited 100 percent to customers.  The CPUC approved the settlement in oral deliberations on April 21, 2010.  A written order is expected to follow.

Pending and Recently Concluded Regulatory Proceedings — FERC

Wholesale Rate Case — In 2009, PSCo proposed to increase Colorado wholesale rates by $30 million based on a 12.5 percent ROE, a 58 percent equity ratio and an electric production rate base of $315 million.  PSCo has requested that the FERC suspend action on the filing to allow time for settlement negotiations as PSCo is in settlement discussions with its wholesale customers.  PSCo expects rates subject to refund to go into effect later in 2010.

SPS

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

Base Rate

Lubbock Electric Distribution Assets — In November 2009, SPS entered into an agreement with the city of Lubbock, Texas (City of Lubbock), in which SPS will sell its electric distribution system assets within the city limits to the City of Lubbock for approximately $87 million.  As part of this transaction, SPS will continue to provide the wholesale power to meet the electric load for the customers that SPS currently serves.  The wholesale power agreements provide for formula rates that change annually based on the actual cost of service.  The formula rate with West Texas Municipal Power Agency (WTMPA) reflects an initial 10.5 percent ROE.  All or portions of this transaction are subject to review and approval by the PUCT, the New Mexico Public Regulation Commission (NMPRC) and the FERC.  This transaction is expected to close late in 2010.  It is anticipated that any resulting gain on the sale of assets will be shared with retail customers in Texas.

The FERC has accepted the amended WTMPA full-requirements contract.  Parties in the Texas proceeding have begun settlement talks.

13

Table of Contents

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, all wholesale cooperative customers of SPS, filed a rate complaint with the FERC alleging that SPS’ rates for wholesale service were excessive and that SPS had incorrectly calculated monthly fuel cost adjustment charges to such customers (the Complaint).  Among other things, the complainants asserted that SPS had inappropriately allocated average fuel and purchased power costs to other wholesale customers, effectively raising the fuel cost charges to the complainants.  Cap Rock Energy Corporation (Cap Rock), another full-requirements customer of SPS, Public Service Company of New Mexico (PNM) and Occidental Permian Ltd. and Occidental Power Marketing, L.P. (Occidental), SPS’ largest retail customer, intervened in the proceeding.

Golden Spread Complaint Settlement — In December 2007, SPS reached a settlement with Golden Spread (which now includes Lyntegar Electric) and Occidental regarding base rate and fuel issues raised in the complaint described above as well as a subsequent rate proceeding.  In April 2008, the FERC approved the settlement, which resolved all issues pertaining to Golden Spread that were the subject of the Complaint; implemented a formula rate and extended the term of its partial requirements sale to Golden Spread beginning 2012 at 500 megawatts (MW) and ramping down to 200 MW for the two years prior to the end of the term in 2019.  The settlement made the extended purchase contingent on certain state approvals.  Golden Spread agreed to hold SPS harmless from any future adverse regulatory treatment regarding the proposed sale and SPS agreed to contingent payments ranging from $3 million to a maximum of $12 million, payable in 2012, in the event that there is an adverse cost assignment decision or a failure to obtain state approvals.  Requests for certain state approvals have been obtained from the PUCT and NMPRC.

New Mexico Cooperatives’ Complaint Settlement — In January 2010, SPS reached a settlement with Farmers’ Electric Cooperative of New Mexico, Lea County Electric Cooperative, Central Valley Electric Cooperative and Roosevelt County Electric Cooperative, all wholesale customers of SPS located in New Mexico, and Occidental regarding the same base rate and fuel issues raised in the complaint described above.  The settlement with these wholesale customers is now pending approval by the FERC.  The settlement resolves all issues arising from the complaint docket and implements a replacement contract with a formula production rate at 10.5 percent ROE and extended term of its requirements sale to the four wholesale customers.  The four wholesale customers must reduce their system average cost power purchases by 90 to 100 MW in 2012, and implement staged reductions in system average cost power purchases through the term of the agreement, which terminates on May 31, 2026.  The settlement made the replacement contract contingent on certain state approvals.  In the event not all regulatory approvals are received, the settlement includes a one time total contingent payment of $12 million by SPS to these wholesale customers.  These wholesale customers agreed to hold SPS harmless from any future adverse regulatory treatment regarding the proposed wholesale power sale.

