UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of Act:      None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act. ý Yes or No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. o Yes or No ý

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act). ý Large accelerated filer  o Accelerated filer  o Non-accelerated filer

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). o Yes or No ý

As of June 30, 2005, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $7,843,601,587 and there were 402,357,588 shares of common stock outstanding.

As of February 21, 2006, there were 403,814,069 shares of common stock outstanding, $2.50 par value.

DOCUMENTS INCORPORATED BY REFERENCE

The Registrant’s Definitive Proxy Statement for its 2006 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

Index

PART I

Item 1 — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

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COMPANY OVERVIEW

Xcel Energy is a holding company, with subsidiaries engaged primarily in the utility business.  In 2005, Xcel Energy’s continuing operations included the activity of four wholly owned utility subsidiaries that serve electric and natural gas customers in 10 states. These utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utilities serve customers in portions of Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas and Wisconsin.  Along with WGI, an interstate natural gas pipeline company, these companies comprise our continuing regulated utility operations

Xcel Energy’s nonregulated subsidiaries in continuing operations include Eloigne and Planergy International, Inc.  Planergy International, Inc. closed and began selling a majority of its business operations in 2003 with all operations ceasing in 2004.

Discontinued utility operations include the activity of Viking, which was sold in January 2003; BMG, which was sold in October 2003; and Cheyenne, which was sold in January 2005.

In April 2005, Zachry Group, Inc. acquired all of the outstanding shares of UE, a nonregulated subsidiary.  In August 2005, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Quixx Corp., a former subsidiary of UE that partners in cogeneration projects that was not included in the sale of UE to Zachry.  As a result, Xcel Energy is reporting UE and Quixx as components of discontinued operations for all periods presented.

During 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Seren Innovations, Inc.   On Nov. 3, 2005, Xcel Energy completed the sale of Seren’s California assets to WaveDivision Holdings, LLC.  On Jan. 9, 2006, Xcel Energy completed the sale of Seren’s Minnesota assets to Charter Communications.

During 2003, Xcel Energy divested its ownership interest in NRG.  On May 14, 2003, NRG filed for bankruptcy to restructure their debt.  As a result of the reorganization, Xcel Energy relinquished its ownership interest in NRG.  Xcel Energy made payments of $752 million to NRG in 2004.  During 2003, the board of directors of Xcel Energy also approved management’s plan to exit certain businesses conducted by the nonregulated subsidiaries Xcel Energy International Inc. and e prime inc.  NRG, Xcel Energy International, e prime, Seren, UE and Quixx are accounted for as components of discontinued operations.

For more information regarding Xcel Energy’s discontinued operations, see Note 2 to the Consolidated Financial Statements.

Historically, Xcel Energy has been a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA).  As a registered holding company, Xcel Energy, its utility subsidiaries and certain of its non-utility subsidiaries have been subject to extensive regulation by the SEC under PUHCA with respect to numerous matters, including issuances and sales of securities, acquisitions and sales of certain utility properties, payments of dividends out of capital and surplus, and intra-system sales of certain non-power goods and services.  In addition, the PUHCA generally limited the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company.

On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (Energy Act), significantly changing many federal statutes and repealing PUHCA as of February 8, 2006.  As part of the repeal of PUHCA, FERC was given more authority over the merger and acquisition of public utilities and more authority over the books and records of public utilities.  Despite these increases in FERC’s authority, Xcel Energy believes that the repeal of PUHCA will lessen its regulatory burdens and give it more flexibility in the event it were to choose to expand its utility or non-utility businesses.

Besides repealing PUHCA, the Energy Act is also expected to have substantial long-term effects on energy markets, energy investment and regulation of public utilities and holding company systems by the FERC and DOE.  FERC and DOE are in various stages of rulemaking in implementing the Energy Act.  While the precise impact of these rulemakings cannot be determined at this time, Xcel Energy generally views the Energy Act as legislation that will enhance the utility industry going forward.

Xcel Energy was incorporated under the laws of Minnesota in 1909.  Xcel Energy’s executive offices are located at 800 Nicollet Mall, Minneapolis, Minn. 55402.  Its Web site address is www.xcelenergy.com.  Xcel Energy makes available, free of charge through its Web site, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC.  In addition,

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the Xcel Energy Guidelines on Corporate Governance and Code of Conduct also are available on its Web site.

NSP-Minnesota

NSP-Minnesota was incorporated in 2000 under the laws of Minnesota.  Prior to 2000, the regulated utility operations currently conducted by NSP-Minnesota were conducted by the legal entity now operating under the name Xcel Energy.  NSP-Minnesota is an operating utility engaged in the generation, purchase, transmission, distribution and sale of electricity in Minnesota, North Dakota and South Dakota.  The wholesale customers served by NSP-Minnesota comprised approximately X percent of the total Kwh sales in 2005.  NSP-Minnesota also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in Minnesota and North Dakota.  NSP-Minnesota provides electric utility service to approximately 1.3 million customers and gas utility service to approximately 0.5 million customers.

The electric production and transmission system of NSP-Minnesota is managed as an integrated system with that of NSP-Wisconsin, jointly referred to as the NSP System. The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin.  A FERC-approved agreement between the two companies, called the Interchange Agreement, provides for the sharing of all costs of generation and transmission facilities of the NSP System, including capital costs.

NSP-Minnesota owns the following direct subsidiaries: United Power and Land Co., which holds real estate; and NSP Nuclear Corp., which holds NSP-Minnesota’s interest in the NMC.  NSP Financing I, a former special purpose financing trust of NSP-Minnesota, was dissolved in September 2003.

NSP-Wisconsin

NSP-Wisconsin was incorporated in 1901 under the laws of Wisconsin.  NSP-Wisconsin is an operating utility engaged in the generation, transmission and distribution of electricity to approximately 242,000 customers in portions of northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan.  The wholesale customers served by NSP-Wisconsin comprised approximately 8 percent of NSP-Wisconsin’s total Kwh sales in 2005.  NSP-Wisconsin also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in the same service territory to approximately 98,000 customers.  See the discussion of the integrated management of the electric production and transmission system of NSP-Wisconsin under NSP-Minnesota, discussed previously.

NSP-Wisconsin owns the following direct subsidiaries: Chippewa and Flambeau Improvement Co., which operates hydro reservoirs; Clearwater Investments Inc., which owns interests in affordable housing; and NSP Lands, Inc., which holds real estate.

PSCo

PSCo was incorporated in 1924 under the laws of Colorado. PSCo is an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity.  PSCo also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas.  PSCo serves approximately 1.3 million electric customers and approximately 1.2 million natural gas customers in Colorado.  The wholesale customers served by PSCo comprised approximately 23 percent of PSCo’s total Kwh sales in 2005.

PSCo owns the following direct subsidiaries: 1480 Welton, Inc., which owns certain real estate interests for PSCo; PSRI, which owns and manages permanent life insurance policies on certain current and former employees; and Green and Clear Lakes Company, which owns water rights. PSCo also holds a controlling interest in several other relatively small ditch and water companies whose capital requirements are not significant.  PSCo Capital Trust I, a former special purpose financing trust of PSCo, was dissolved in December 2003.

SPS

SPS was incorporated in 1921 under the laws of New Mexico. SPS is an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity. SPS serves approximately 395,000 electric customers in portions of Texas, New Mexico, Oklahoma and Kansas. The wholesale customers served by SPS comprised approximately 38 percent of SPS’s total Kwh sales in 2005.  A major portion of SPS’ retail electric operating revenues is derived from operations in Texas.  In October 2005, SPS reached a definitive agreement to sell its delivery system operations in Oklahoma, Kansas and a small portion of Texas to Tri-County Electric Cooperative.  The transaction, subject to regulatory approvals, is expected to

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be completed in 2006.  Southwestern Public Service Capital I, a former special purpose financing trust of SPS, was dissolved in January 2004.

Other Regulated Subsidiaries

WGI was incorporated in 1990 under the laws of Colorado. WGI is a small interstate natural gas pipeline company engaged in transporting natural gas from the PSCo system near Chalk Bluffs, Colo., to the Cheyenne system near Cheyenne, Wyo.

See financial information regarding the segments of Xcel Energy’s business at Note 17 to the Consolidated Financial Statements.

ELECTRIC UTILITY OPERATIONS

Electric Utility Trends

Overview

Utility Industry Growth — Xcel Energy intends to focus on growing through investments in electric and natural gas rate base to meet growing customer demands and to maintain or increase reliability and quality of service to customers.  Xcel Energy will file rate cases with state and federal regulators to earn a return on its investments and recover costs of operations.

Utility Restructuring and Retail Competition — The structure of the utility industry has been subject to change.  Merger and acquisition activity has been significant as utilities combined to capture economies of scale or establish a strategic niche in preparing for the future.  Some states have implemented some form of retail electric utility competition.  Much of Texas has implemented retail competition, but it is presently limited to utilities within the Electric Reliability Council of Texas, which does not include SPS.  Under current law, SPS can file a plan to implement competition, subject to regulatory approval, in Texas on or after Jan. 1, 2007.  However, SPS has no plan to implement retail competition in its service area.  In 2002, NSP-Wisconsin began providing its Michigan electric customers with the opportunity to select an alternative electric energy provider.  To date, no NSP-Wisconsin customers have selected an alternative electric energy provider.

The retail electric business does face some competition as industrial and large commercial customers have some ability to own or operate facilities to generate their own electricity. In addition, customers may have the option of substituting other fuels, such as natural gas or steam/chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region.  While each of Xcel Energy’s Utility Subsidiaries face these challenges, these subsidiaries believe their rates are competitive with currently available alternatives.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electric energy sold at wholesale, hydro facility licensing, accounting practices and certain other activities of Xcel Energy’s Utility Subsidiaries.  State and local agencies have jurisdiction over many of Xcel Energy’s activities, including regulation of retail rates and environmental matters.

FERC Rules Implementing Energy Act - The Energy Act repealed PUHCA effective Feb. 8, 2006.  In addition, the Energy Act required the FERC to conduct several rulemakings to adopt new regulations to implement various aspects of the Energy Act.  Since Aug. 2005, the FERC has completed or initiated the proceedings to modify its regulations on a number of subjects, including:

•      Adopting new regulations to implement the Energy Act repeal of PUHCA by establishing rules for accounting procedures for holding company systems, including cost allocation rules for transactions between companies within a holding company system;

•      Adopting new regulations to implement changes to the FERC’s merger and asset transfer authority under Section 203 of the Federal Power Act;

•      Adopting new “market manipulation regulations” prohibiting any “manipulative or deceptive device or contrivance” in wholesale natural gas and electricity commodity and transportation or transmission markets and interpreting this standard in a manner consistent with Rule 10b-5 of the SEC; violations are subject to potential civil penalties of up to $1 million per day;

•      Adopting regulations to establish a national Electric Reliability Organization (ERO) to replace the voluntary North American Electric Reliability Council (NERC) structure, and requiring the ERO to establish mandatory reliability

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standards and imposition of financial or other penalties for violations of adopted standards; NERC is expected to apply to become designated as the ERO later in 2006;

•      Adopting rules to implement changes to the Public Regulatory Policy Act of 1978 (PURPA) to allow utility ownership of Qualifying Facilities (QFs) and strengthening the thermal energy requirements for entities seeking to be QFs;

•      Proposing rules that would allow a utility to seek to eliminate its mandatory QF power purchase obligation for utilities in organized wholesale energy markets;

•      Proposing rules to establish incentives for investment in new electric transmission infrastructure.

Xcel Energy cannot predict the ultimate impact the new regulations will have on its operations or financial results.

Market-Based Rate Authority — The FERC regulates the wholesale sale of electricity.  In order to obtain market-based rate authorization from the FERC, utilities are required to submit analyses demonstrating whether they have market power in the relevant markets.  Xcel Energy and its utility subsidiaries were previously granted market-based rate authority by the FERC.  However, the FERC has subsequently modified its standards making it more difficult for utilities to demonstrate that they do not have market power and thus more difficult to obtain market-based rate authority, particularly in their own service territories.

On Feb. 7, 2005, Xcel Energy on behalf of itself and the utility subsidiaries filed an updated market-power analysis that applied FERC’s new standards.  This analysis demonstrated that all of the Utility Subsidiaries, with the exception of PSCo, passed the pivotal supplier analysis in their own control areas and all adjacent markets, but that all failed the market share analysis in their own control areas, and in the case of NSP-Minnesota and NSP-Wisconsin, which jointly operate a single control area and accordingly are analyzed as one company, in certain adjacent markets.

In June 2005, the FERC initiated a proceeding to investigate PSCo’s and SPS’ market-based rate authority within their own control areas.  The refund effective date that has been set as part of that investigation for such sales is Aug. 12, 2005.  Because of the commencement of the MISO Day 2 market, and the FERC’s decision consistent with other precedent to analyze NSP-Minnesota and NSP-Wisconsin as part of that larger market, the FERC is not addressing NSP-Minnesota’s and NSP-Wisconsin’s market power in that investigation. The FERC did require that Xcel Energy make a compliance filing providing information, including information regarding the FERC’s affiliate abuse component of its market power analysis and the allegations regarding that component made by an intervenor within 30 days of the date of issuance of its order.  The latter compliance filing was submitted on July 5, 2005.

On Aug. 1, 2005, SPS and PSCo submitted a filing to withdraw their market-based rate authority with respect to sales within their control areas.  SPS and PSCo proposed to charge existing cost-based rates for sales into the SPS and PSCo control areas.  In October 2005, PSCo and SPS filed revised tariff sheets to reflect that limitation on their market-based rate authority.  Certain intervenors are still contending that the FERC must hold an investigation regarding SPS’ market power and the rates that SPS is proposing to charge where it has relinquished market-based rate authority.  The matter is pending before the FERC.

Electric Transmission Rate Regulation — The FERC also regulates the rates charged and terms and conditions for electric transmission services.  FERC policy encourages utilities to turn over the functional control over their electric transmission assets and the related responsibility for the sale of electric transmission services to an RTO.  NSP-Minnesota and NSP-Wisconsin are members of the MISO, which began RTO operations in early 2002.  SPS is a member of the SPP, which proposes to begin RTO operations on May 1, 2006.  SPS has been a member of SPP’s regional transmission tariff since 2001.  Each RTO separately files for regional transmission tariff rates for approval by FERC.  All members within that RTO are then subjected to those rates.  SPS has not yet filed for state regulatory authorization in New Mexico to transfer functional control of its transmission system to the SPP RTO.  PSCo is currently participating with other utilities in the development of an RTO.