Order on Wholesale Rate Complaints — In April 2008, the FERC issued its Order on the Complaint applied to the remaining non-settling parties.  The Order addresses base rate issues for the period from Jan. 1, 2005 through June 30, 2006, for SPS’ full requirements customers who pay traditional cost-based rates and requires certain refunds.

Several parties, including SPS, filed requests for rehearing on the order.  These requests are pending before the FERC.  In July 2008, SPS submitted its compliance report to the FERC and calculated the base rate refund for the 18-month period to be $6.1 million and the fuel refund to be $4.4 million.  Several wholesale customers have protested the calculations.  Once the final refund amounts are approved by the FERC, interest will be added to the refund due to the remaining non-settled customers.  As of March 31, 2010, SPS has accrued an amount sufficient to cover the estimated refund obligation.

7.    Commitments and Contingent Liabilities

Except to the extent noted below and in Note 6 to the consolidated financial statements in this Quarterly Report on Form 10-Q, the circumstances set forth in Notes 16, 17 and 18 to the consolidated financial statements included in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2009, appropriately represent, in all material respects, the current status of 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 contingencies and unresolved contingencies that are material to Xcel Energy’s financial position.

Commitments

Variable Interest Entities — Effective Jan. 1, 2010, Xcel Energy adopted new guidance on consolidation of variable interest entities contained in ASC 810 Consolidation.  The guidance requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary.

14

Table of Contents

Purchased Power Agreements — The utility subsidiaries of Xcel Energy have entered into agreements with other utilities and energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance or during outages, and meet operating reserve obligations.

NSP-Minnesota, PSCo and SPS have various pay-for-performance contracts with expiration dates through the year 2034.  In general, these contracts provide for energy payments based on actual power taken under the contracts as well as capacity payments.  Capacity payments are typically contingent on the independent power producing entity meeting certain contract obligations, including plant availability requirements.  Certain contractual payments are adjusted based on market indices; however, the effects of price adjustments are mitigated through purchased energy cost recovery mechanisms.

Xcel Energy is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is in the future required to be provided other than contractual payments for energy and capacity set forth in purchased power agreements.

Certain natural gas and biomass fueled purchased power agreements that either reimburse the independent power producing entities for fuel costs, or contain tolling arrangements under which Xcel Energy procures the fuel required to produce the energy it purchases, have been determined to be variable interest entities.

Xcel Energy has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over operations and maintenance, historical and estimated future fuel and electricity prices, and financing activities; including the maintenance of debt to equity financing ratios.  Xcel Energy has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.  As of March 31, 2010 and Dec. 31, 2009, Xcel Energy had approximately 5,012 MW of capacity under long-term purchased power agreements with entities that have been determined to be variable interest entities.

Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk electric generating stations from TUCO, Inc. (TUCO) under contracts for those facilities that expire in 2016 and 2017, respectively.  TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to meet SPS’ requirements.  TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.

No significant financial support has been, or is in the future, required to be provided to TUCO by SPS, other than contractual payments for delivered coal.  However, the fuel contracts have been determined to create a variable interest in TUCO due to SPS’ reimbursement of certain fuel procurement costs.  SPS has evaluated the TUCO coal supply contracts and has concluded that it is not the primary beneficiary because SPS does not have the power to direct the activities that most significantly impact TUCO’s economic performance.