Centralized Regional Wholesale Markets – FERC rules require RTO’s to operate centralized regional wholesale energy markets.  The FERC required the MISO to begin operation of a “Day 2” energy market on April 1, 2005.  MISO uses security constrained regional economic dispatch and congestion management using locational marginal pricing (LMP) and FTR’s.  The Day 2 market is intended to provide more efficient generation dispatch over the 15 state MISO region.

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NSP-Minnesota

Ratemaking Principles

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s operations are regulated by the MPUC, the NDPSC and the SDPUC within their respective states. The MPUC has regulatory authority over aspects of NSP-Minnesota’s financial activities, including security issuances, property transfers, mergers and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s electric resource plans for meeting customers’ future energy needs. The MPUC also certifies the need for generating plants greater than 50 MW and transmission lines greater than 100 KV.

The MPUC is also empowered to select and designate sites for new power plants with a capacity of 50 MW or more and wind energy conversion plants with a capacity of five MW or more. It also designates routes for electric transmission lines with a capacity of 100 KV or more. No power plant or transmission line may be constructed in Minnesota except on a site or route designated by the MPUC. The NDPSC and SDPUC have regulatory authority over the need for certain generating and transmission facilities, and the siting and routing of certain new generation and transmission facilities in North Dakota and South Dakota, respectively.

NSP-Minnesota is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce. NSP-Minnesota has received authorization from the FERC to make wholesale electric sales at market-based prices (see market-based rate authority discussion) and is a transmission-owner member of the MISO RTO.

Fuel, Purchased Energy and Conservation Cost Recovery Mechanisms — NSP-Minnesota’s retail electric rate schedules in Minnesota, North Dakota and South Dakota include a FCA that provides for monthly adjustments to billings and revenues for changes in prudently incurred cost of fuel, fuel related items and purchased energy.  NSP-Minnesota is permitted to recover these costs through FCA mechanisms individually approved by the regulators in each jurisdiction.  The FCA mechanisms allow NSP-Minnesota to bill customers for the cost of fuel and fuel related costs used to generate electricity at its plants and energy purchased from other suppliers.  With NSP-Minnesota’s participation in the MISO Day 2 market, questions have been raised regarding the inclusion of certain MISO charges in the FCA.  For further discussion, see NSP-Minnesota Pending and Recently Concluded Regulatory Proceedings – MPUC.  In general, capacity costs are not recovered through the FCA.  NSP-Minnesota’s electric wholesale customers also have a FCA provision in their contracts.

NSP-Minnesota is required by Minnesota law to spend a minimum of 2 percent of Minnesota electric revenue on conservation improvement programs.  These costs are recovered through an annual cost recovery mechanism for electric conservation and energy management program expenditures. NSP-Minnesota is required to request a new cost recovery level annually.

Performance-Based Regulation — In December 2003, the MPUC voted to approve NSP-Minnesota’s MERP proposal to convert two coal-fueled electric generating plants to natural gas, and to install advanced pollution control equipment at a third coal-fired plant.  All three plants are located in the Minneapolis - St. Paul metropolitan area. These improvements are expected to significantly reduce air emissions from these facilities, while increasing the capacity at system peak by 300 MW. The projects are expected to come on line between 2007 and 2009, at a cumulative investment of approximately $1 billion.  The MPUC approved a rate rider to recover prudent costs of the projects from Minnesota customers beginning Jan. 1, 2006, including a rate of return on the construction work in progress.  The MPUC approval has a sliding ROE scale based on actual construction cost compared with a target level of construction costs (based on an equity ratio of 48.5 percent and debt of 51.5 percent) to incentivize NSP-Minnesota to control construction costs.

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Pending and Recently Concluded Regulatory Proceedings - FERC

MISO Operations —NSP-Minnesota and NSP-Wisconsin are members of the MISO. The MISO is an RTO that provides regional transmission tariff administration services for electric transmission systems, including those of NSP-Minnesota and NSP-Wisconsin.  In 2002, NSP-Minnesota and NSP-Wisconsin received all required regulatory approvals to transfer functional control of their high voltage (100 KVand above) transmission systems to the MISO. The MISO membership grants MISO functional control over the operations of these facilities and the facilities of certain neighboring electric utilities.

On April 1, 2005, MISO initiated a regional wholesale energy market using LMP and FTR’s Day 2 market pursuant to its TEMT.  While it is anticipated the Day 2 market will provide efficiencies through region-wide generation dispatch and increased reliability, as well as long-term benefits through dispatch of power from the most cost-effective sources of generation or transmission, there are costs associated with the Day 2 market.  NSP-Minnesota and NSP-Wisconsin have requested recovery of these costs within their respective jurisdictions.  For further discussion, see Pending and Recently Concluded Regulatory Proceedings – MPUC.

Within MISO, an independent market monitor reviews market bids and prices to identify any unusual activity.  The FERC has notified Xcel Energy that it is investigating pricing and market-related issues.  Xcel Energy and other market participants continue to work with MISO, the independent market monitor and the FERC to resolve Day 2 market implementation issues such as dispatch methods and settlement calculation details.  Xcel Energy also intends to work with these parties to resolve any identified issues.

New business processes, systems and internal controls over financial reporting were planned and implemented by Xcel Energy and MISO during the second quarter of 2005 to conduct business within the MISO Day 2 market.  Xcel Energy continues to validate these changes and to review the energy costs and revenues determined by MISO.  Xcel Energy and other market participants have disputed certain transactions.

MISO Long Term Transmission Pricing - On Oct. 7, 2005, MISO filed proposed tariff revisions that would allow MISO to regionalize the cost of certain future high voltage transmission lines owned by specific transmission owners but constructed pursuant to the MISO transmission expansion plan.  The proposed tariffs reflect stakeholder input to MISO.  MISO proposed the tariff revisions to be effective on Feb. 4, 2006.  Xcel Energy generally supports the proposed tariff revisions, which should encourage transmission construction by regionalizing a share of the cost of projects providing regional benefits.  Comments on or protests to the proposed tariff revisions were filed at FERC in late 2005.  In February 2006, the FERC issued an order accepting the tariff revisions, subject to modifications and additional procedures.  Xcel Energy cannot predict the ultimate impact of the MISO tariff proposed at this time.

MISO/PJM SECA - On Nov. 18, 2004, FERC issued an order approving portions of a plan providing for continued use of “license plate” rates for the MISO/PJM region, but rejecting proposed transition payments to compensate transmission owners for reductions in transmission revenues.  FERC instead ordered the MISO and PJM to file a Seams Elimination Charge Adjustment (SECA) transition mechanism.  The replacement compliance filings were effective Dec. 1, 2004.  The FERC order eliminates any transition payments and the SECA filings instead provide for both revenues and payments that net to approximately $86,000 in revenues per month to NSP-Minnesota and NSP-Wisconsin in 2005.

Various parties sought rehearing of the Nov. 18, 2004 order and/or filed objections to the Nov. 24, 2004 SECA compliance filings.  On Feb. 10, 2005, the FERC issued an order accepting the SECA filings effective Dec. 1, 2004, subject to refund, and set the proposals for hearings.  The SECA proposals are now in hearings at the FERC.  Certain parties have proposed a regional average transition charge, which could shift costs to NSP-Minnesota and NSP-Wisconsin, effective Dec. 1, 2004.  Xcel Energy has opposed these regionalized approaches.  The final FERC decision is expected to be issued by the end of 2006.  Under the FERC orders, the SECA transition charges are set to expire Mar. 31, 2006.

Pending and Recently Concluded Regulatory Proceedings - 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, a projected common equity ratio to total capitalization of 51.7 percent and a projected electric rate base of $3.2 billion.  On Dec. 15, 2005, the MPUC authorized an interim rate increase of $147 million, subject to refund, which became effective on Jan. 1, 2006.  The anticipated procedural schedule is as follows:

•      March 2^nd – Intervenor Direct Testimony

•      March 30^th – Rebuttal Testimony

•      April 13^th – Surrebuttal Testimony

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•      April 20^th – April 28^th – Evidentiary Hearings

•      May 24^th – Initial Briefs

•      June 6^th – Reply Briefs

•      July 6^th – Administrative Law Judge Report

•      September 5^th – MPUC Order

Renewable Transmission Cost Recovery — In 2002, NSP-Minnesota filed for MPUC approval to establish an RCR adjustment mechanism to recover the costs of transmission investments incurred to deliver renewable energy resources.  The RCR adjustment mechanism provides for annual filings to set the RCR adjustment rates using updated transmission cost information.  The MPUC approved the RCR adjustment mechanism and the two-phase filing mechanism in April 2003.  In February 2004, the MPUC conditionally approved the initial Phase 1 facility eligibility determination filing.  NSP-Minnesota then filed for approval to recover annual additional transmission costs from May 2004 to December 2004, which were approximately $6 million. The request was approved and the RCR was implemented Dec. 1, 2004.  NSP-Minnesota collected approximately $0.2 million in 2004.  NSP-Minnesota submitted a filing in February 2005 to determine the eligibility of additional transmission projects and to establish the RCR factors for 2005, seeking recovery of $12.9 million of additional costs in 2005.  The MPUC approved revised factors by order dated Jan. 9, 2006, and NSP-Minnesota submitted its compliance filing in late January 2006 for rates to be effective Mar. 1, 2006.  In Oct. 2005, NSP-Minnesota revised the recoverable expense to $9.3 million, of which $5.4 million has been recovered. Because of the pending Minnesota rate case, the RCR rates in effect in 2006 will recover only the unrecovered 2005 costs of $3.9 million.  All 2006 costs are proposed to be recovered in the Minnesota electric rate case discussed above.

MISO Cost Recovery — On Dec. 18, 2004, NSP-Minnesota filed with the MPUC a petition to seek recovery of the Minnesota jurisdictional portion of all net costs associated with the implementation of the MISO Day 2 market through its FCA.  The MPUC issued an interim order in April 2005 allowing MISO Day 2 charges to be recovered through the NSP-Minnesota FCA mechanism. In December 2005, the MPUC issued a second interim order approving the recovery of certain MISO charges through the FCA mechanism but requiring that additional charges either be recovered as part of a general rate case or through an annual review process outside the fuel and purchased energy cost recovery mechanism, and requiring refunds of non-FCA costs.  The December 2005 MPUC order also suspended the refund obligation until such time as it could reconsider the matter.  On Feb. 9, 2006, the MPUC voted to reconsider its December 2005 order.  The MPUC on reconsideration determined that parties be directed to determine which charges are appropriately in the FCA and which are more appropriately established in base rates and report back to the MPUC in 60 days; to grant deferred accounting treatment for costs ultimately determined to be included in base rates for a period of 36 months, with recovery of deferred amounts to be reviewed in a general rate case; and that amounts collected to date through the FCA under the April and December 2005 interim orders are not subject to refund.  As a result, NSP-Minnesota expects to have the opportunity to recover (or seek to recover in a rate case) all of its MISO Day 2 costs.

In March 2005, the PSCW issued an interim order allowing NSP-Wisconsin deferred accounting treatment of MISO charges.  However, the PSCW staff issued an interpretive memorandum in October 2005 asserting that certain MISO costs may not be recovered through the interim fuel cost mechanism and may not be deferrable.  NSP-Wisconsin and the other Wisconsin utilities contested staff’s interpretation in their November comments to the PSCW.  To date, NSP-Wisconsin has deferred approximately $5.7 million of MISO Day 2 costs as a regulatory asset.

Xcel Energy also notified MISO that NSP-Minnesota and NSP-Wisconsin may seek to withdraw from MISO if rate recovery of Day 2 costs is not allowed.  Withdrawal would require FERC approval and could require Xcel Energy to pay a withdrawal fee.

In addition, in March 2005, NSP-Minnesota filed petitions similar to the December 2004 Minnesota filing with the NDPSC and the SDPUC proposing changes to allow recovery of the applicable North Dakota and South Dakota jurisdictional portions of the MISO Day 2 market costs.  The SDPUC approved the proposed tariff changes effective April 1, 2005, as requested.  The NDPSC granted interim recovery through the FCA beginning April 1, 2005, but similar to the decision of the MPUC, conditioned the relief as being subject to refund until the merits of the case are determined.  To date, the NDPSC has conducted no further proceedings regarding the NSP-Minnesota filing.

Energy Legislation — In 2005, the Minnesota Legislature passed and the Governor signed an Omnibus Energy Bill, effective July 1, 2005.  Among other things, the new law provides authority for the MPUC to approve rate rider recovery for transmission investments that have been approved through a certificate of need, the biennial transmission plan, or are associated with compliance with the state’s renewable energy objective.  The statute provides that the rate rider may include recovery of the revenue requirement associated with qualifying projects, including a current return on construction work in progress.  NSP-Minnesota is currently preparing a filing to the MPUC for approval of a new tariff to implement this statute.

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Capacity and Demand

Uninterrupted system peak demand for the NSP System’s electric utility for each of the last three years and the forecast for 2006, assuming normal weather, are listed below.

The peak demand for the NSP System typically occurs in the summer. The 2005 uninterrupted system peak demand for the NSP System occurred on June 23, 2005.

Energy Sources and Related Initiatives

NSP-Minnesota expects to use existing electric generating stations; purchases from other utilities, independent power producers and power marketers; demand-side management options; and phased expansion of existing generation at select power plants to meet its system capacity requirements.

Purchased Power — NSP-Minnesota has contractual arrangements to purchase power from other utilities and nonregulated energy suppliers. Capacity, typically measured in KW or MW, is the measure of the rate at which a particular generating source produces electricity. Energy, typically measured in Kwh or Mwh, is a measure of the amount of electricity produced from a particular generating source over a period of time. Long-term purchase power contracts typically require a periodic payment to secure the capacity from a particular generating source and a charge for the associated energy actually purchased from such generating source.

NSP-Minnesota also makes short-term firm and non-firm purchases to replace generation from company-owned units that are unavailable due to maintenance and unplanned outages, to provide the utility’s reserve obligation, to obtain energy at a lower cost than that which could be produced by other resource options, including company-owned generation and/or long-term purchase power contracts, and for various other operating requirements.

On Dec. 27, 2005, Excelsior Energy Inc. (Excelsior), an independent energy developer, filed a petition with the MPUC seeking to compel NSP-Minnesota to enter into a power purchase agreement related to its proposed integrated gasification, combined-cycle power plant (Mesaba project) that would be located in northern Minnesota.  The petition requested the MPUC to determine that the proposed purchase is in the public interest and that the technology proposed for the Mesaba Project, which Excelsior claims is a “clean energy technology” under Minnesota law, is or is likely to be a least-cost resource pursuant to Minnesota law.  NSP-Minnesota has not been provided a full, unredacted copy of the proposed power purchase agreement and has not entered into the power purchase agreement with Excelsior.  The petition seeks to compel NSP-Minnesota to purchase at least 13 percent of NSP-Minnesota’s electric energy provided to retail customers from the Mesaba Project, which Excelsior claims would require two units of its Mesaba Project each proposed at 603 MW.  Excelsior’s filing asserts much of its proposal is confidential under the MPUC’s rules, including the pricing and other economic terms.  NSP-Minnesota is seeking access to the confidential information.  The MPUC asked for comments on the process for the filing and comments on the ability to obtain information filed under confidential protection.  NSP-Minnesota has asked the MPUC to first resolve issues surrounding the confidential information, then to address legal issues surrounding the proposal and after resolution of those issues, to consider the proposal in light of its legal conclusions.