Low-Income Housing Limited Partnerships — Eloigne Company (Eloigne) and NSP-Wisconsin have entered into limited partnerships for the construction and operation of affordable rental housing developments which qualify for low-income housing tax credits.  Xcel Energy has determined Eloigne and NSP-Wisconsin’s low-income housing limited partnerships to be variable interest entities primarily due to contractual arrangements within each limited partnership that establish sharing of ongoing voting control and profits and losses that does not consistently align with the partners’ proportional equity ownership.  These limited partnerships are designed to qualify for low-income housing tax credits, and Eloigne and NSP-Wisconsin generally receive a larger allocation of the tax credits than the general partners at inception of the arrangements.  It has been determined that Eloigne and NSP-Wisconsin have the power to direct the activities that most significantly impact these entities’ economic performance, and therefore Xcel Energy consolidates these limited partnerships in its consolidated financial statements.

Equity financing for these entities has been provided by Eloigne and NSP-Wisconsin and the general partner of each limited partnership, and Xcel Energy’s risk of loss is limited to its capital contributions, adjusted for any distributions and its share of undistributed profits and losses; no significant additional financial support has been, or is in the future, required to be provided to the limited partnerships by Eloigne or NSP-Wisconsin.  Mortgage-backed debt typically comprises the majority of the financing at inception of each limited partnership and is paid over the life of the limited partnership arrangement.  Obligations of the limited partnerships are generally secured by the low income housing properties of each limited partnership, and the creditors of each limited partnership have no significant recourse to Xcel Energy or its subsidiaries.  Likewise, the assets of the limited partnerships may only be used to settle obligations of the limited partnerships, and not those of Xcel Energy or its subsidiaries.

15

Table of Contents

Amounts reflected in Xcel Energy’s consolidated balance sheets for the Eloigne and NSP-Wisconsin low-income housing limited partnerships include the following:

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 insurance claims.  Additionally, where applicable, the subsidiary involved is pursuing, or intends to pursue, recovery from other potentially responsible parties (PRPs) 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 or other parties have caused environmental contamination.  Environmental contingencies could arise from various situations, including sites of former manufactured gas plants (MGPs) operated by Xcel Energy subsidiaries, predecessors, or other entities; and third-party sites, such as landfills, for which Xcel Energy is alleged to be a PRP that sent hazardous materials and wastes.  At March 31, 2010, the liability for the cost of remediating these sites was estimated to be $102.3 million, of which $6.4 million was considered to be a current liability.

Manufactured Gas Plant Sites

Ashland MGP Site — NSP-Wisconsin has been named a PRP for creosote and coal tar contamination at a site in Ashland, Wis.  The Ashland/Northern States Power Lakefront Superfund Site (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 Chequamegon Bay adjoining the park.

In September 2002, the Ashland site was placed on the National Priorities List.  A final determination of the scope and cost of the remediation of the Ashland site is not currently expected until sometime in 2010.  In October 2004, the state of Wisconsin 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 state also alleged a claim for forfeitures and interest.  This litigation was resolved in the first quarter of 2009, and all costs paid to the state are expected to be recoverable in rates.

In 2009, the Environmental Protection Agency (EPA) issued its proposed remedial action plan (PRAP).  The estimated remediation costs for the cleanup proposed by the EPA in the PRAP range between $94.4 million and $112.8 million.  NSP-Wisconsin submitted comments to EPA in response to the PRAP, and indicated that it had serious concerns about the cleanup approach proposed by the EPA.  It is expected that the EPA will select a final remedial action plan sometime in 2010.

16

Table of Contents

NSP-Wisconsin’s potential liability, the actual cost of remediating the Ashland site and the time frame over which the amounts may be paid out are not determinable until the EPA selects a remediation strategy for the entire site and determines NSP-Wisconsin’s level of responsibility.  NSP-Wisconsin continues to work with the Wisconsin Department of Natural Resources to access state and federal funds to apply to the ultimate remediation cost of the entire site.  NSP-Wisconsin has recorded a liability of $97.5 million based upon the minimum of the range of remediation costs established by the PRAP, together with estimated outside legal, consultant and remedial design costs.  NSP-Wisconsin has deferred, as a regulatory asset, the costs accrued for the Ashland site based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for 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 be credited to ratepayers.