NSP System Resource Plan — On Nov. 1, 2004, NSP-Minnesota filed its 2004 resource plan with the MPUC.  The resource plan projects a need for an additional 3,100 MW of electricity resources during the next 15 years, based on an anticipated growth in demand of 1.61 percent annually, or approximately 170 MW per year, during the period.  The resource plan:

•      identifies the need for adding up to 1,125 MW of new base-load electricity generation by 2015;

•      recommends a new resource acquisition process that includes multiple options for consideration, including generation built by NSP-Minnesota;

•      recommends increasing energy-saving goals for demand-side energy management programs by nearly 17 percent;

•      recommends extending the operating licenses for the Prairie Island and Monticello nuclear plants by 20 years (on Jan. 18, 2005, NSP-Minnesota applied for a certificate of need in Minnesota for a dry spent-fuel storage facility at the Monticello plant, and plans to file an application with the federal government to extend the Monticello plant’s

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license and to make similar filings for the Prairie Island plant in 2008);

•      assumes nearly 1,700 MW of wind power with most developed on NSP-Minnesota’s system;

•      identifies the need for obtaining up to 550 MW of new power resources for peak usage times by 2015 depending on the amount and timing of any base-load resources acquired; and

•      cites the importance of ensuring that sufficient transmission resources are available to move electricity from generation sources.

On Aug. 1, 2005, the Minnesota Department of Commerce filed comments that Xcel Energy had overestimated its forecast and that there was no need for new resources until 2015.  Other parties filed various comments relating to the environmental impacts of the plan, the use of renewable fuels, the need to construct a 600 MW integrated gasification combined-cycle facility in Northern Minnesota, and NSP-Minnesota’s monitoring of the Northern Flood Agreement between the Province of Manitoba and various Canadian First Nations.

On Nov. 23, 2005, Xcel Energy filed updated analysis and replies with the MPUC.  The updated analysis supported Xcel Energy’s original forecast and identified upgrades to certain existing facilities that could provide cost-effective base load energy to Xcel Energy’s customers and defer the need for new base load until 2015.  The filing also detailed Xcel Energy’s examination of new base load options.  On the same day, the Minnesota Department of Commerce filed a proposal to select base load resources through a certificate of need process rather than a bidding process.  Xcel Energy expects the MPUC to make a final ruling on the Resource Plan and the bidding process in the first half of 2006.

NSP-Minnesota Transmission Certificates of Need — In December 2001, NSP-Minnesota proposed construction of various transmission system upgrades to provide transmission outlet capacity for up to 825 MW of renewable energy generation (wind and biomass) being constructed in southwest and western Minnesota.  In March 2003, the MPUC granted four certificates of need to NSP-Minnesota, thereby approving construction, subject to certain conditions. The initial projected cost of the transmission upgrades was approximately $160 million.  The MEQB granted a routing permit for the first major transmission facilities in the development program in 2004.  The remaining route permit proceedings were completed in 2005.  In 2003, the MPUC also approved an RCR adjustment that allows NSP-Minnesota to recover the revenue requirements associated with certain transmission investments associated with delivery of renewable energy resources through an automatic adjustment mechanism that started in 2004.  See the Pending and Recently Concluded Regulatory Proceedings — MPUC, Renewable Transmission Cost Recovery section for further discussion.

Purchased Transmission Services —NSP-Minnesota and NSP-Wisconsin have contractual arrangements with MISO to deliver power and energy to NSP System native load customers.  Point-to-point transmission services typically include a charge for the specific amount of transmission capacity being reserved. Network transmission services include a charge based on the transmission customer’s monthly peak demand.

Nuclear Power Operations and Waste Disposal - NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See additional discussion regarding the nuclear generating plants at Note 15 to the Consolidated Financial Statements.

Nuclear power plant operation produces gaseous, liquid and solid radioactive wastes. The discharge and handling of such wastes are controlled by federal regulation.  High-level radioactive wastes primarily include used nuclear fuel. Low-level radioactive waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in the plant.

Low-Level Radioactive Waste Disposal — Federal law places responsibility on each state for disposal of its low-level radioactive waste generated within its borders. Low-level radioactive waste from NSP-Minnesota’s Monticello and Prairie Island nuclear plants is currently disposed at the Barnwell facility located in South Carolina (all classes of low-level waste) and at the Clive facility located in Utah (class A low-level substance only). Chem Nuclear is the owner and operator of the Barnwell facility, which has been given authorization by South Carolina to accept low-level radioactive waste from states that are not a member of South Carolina’s state compact.  Envirocare, Inc. operates the Clive facility.  NSP-Minnesota has an annual contract with Barnwell, but is also able to utilize the Envirocare facility through various low-level waste processors.  NSP-Minnesota has low-level storage capacity available on-site at Prairie Island and Monticello that would allow both plants to continue to operate until the end of their current licensed lives, if off-site low-level disposal facilities were not available to NSP-Minnesota.

High-Level Radioactive Waste Disposal — The federal government has the responsibility to dispose of, or permanently store, domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to

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implement a program for nuclear high level waste management. This includes the siting, licensing, construction and operation of a repository for domestically produced spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent Federal storage or disposal facility. To date, the DOE has not accepted any of NSP-Minnesota’s spent nuclear fuel.  See Item 3 — Legal Proceedings and Note 15 to the Consolidated Financial Statements for further discussion of this matter.

NSP-Minnesota has on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear plants. In 1993, the Prairie Island plant was licensed by the federal NRC to store up to 48 casks of spent fuel at the plant. In 1994, the Minnesota Legislature adopted a limit on dry cask storage of 17 casks for the entire state.  On May 29, 2003, the Minnesota Legislature enacted revised legislation that will allow NSP-Minnesota to continue to operate the facility and store spent fuel there until its current licenses with the NRC expire in 2013 and 2014. The legislation transfers the primary authority concerning future spent-fuel storage issues from the state Legislature to the MPUC. It also allows for additional storage without the requirement of an affirmative vote from the state Legislature, if the NRC extends the licenses of the Prairie Island and Monticello plants and the MPUC grants a certificate of need for such additional storage. It is estimated that operation through the end of the current license will require 12 additional storage casks to be stored at the plant, for a total of 29 casks.  As of Dec. 31, 2005, there were 20 casks loaded and stored at the Prairie Island plant. See Note 15 in the Consolidated Financial Statements for further discussion of the matter.

Visual Inspections — Required visual inspections have been performed on the Prairie Island Unit 2 upper and lower reactor vessel heads, and the Unit 1 upper head. Reactor vessel heads for both units were found to be in compliance with all NRC requirements. The reactor vessel upper head for Prairie Island Unit 2 was replaced during the 2005 refueling outage, and Xcel Energy expects to replace the reactor vessel upper head for Prairie Island Unit 1 in early 2006.

Private Fuel Storage (PFS) — NSP-Minnesota is part of a consortium of private parties working to establish a private facility for interim storage of spent nuclear fuel. In 1997, PFS filed a license application with the NRC for a temporary storage site for spent nuclear fuel on the Skull Valley Indian Reservation in Utah. The NRC license review process includes formal evidentiary hearings before the ASLB and opportunities for public input. On Sept. 9, 2005, the NRC Commissioners directed the NRC staff to issue the license for PFS, ending the 8-year effort to gain a license for the site.  In December 2005, the U.S. Supreme Court denied Utah’s petition for a writ of certiorari to hear an appeal of a lower court’s ruling on a series of state statutes aimed at blocking the storage and transportation of spent fuel to PFS. Also in December 2005, NSP-Minnesota forwarded a letter to Senator Hatch (UT) indicating that it would hold in abeyance future investments in the construction of PFS as long as there is apparent and continuing progress in federally sponsored initiatives for storage, reuse, and/or disposal for the nation’s spent nuclear fuel.

Prairie Island Steam Generator Replacement — In the fall of 2004, NSP-Minnesota spent approximately $132 million to successfully replace the Prairie Island Unit 1 steam generators.  The Unit 2 steam generators have not yet been replaced, but received the required inspections during the scheduled 2005 outage. Based on current rates of degradation and available repair processes, NSP-Minnesota plans to replace these steam generators in the 2013 regular refueling outage. Due to the potential shortages in the world markets for materials and shop capabilities, NSP-Minnesota expects to begin the approval process in 2006 for long-lead time materials.

NSP-Minnesota Nuclear Plant Re-licensing— Monticello’s current 40-year license expires in 2010, and Prairie Island’s licenses for its two units expire in 2013 and 2014.  In March 2005, NSP-Minnesota filed its application with the NRC for an operating license extension for Monticello of up to 20 years.  NSP-Minnesota filed its application with the MPUC for Monticello in January 2005 seeking a certificate of need for dry spent fuel storage. Decisions by both the federal and state agencies regarding Monticello re-licensing are expected in early 2007. Prairie Island has initiated the necessary plant assessments and aging analysis to support submittal of similar applications to the NRC and Minnesota, currently planned for submittal in early 2008.

Nuclear Management Co. (NMC) — During 1999, NSP-Minnesota, Wisconsin Electric Power Co., Wisconsin Public Service Corporation (WPS) and Alliant Energy Corp. established NMC. The Consumers Power subsidiary of CMS Energy Corp. joined the NMC during 2000.

NMC manages the operations and maintenance at the plants, and is responsible for physical security. NMC’s responsibilities also include oversight of on-site dry storage facilities for used nuclear fuel at the Prairie Island nuclear plant. Utility plant owners, including NSP-Minnesota, continue to own the plants, control all energy produced by the plants, and retain responsibility for nuclear liability insurance and decommissioning costs.

In 2005 and 2006, as a result of selling their nuclear plants, WPS and Alliant Energy ended their participation in NMC.  In December 2005, Consumer Power announced its intent to sell its nuclear plant, which will leave NSP-Minnesota and Wisconsin Electric Power Co. as the remaining members of the NMC, with a combined total of 3 sites and 5 reactors. NMC

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is in the process of identifying and marketing its services to other potential nuclear utility candidates to replace the departing members.

For further discussion of nuclear issues, see Notes 14 and 15 to the Consolidated Financial Statements.

Fuel Supply and Costs

The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels during such years.

* Includes refuse-derived fuel and wood

See additional discussion of fuel supply and costs under Factors Affecting Results of Continuing Operations in Management’s Discussion and Analysis under Item 7.

Fuel Sources — Coal inventory levels may vary widely among plants.  However, the NSP System normally maintains no less than 30 days of coal inventory at each plant site.  Estimated coal requirements at NSP-Minnesota and NSP-Wisconsin’s major coal-fired generating plants are approximately 13.3 million tons per year. NSP-Minnesota and NSP-Wisconsin have long-term contracts providing for the delivery of up to 99 percent of 2006 coal requirements. Coal delivery may be subject to short-term interruptions or reductions due to transportation problems, weather, and availability of equipment.  See Management’s Discussion and Analysis for further discussion of coal delivery disruptions.

NSP-Minnesota and NSP-Wisconsin expect that all of the coal burned in 2006 will have an average sulfur content of less than 0.75 percent.  The NSP System has contracts for a maximum of 35.8 million tons of low-sulfur coal for the next 3 years.  The contracts are with 1 Montana coal supplier, 3 Wyoming suppliers and 1 Minnesota oil refinery, with expiration dates in 2006 and 2007.

To operate NSP-Minnesota’s nuclear generating plants, NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication. The contract strategy involves a portfolio of spot purchases and medium- and long-term contracts for uranium, conversion and enrichment.

•      Current nuclear fuel supply contracts cover 100 percent of uranium requirements through 2006 and 91.8 percent of the 2007 requirements with no coverage of requirements for 2008 and beyond. Contracts with additional uranium concentrates suppliers are currently in various stages of negotiations that are expected to provide a portion of the requirements through 2016.

•      Current contracts for conversion services requirements cover 100 percent of the requirements for 2006 and 53 percent for 2007 with no current coverage of requirements for 2011 and beyond. A contract with an additional conversion services supplier is nearing completion that is expected to provide additional coverage for 2007 through 2011.

•      Current enrichment services contracts cover 100 percent of the 2006 requirements. Approximately 30 percent of the 2007 through 2010 requirements are currently covered with no coverage of requirements for 2011 and beyond. These contracts expire at varying times between 2006 and 2010. Contracts with additional enrichment services suppliers are currently in various stages of negotiation that are expected to supply additional coverage from 2007 through 2010.

•      Fuel fabrication for Monticello is covered through 2010.  Fuel fabrication is 100 percent committed for Prairie Island Unit 1 through 2006 and Prairie Island Unit 2 is covered for the 2006 fuel fabrication services under an amendment signed in 2005. NSP-Minnesota and NMC are currently in negotiations with Westinghouse to pursue fuel fabrication for Prairie Island plant needs beyond the current fuel contracts.

NSP-Minnesota expects sufficient uranium, conversion and enrichment to be available for the total fuel requirements of its nuclear generating plants. Contracts for additional uranium and enrichment services are currently being negotiated that would provide additional supply requirements through 2016 for uranium and 2010 for enrichment services.

The NSP System uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers.  Natural gas supplies for power plants are procured under short-, intermediate- and long-term contracts which expire in various years from 2006 through 2027 in order to provide an adequate supply of fuel.  Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery.  At Dec. 31, 2005, NSP-Minnesota’s commitments related to these contracts were approximately $127 million.  The NSP System has current fuel oil inventory adequate to meet anticipated 2006 requirements and also has access to the spot market to buy more oil, if needed.

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Commodity Marketing Operations

NSP-Minnesota conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. Participation in short-term wholesale energy markets provides market intelligence and information that supports the energy management of NSP-Minnesota.  NSP-Minnesota uses physical and financial instruments to minimize commodity price and credit risk and hedge supplies and purchases. Engaging in short-term sales and purchase commitments results in an efficient use of our plants and the capturing of additional margins from non-traditional customers. NSP-Minnesota also uses these marketing operations to capture arbitrage opportunities created by regional pricing differentials, supply and demand imbalances and changes in fuel prices.  See additional discussion under Item 7A — Quantitative and Qualitative Disclosures About Market Risk.