In addition to potential liability for remediation, NSP-Wisconsin may also have potential liability for natural resource damages at the Ashland site.  NSP-Wisconsin has recorded an estimate of its potential liability based upon its best estimate of potential exposure.

Third Party and Other Environmental Site Remediation

Asbestos Removal — Some of Xcel Energy’s 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 (ARO).  See additional discussion of AROs in Note 17 to the Xcel Energy Annual Report on Form 10-K for the year ended Dec. 31, 2009.  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.

Other Environmental Requirements

Colorado Clean Air-Clean Jobs Act — The Colorado Clean Air-Clean Jobs Act (the Act) was signed into law on April 19, 2010.  The Act establishes a timeline and regulatory framework for rate-regulated utilities in Colorado to develop a plan to potentially retrofit, retire or replace 900 MW or more of aging coal-fired electric generating capacity.  The plan must result in a reduction of 70 to 80 percent in nitrogen oxide (NOx) emissions from affected coal-fired power plants by 2018 or sooner to meet current and reasonably foreseeable Clean Air Act (CAA) emission reduction mandates.

Under the emission reduction plan, PSCo may retrofit its existing coal-fired plants with emission controls or retire and replace the plants with natural gas-fired generation or other low emitting resources.  The Act specifically requires PSCo to study the early retirement of up to 900 MW of existing coal-fired capacity, but does not require any retirement unless, among other things, the retirement can be accomplished at a reasonable cost while protecting system reliability.  PSCo must submit its plan to the CPUC by Aug. 15, 2010 and the CPUC must act on the plan by Dec. 15, 2010.  Pursuant to the Act, PSCo is entitled to fully recover the costs that it prudently incurs in executing an approved emission reduction plan and is allowed a return on construction work in progress and annual changes in rates to recover plant costs.  The Act also makes interim rates permissible in Colorado, starting Jan. 1, 2012.

EPA Greenhouse Gas (GHG) Endangerment Finding — On Dec. 7, 2009, in response to the U. S. Supreme Court’s decision in Massachusetts v. EPA, 549 U. S. 497 (2007), the EPA issued its “endangerment” finding that GHG emissions endanger public health and welfare and that emissions from motor vehicles contribute to the GHGs in the atmosphere.  This endangerment finding creates a mandatory duty for the EPA to regulate GHGs from light duty vehicles.  On April 1, 2010, the EPA issued GHG efficiency standards for light duty vehicles, which will take effect on Jan. 2, 2011.  The EPA takes the position that after Jan. 2, 2011, any permit issued for major stationary sources, such as power plants, must address GHG emissions through Best Available Control Technology review and emissions limits.

Clean Air Interstate Rule (CAIR) — In March 2005, the EPA issued the CAIR to further regulate sulfur dioxide (SO2) and 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.  In response to the decisions by the U. S. Court of Appeals for the District of Columbia, which vacated but later reinstated CAIR while the EPA develops revised regulations, the EPA has indicated that a CAIR replacement rule will be proposed in May 2010 with finalization planned for 2011.

17

Table of Contents

As currently written, 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.

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.  The remaining capital investments for NOx controls in the SPS region are estimated at $4.5 million.  For 2009, the NOx allowance compliance costs were $1.7 million.  The estimated NOx allowance cost for 2010 is $1.2 million.  Annual purchases of SO2 allowances are estimated in the range of $1.7 million to $7.7 million each year, beginning in 2013, for phase I.

On Nov. 3, 2009, the EPA published a rule staying the effectiveness of CAIR in Minnesota effective Dec. 3, 2009.  Cost estimates are therefore not included at this time for NSP-Minnesota.  For 2009, the NOx allowance costs for NSP-Wisconsin were $0.5 million.  The estimated NOx allowance cost for 2010 is $0.4 million.  Allowance cost estimates for SPS and NSP-Wisconsin are based on fuel quality and current market data.  Xcel Energy believes the cost of any required capital investment or allowance purchases will be recoverable from customers in rates.