NSP-Wisconsin

Ratemaking Principles

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Wisconsin’s operations are regulated by the PSCW and the MPSC, within their respective states.  In addition, each of the state commissions certifies the need for new generating plants and electric transmission lines to be located within the respective states before the facilities may be sited and built.  NSP-Wisconsin is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce. NSP-Wisconsin has received authorization from the FERC to make wholesale electric sales at market-based prices (see market-based rate authority discussion).

The PSCW has a biennial base-rate filing requirement.  By June of each odd-numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January. The filing procedure and review generally allow the PSCW sufficient time to issue an order and implement new base rates effective with the start of the test year.

Fuel and Purchased Energy Cost Recovery Mechanisms — NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers.  Instead, it has a procedure that compares actual monthly and anticipated annual fuel costs with those costs that were included in the latest retail electric rates. If the comparison results in a difference of 2 percent above base rates or 0.5 percent below, the PSCW may hold hearings limited to fuel costs and revise rates upward or downward. Any revised rates would remain in effect until the next rate change. The adjustment approved is calculated on an annual basis, but applied prospectively.  NSP-Wisconsin’s wholesale electric rate schedules provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy.

NSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, which are based on 12-month projections.  After each 12-month period, a reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period.

Pending and Recently Concluded Regulatory Proceedings - FERC

MISO — See the discussion of the MISO activity under NSP-Minnesota Pending and Recently Concluded Regulatory Proceedings.

Pending and Recently Concluded Regulatory Proceedings - PSCW

MISO Cost Recovery - On Mar. 29, 2005, NSP-Wisconsin received an order from the PSCW granting its request to defer the costs and benefits attributable to the start-up of the MISO Day 2 energy market.  NSP-Wisconsin also received an order granting its request to record energy market transactions on a net basis. The netting of transactions is consistent with the approach envisioned by the FERC in approving the transmission and energy markets tariff and is consistent with generally accepted accounting principles.  On Sept. 22, 2005, the PSCW opened an investigation to obtain information from interested persons related to MISO policy development that is beneficial to ratepayers and that protects the public interest.  On Oct. 18, 2005, the PSCW solicited comments on the PSCW staff proposal regarding rate and accounting treatment of MISO revenues and costs, as well as a request to escrow MISO Day 2 energy market costs until 2008.  On Nov. 17, 2005, NSP-Wisconsin and other Wisconsin utilities filed comments on the PSCW staff proposal and clarified the utilities’ position on their interpretation of the previously granted deferral order.  NSP-Wisconsin will continue to work with the PSCW and other utilities to address the longer-term issue related to MISO policies.

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NSP-Wisconsin 2005 Fuel Cost Recovery - On April 22, 2005, NSP-Wisconsin filed an application with the PSCW to increase electric rates by $10 million, or 2.7 percent, annually to provide for recovery of forecasted increased costs of fuel and purchased power over the balance of 2005.  The March 2005 actual fuel costs were approximately 13 percent higher than authorized recovery in current base rates, and the forecast for the remainder of 2005 showed costs outside the previously established annual range by 9.6 percent.  On May 18, 2005, the PSCW issued an order approving interim rates at the level requested, effective May 19, 2005.  This rate increase generated an estimated $6.5 million in additional revenue for NSP-Wisconsin in 2005.  Under the provisions of the Wisconsin fuel rules, any difference between interim rates and final rates is subject to refund.  On Sept. 28, 2005, the PSCW issued a final order approving an increase of $11.6 million, or 3.1 percent annually.  Because the final rates were slightly higher than interim rates authorized in May 2005, no refund was necessary.  With an effective date of Oct. 1, 2005, final rates collected approximately $0.4 million in incremental revenue, as compared to interim rates, over the last three months of 2005.

On Oct. 14, 2005, NSP-Wisconsin filed an application with the PSCW to increase the amount of the authorized fuel and purchased power surcharge by $8.9 million or 2.3 percent on an annual basis.  This additional request was due to dramatic increases in the cost of natural gas and purchased power since the surcharge amount was set in mid-August.  September 2005 actual fuel costs were approximately 38 percent higher than authorized recovery in current rates, and the forecast for the remainder of 2005 showed costs outside the annual range by 7.5 percent.  A PSCW order authorizing an increase in the amount of the surcharge on an interim basis, subject to refund, was issued Nov. 10, 2005, and NSP-Wisconsin collected approximately $1.3 million in additional revenue over the remainder of 2005.  The surcharge was discontinued with the implementation of new 2006 base rates, which went into effect Jan. 9, 2006.  A final hearing in the 2005 fuel surcharge case was held Feb. 10, 2006, to determine whether any refund of interim rates is necessary.  NSP-Wisconsin and PSCW staff both filed testimony indicating that actual fuel costs for the period in question exceeded levels assumed in setting interim rates, and no refund is necessary.  A final PSCW decision is expected in the first quarter of 2006.

NSP-Wisconsin 2006 General Rate Case – In 2005, NSP-Wisconsin, requested an electric revenue increase of $58.3 million and a natural gas revenue increase of $8.1 million, based on a 2006 test year, an 11.9 percent return on equity and a common equity ratio of 56.32 percent.  On Jan. 5, 2006, the PSCW approved an electric revenue increase of $43.4 million and a natural gas revenue increase of $3.9 million, based on an 11.0 percent return on equity and a 54-percent common equity ratio target.  The new rates were effective Jan. 9, 2006.  The order authorized the deferral of an additional $6.5 million in costs related to nuclear decommissioning and manufactured gas plant site clean up for recovery in the next rate case.  The order also prohibits NSP-Wisconsin from paying dividends above $42.7 million, if its actual calendar year average common equity ratio is or will fall below 54.03 percent.  It also imposes an asymmetrical electric fuel clause bandwidth of positive 2 percent to negative 0.5 percent outside of which NSP-Wisconsin would be permitted to request or be required to change rates.

Capacity and Demand

NSP-Wisconsin operates an integrated system with NSP-Minnesota.  See discussion of the system capacity and demand under NSP-Minnesota Capacity and Demand discussed previously.

Energy Sources and Related Initiatives

NSP-Wisconsin operates an integrated system with NSP-Minnesota.  See a discussion of the system energy sources under NSP-Minnesota Energy Sources and Related Initiatives discussed previously.

Fuel Supply and Costs

NSP-Wisconsin operates an integrated system with NSP-Minnesota.  See a discussion of the system energy sources under NSP-Minnesota Fuel Supply and Costs discussed previously.

PSCo

Ratemaking Principles

Summary of Regulatory Agencies and Areas of Jurisdiction — PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities.  PSCo is regulated by the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce.

Fuel, Purchased Energy and Conservation Cost Recovery Mechanisms — PSCo has several retail adjustment clauses that recover fuel, purchased energy and resource costs:

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•      Electric Commodity Adjustment (ECA) — The ECA, effective Jan. 1, 2004, is an incentive adjustment mechanism that compares actual fuel and purchased energy expense in a calendar year to a benchmark formula. The ECA also provides for an $11.25 million cap on any cost sharing over or under an allowed ECA formula rate.  The formula rate is revised annually and collected or refunded in the following year, if necessary.  The current ECA mechanism will expire Jan. 1, 2007.

•      Purchased Capacity Cost Adjustment (PCCA) — The PCCA, which became effective June 1, 2004, allows for recovery of purchased capacity payments to certain power suppliers under specifically identified power purchase agreements that are not included in the determination of PSCo’s base electric rates or other recovery mechanisms.  The PCCA will expire on Dec. 31, 2006.  Purchased capacity costs both from contracts included within the PCCA and from contracts not included within the PCCA are expected to be eligible for recovery through base rates, when PSCo files its next general rate case.