Clean Air Mercury Rule (CAMR) — In March 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants.  In February 2008, the U. S. Court of Appeals for the District of Columbia vacated CAMR, which impacts federal CAMR requirements, but not necessarily state-only mercury legislation and rules.  The EPA has agreed to finalize Maximum Achievable Control Technology (MACT) emission standards for all hazardous air pollutants from electric utility steam generating units by November 2011 to replace CAMR.  Xcel Energy anticipates that the EPA will require affected facilities to demonstrate compliance within 18 to 36 months thereafter.

Colorado Mercury Regulation — The Colorado Air Quality Control Commission (AQCC) passed a mercury rule, which requires mercury emission controls capable of achieving 80 percent capture to be installed at the Pawnee Generating Station by 2012 and other specified units by 2014.  The expected cost estimate for the Pawnee Generating Station is $2.3 million for capital costs with an annual estimate of $1.4 million for sorbent expense.  PSCo is evaluating the emission controls required to meet the state rule for the remaining units and is currently unable to provide a total capital cost estimate.

Minnesota Mercury Legislation — In May 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 NSP-Minnesota, the Act covers units at the A. S. King and Sherco generating facilities.  NSP-Minnesota installed and is operating and maintaining continuous mercury emission monitoring systems at these generating facilities.

In November 2008, the MPUC approved and ordered the implementation of the Sherco Unit 3 and A. S. King mercury emission reduction plans.  A sorbent injection control system was installed at Sherco Unit 3 in December 2009, with installation at A. S. King scheduled for December 2010.  In an order dated Nov. 4, 2009, the MPUC authorized NSP-Minnesota to collect approximately $3.5 million from customers through a mercury rider in 2010.

On Dec. 21, 2009, NSP-Minnesota filed the plans for mercury control at Sherco Units 1 and 2 with the MPUC and the Minnesota Pollution Control Agency (MPCA).  Assuming these plans are approved, NSP-Minnesota expects to file for recovery of the costs to implement these plans through the mercury cost recovery rider.

Regional Haze Rules — In June 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 best available retrofit technology (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.  States are required to identify the facilities that will have to reduce SO2, NOx and particulate matter emissions under BART and then set BART emissions limits for those facilities.

PSCo

In May 2006, the Colorado AQCC promulgated BART regulations requiring certain major stationary sources to evaluate and install, operate and maintain BART to make reasonable progress toward meeting the national visibility goal.  PSCo expects the cost of any required capital investment will be recoverable from customers.  Emissions controls are expected to be installed between 2012 and 2015.  Colorado’s BART state implementation plan (SIP) has been submitted to the EPA for approval.  The Colorado Air Pollution Control Division (CAPCD) is currently analyzing what types of additional NOx controls may be necessary to meet reasonable progress goals for Colorado’s Class I areas, the new ozone standard, and Rocky Mountain National Park nitrogen deposition reduction goals.  The CAPCD has indicated that it expects to submit a Regional Haze/Reasonable Further Progress SIP to the EPA in early

18

Table of Contents

2011.  PSCo anticipates that for those plants included in the Clean Air-Clean Jobs Act’s emission reduction plan, the plan will satisfy regional haze requirements.

In March 2010, two environmental groups petitioned the U. S. Department of Interior (DOI) to certify that 12 coal-fired boilers and one coal-fired cement kiln in Colorado are contributing to visibility problems in Rocky Mountain National Park.  Four PSCo plants are named in the petition:  Cherokee, Hayden, Pawnee and Valmont.  The groups allege that the Colorado BART rule is inadequate to satisfy the CAA mandate of ensuring reasonable further progress towards restoring natural visibility conditions in the park.  It is not known when the DOI will rule on the petition.

NSP-Minnesota

NSP-Minnesota submitted its BART alternatives analysis for Sherco Units 1 and 2 in October 2006.  The MPCA reviewed the BART analyses for all units in Minnesota and determined that overall, compliance with CAIR is better than BART.  On Nov. 13, 2008, NSP-Minnesota submitted a revised BART alternatives analysis letter to the MPCA to account for increased construction and equipment costs.  The underlying conclusions and proposed emission control equipment, however, remain unchanged from the original 2006 BART analysis.  The MPCA completed their BART determination and proposed SO2 and NOx limits in the draft SIP that are equivalent to the reductions made under CAIR.

On Oct. 21, 2009, the DOI certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to pollution emissions from NSP-Minnesota’s Sherco Units 1 and 2.  The EPA currently administers the 1980 Visibility Protection Rules for the State of Minnesota through a Federal Implementation Plan.  As such, EPA Region 5 is required to make its own determination as to whether Sherco Units 1 and 2 cause or contribute to visibility impairment and if so, whether the level of controls proposed by MPCA is appropriate.

The MPCA determined that this certification does not alter the proposed SIP.  The SIP proposes BART controls for Sherco that are designed to improve visibility in the national parks, but does not require Selective Catalytic Reduction (SCR) on Units 1 and 2.  The MPCA concluded that the minor visibility benefits derived from SCR do not outweigh the substantial costs.  On Dec. 15, 2009, the MPCA Citizens Board approved the SIP, which has been submitted to the EPA for approval.

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 (BTA) 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 (Court of Appeals) challenging the phase II rulemaking.  In January 2007, the Court of Appeals issued its decision and remanded the rule to the EPA for reconsideration.  In June 2007, the EPA suspended the deadlines and referred any implementation to each state’s best professional judgment until the EPA is able to fully respond to the remand.  In April 2008, the U. S. Supreme Court granted limited review of the Court of Appeals’ opinion to determine whether the EPA has the authority to consider costs and benefits in assessing BTA.  On April 1, 2009, the U. S. Supreme Court issued a decision in Entergy Corp. v. Riverkeeper, Inc., concluding that the EPA can consider a cost benefit analysis when establishing BTA.  The decision overturned only one aspect of the Court of Appeals’ earlier opinion, and gives the EPA the discretion to consider costs and benefits when it reconsiders its phase II rules.  Until the EPA fully responds to the Court of Appeals’ decision, the rule’s compliance requirements and associated deadlines will remain unknown.  As such, it is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time.

The MPCA exercised its authority under best professional judgment to require the Black Dog Generating Station in its recently renewed wastewater discharge permit to create and submit a plan by April 30, 2010 to reduce the plant intake’s impact on aquatic wildlife.  NSP-Minnesota is discussing alternatives with the local community and regulatory agencies to address this concern.

PSCo Notice of Violation (NOV) — In July 2002, PSCo received an NOV from the EPA alleging violations of the New Source Review (NSR) requirements of the CAA at the Comanche Station and Pawnee Station 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.  PSCo 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.

Cunningham Draft Compliance Order — On Feb. 18, 2010, SPS received a draft compliance order from the New Mexico Environment Department (NMED) for Cunningham Station.  In the draft order, NMED alleges that Cunningham exceeded its permit limits for NOx on 7,336 occasions and failed to report these exceedances as required by its permit.  The draft order includes a proposed penalty of $16.1 million.  SPS denies these allegations and will have an opportunity to discuss the alleged violations and proposed penalty with NMED prior to the issuance of a final order.  SPS will vigorously defend its position in negotiations with NMED.

19

Table of Contents

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.

Gas Trading Litigation

e prime, inc. (eprime) is a wholly owned subsidiary of Xcel Energy.  Among other things, e prime was in the business of natural gas trading and marketing.  e prime has not engaged in natural gas trading or marketing activities since 2003.  Thirteen lawsuits have been commenced against e prime and Xcel Energy (and NSP-Wisconsin, in one instance); alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices.  Xcel Energy, e prime, and NSP-Wisconsin deny these allegations, believe they are without merit and will vigorously defend against these lawsuits, including seeking dismissal and summary judgment.

The initial gas-trading lawsuit, a purported class action brought by wholesale natural gas purchasers, was filed in November 2003 in the United States District Court in the Eastern District of California.  e prime is one of several defendants named in the complaint. This case is captioned Texas-Ohio Energy vs. CenterPoint Energy et al.  The other twelve cases arising out of the same or similar set of facts are captioned Fairhaven Power Company vs. EnCana Corporation et al.; Ableman Art Glass vs. EnCana Corporation et al.; Utility Savings and Refund Services LLP vs. Reliant Energy Services Inc. et al.; Sinclair Oil Corporation vs. e prime and Xcel Energy Inc.; Ever-Bloom Inc. vs. Xcel Energy Inc. and e prime et al.; Learjet, Inc. vs. e prime and Xcel Energy Inc et al.; J.P. Morgan Trust Company vs. e prime and Xcel Energy Inc. et al.; Breckenridge Brewery vs. e prime and Xcel Energy Inc. et al.; Missouri Public Service Commission vs. e prime, inc. and Xcel Energy Inc. et al.; Arandell vs. e prime, Xcel Energy, NSP-Wisconsin et al.; NewPage Wisconsin System Inc vs. e prime, Xcel Energy, NSP-Wisconsin et al. and Heartland Regional Medical Center vs. e prime, Xcel Energy et al. Many of these cases involve multiple defendants and have been transferred to Judge Phillip Pro of the U. S. District Court in Nevada, who is the judge assigned to the Western Area Wholesale Natural Gas Antitrust Litigation.

e prime and some other defendants were dismissed from the Breckenridge Brewery lawsuit in February 2008, but Xcel Energy remains a defendant in that lawsuit and e prime Energy Marketing was added as a defendant in February 2008.

No trial dates have been set for any of these lawsuits.  In 2009, the parties reached a settlement agreement in the Abelman Art Glass, Ever Bloom, Fairhaven Power Company, Texas-Ohio Energy, and Utility Savings and Refund Services cases.  The terms of the settlement did not have a material financial effect upon Xcel Energy.  Discovery in most of the remaining cases was completed by Dec. 5, 2009.  In October 2009, the Court granted defendants’ motion to renew their summary judgment motions and such motions were filed in November 2009.  If summary judgment is not granted, trial for all cases venued in Nevada will likely be set for 2010.

In November 2007, the Missouri Public Service Commission case was remanded to Missouri state court.  On Jan. 13, 2009, the Missouri state court granted defendants’ motion to dismiss plaintiff’s complaint for lack of standing.  Plaintiffs filed an appeal and on Dec. 8, 2009, the Missouri Court of Appeals affirmed the dismissal.

In March 2009, Newpage Wisconsin System Inc. commenced a lawsuit in state court in Wood County, Wis.  The allegations are substantially similar to Arandell and name several defendants, including Xcel Energy, e prime and NSP-Wisconsin.  In September 2009, Plaintiffs moved to consolidate the Newpage and Arandell matters.  Defendants have filed motions to dismiss and, as with Arandell, Xcel Energy, e prime and NSP-Wisconsin believe the allegations asserted against them are without merit and they intend to vigorously defend against the asserted claims.

Environmental Litigation

Carbon Dioxide (CO2) Emissions Lawsuit — In 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U. S. District Court in the Southern District of New York against five utilities, including Xcel Energy, to force reductions in CO2 emissions.  The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority.  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.  On Sept. 19, 2005, the court granted a motion to dismiss on constitutional grounds.  Plaintiffs filed an appeal to the U. S. Court of Appeals for the Second Circuit.  On Sept. 21, 2009, the Court of Appeals issued an opinion reversing the lower court decision.  A subsequent petition for rehearing and en banc review was denied.  Defendants anticipate filing a petition for review with the U. S. Supreme Court on or before June 2010.

20

Table of Contents

Comer vs. Xcel Energy Inc. et al. — In 2006, Xcel Energy received notice of a purported class action lawsuit filed in U. S. District Court in 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 emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.”  Plaintiffs allege in support of their claim, several legal theories, including negligence and public and private nuisance and seek damages related to the loss resulting from the hurricane.  Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims.  In August 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds.  Plaintiffs filed a notice of appeal to the U. S. Court of Appeals for the Fifth Circuit.  On Oct. 16, 2009, the U. S. Court of Appeals for the Fifth Circuit reversed the district court decision, in part, concluding that the plaintiffs pleaded sufficient facts to overcome the constitutional challenges that formed the basis for dismissal by the district court.  A subsequent petition by defendants, including Xcel Energy, for en banc review was granted.  Oral arguments are expected to be presented to the Fifth Circuit panel on May 24, 2010.

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U. S. District Court for the Northern District of California against Xcel Energy and 23 other utilities, oil, gas and coal companies.  Plaintiffs claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village.  Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss on June 30, 2008.  On Oct. 15, 2009, the U. S. District Court dismissed the lawsuit on constitutional grounds.  On Nov. 5, 2009, plaintiffs filed a notice of appeal to the U. S. Court of Appeals for the Ninth Circuit.

Comanche Unit 3 CAA Lawsuit — On July 2, 2009, WildEarth Guardians (WEG) filed a lawsuit in the U. S. District Court in Colorado against PSCo alleging that PSCo violated the CAA by constructing Comanche Unit 3 without a final MACT determination from the Colorado Department of Public Health and Environment, Air Pollution Control Division (APCD).  PSCo disputes these claims and filed a motion to dismiss the suit.  Comanche Unit 3 was constructed with state-of-the-art emission controls and pursuant to a valid air permit issued by the APCD.  On Oct. 28, 2009, WEG filed a motion for a preliminary injunction, seeking to enjoin PSCo from constructing, modifying, or operating Comanche Unit 3 prior to receiving a final MACT determination.  PSCo strongly opposes the injunction.  Among other issues, PSCo believes that WEG has failed to establish a substantial likelihood of prevailing on the merits of the suit and that therefore there is no valid legal basis upon which an injunction should be issued.  The court has yet to rule on WEG’s motion and the group sought a temporary restraining order to stop Comanche Unit 3 from coming on-line.  The court denied WEG’s request for a temporary restraining order on Jan. 26, 2010.  On March 9, 2010, the court partially granted and partially denied PSCo’s motion to dismiss.  The court requested additional briefing on certain issues related to the MACT determination.  Briefing is expected to be finalized by May 6, 2010.

Employment, Tort and Commercial Litigation

Siewert vs. Xcel Energy — In 2004, plaintiffs, the owners and operators of a Minnesota dairy farm, brought an action in Minnesota state court 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 claim losses of approximately $7 million.  NSP-Minnesota denies all allegations.  In December 2008, the Court of Appeals issued a decision ordering dismissal of Plaintiffs’ claims for injunctive relief, but otherwise rejecting NSP-Minnesota’s contentions and ordering the matter remanded for trial.  The Minnesota Supreme Court subsequently granted NSP-Minnesota’s petition for further review and heard oral arguments on Dec. 2, 2009.  It is uncertain when the Minnesota Supreme Court will render a decision.

Qwest vs. Xcel Energy Inc. — In 2004, an employee of PSCo was seriously injured when a pole owned by Qwest malfunctioned. In September 2005, the employee commenced an action against Qwest in Colorado state court in Denver.  In April 2006, Qwest filed a third party complaint against PSCo based on terms in a joint pole use agreement between Qwest and PSCo.  In May 2007, the matter was tried and the jury found Qwest solely liable for the accident and this determination resulted in an award of damages in the amount of approximately $90 million.  In April 2009, the Colorado Court of Appeals affirmed the jury verdict insofar as it relates to claims asserted by Qwest against PSCo.  Qwest filed a petition for rehearing with the Colorado Supreme Court in June 2009.  On Feb. 22, 2010, the Colorado Supreme Court issued a ruling by which it will review the Court of Appeals’ decision as to the punitive damages issue and will not review the Court of Appeals’ decision as it relates to PSCo.

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 La Crosse, Wis.  In lieu of participating in discussions, in October 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.  In November 2003, NSP-Wisconsin commenced suit in Wisconsin state court against St. Paul Fire & Marine

21