•      Steam Cost Adjustment (SCA) — The SCA allows PSCo to recover the difference between its actual cost of fuel and the amount of these costs recovered under its base steam service rates. The SCA rate is revised at least annually to coincide with changes in fuel costs.

•      Air-Quality Improvement Rider (AQIR) — The AQIR recovers, over a 15-year period, the incremental cost (including fuel and purchased energy) incurred by PSCo as a result of a voluntary plan to reduce emissions and improve air quality in the Denver metro area.

•      Demand-Side Management Cost Adjustment (DSMCA) — The DSMCA clause currently permits PSCo to recover DSM costs over five years while non-labor incremental expenses and carrying costs associated with deferred DSM costs are recovered on an annual basis. PSCo also has a low-income energy assistance program. The costs of this energy conservation and weatherization program for low-income customers are recovered through the DSMCA.

PSCo recovers fuel and purchased energy costs from its wholesale customers through a fuel cost adjustment clause accepted for filing by the FERC.

Performance-Based Regulation and Quality of Service Requirements — PSCo currently operates under an electric and natural gas PBRP.  The major components of this regulatory plan include:

•      an annual electric earnings test for 2004 through 2006 with the sharing between customers and shareholders of earnings in excess of a return on equity for electric operations of 10.75 percent;

•      an electric QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to electric reliability and customer service through 2006; and

•      a natural gas QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to natural gas leak repair time and customer service through 2007.

PSCo regularly monitors and records as necessary an estimated customer refund obligation under the PBRP. In April of each year following the measurement period, PSCo files its proposed rate adjustment under the PBRP. The CPUC conducts proceedings to review and approve these rate adjustments annually.

•      In 2003, PSCo did not achieve the performance targets for the QSP electric service unavailability measure or the customer complaint measure.  Targets were met for the natural gas QSP.  There was no sharing of earnings for 2003, as PSCo established new rates in its general rate case.

•      In 2004, PSCo did not earn a return on equity in excess of 10.75 percent, so no refund liability was recorded.  PSCo did not achieve the 2004 performance targets for the electric service unavailability measure, creating a bill credit obligation for 2004 and increasing the maximum bill credit obligation for subsequent years’ performance.  Targets were met for the natural gas QSP.

•      In 2005, PSCo does not anticipate earning a return on equity in excess of 10.75 percent and did not record a refund liability.  QSP results will be filed with the CPUC in April 2006.  An estimated customer refund obligation under the electric QSP plan was recorded in 2005 related to the electric service unavailability measure.  No refund under the natural gas QSP is anticipated. See further discussion of the QSP below.

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Pending and Recently Concluded Regulatory Proceedings - FERC

PSCo and SPS FERC Transmission Rate Case — On Sept. 2, 2004, Xcel Energy filed on behalf of PSCo and SPS an application to increase wholesale transmission service and ancillary service rates within the Xcel Energy joint open access transmission tariff (OATT).  PSCo and SPS requested an increase in annual transmission service and ancillary services revenues of $6.1 million.  As a result of a settlement with certain PSCo wholesale power customers in 2003, their power sales rates would be reduced by $1.4 million.  The net increase in annual revenues proposed was $4.7 million, of which $3.0 million is attributable to PSCo.  The FERC suspended the filing and delayed the effective date of the proposed increase to June 1, 2005.  The interim rates went into effect on June 1, 2005, subject to refund.  On Feb. 6, 2006, the parties in the proceeding submitted an uncontested offer of settlement that contains a formula rate for PSCo, a 10.5 percent rate of return on common equity, and the phased inclusion of PSCo’s 345 KV tie line costs in wholesale transmission service rates.  The settlement results in a $1.6 million rate increase for PSCo effective June 2005.  The offer of settlement is pending FERC approval.

California Refund Proceeding — A number of proceedings are pending before the FERC relating to the price of sales into the California electricity markets from May 1, 2000 through June 20, 2001.  PSCo supplied energy to these markets during this period and has been an active participant in the proceedings.  In September 2005, PSCo reached an agreement with respect to these proceedings with a group of California entities including: San Diego Gas & Electric Company, Pacific Gas and Electric Company, Southern California Edison Company, the California Department of Water Resources, the California Electricity Oversight Board, the California Public Utilities Commission and the California Attorney General.  In December 2005, the FERC approved the settlement without condition for the period of Jan. 1, 2000 through June 20, 2001.  PSCo will pay approximately $5.5 million in cash and assign $1.8 million in accounts receivable from the California Independent System Operator and the California Power Exchange to the settling participants. In 2004, PSCo reserved approximately $7 million related to this proceeding.  The settlement, which includes no acknowledgment of wrongdoing by PSCo, avoids further costly litigation and resolves all claims by PSCo against the settling participants and by the settling participants against PSCo.  While accounting for approximately 90 percent of purchases in the California markets, the California utilities were not the only purchasers in those markets.  However, the settlement makes provision for other purchasers to opt into the settlement.  We do not expect a material financial impact as resolution is reached with the non-settling parties.

Pacific Northwest FERC Refund Proceeding — In July 2001, the FERC ordered a preliminary hearing to determine whether there may have been unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for the period Dec. 25, 2000 through June 20, 2001. PSCo supplied energy to the Pacific Northwest markets during this period and has been an active participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered. Subsequent to the ruling the FERC has allowed the parties to request additional evidence regarding the use of certain strategies and how they may have impacted the markets in the Pacific Northwest markets. For the referenced period, parties have claimed that the total amount of transactions with PSCo subject to refund are $34 million.

On June 25, 2003, the FERC issued an order terminating the proceeding without ordering further proceedings.  On Nov. 10, 2003, in response to requests for rehearing, FERC reaffirmed this ruling to terminate the proceeding without refunds.  Certain purchasers have filed appeals of the FERC’s orders in this proceeding.

FERC OMOI Compliance Audit — On October 28, 2004, the OMOI sent a letter to Xcel Energy stating that OMOI had initiated a routine audit of PSCo compliance with various FERC regulations, including PSCo’s OATT, FERC’s Order No. 889 standards of conduct rules and PSCo’s code of conduct for transactions in power and non-power goods with affiliates with market-based rates.  Similar compliance audits of other utilities have resulted in compliance orders and, in certain cases, civil penalties.  On November 28, 2005, FERC issued an order approving an audit report that recommended certain operational changes but imposed no civil penalties.

Pending and Recently Concluded Regulatory Proceedings - CPUC

Tie Line Cost Recovery - On Sept. 20, 2001, the CPUC ruled that only 50 percent of the total cost of the high voltage direct current (HVDC) converter constructed by PSCo in Lamar, Colorado would be allowed in rate base.  This facility is part of the 345 KV tie line transmission facilities connecting the PSCo and SPS systems.  The CPUC decision resulted in a reduction of potential PSCo rate base of approximately $16.7 million.  On April 7, 2005, PSCo filed an application with the CPUC proposing a mechanism that would leave half of the HVDC facility as a non-rate-base asset, but that would generate revenue

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to recover the cost of the non-rate-base asset on a pay-as-you-go basis.  The proposal would involve allocating half of any energy or fuel cost savings derived from buying electricity through the tie line or making sales through the tie line.  Alternatively, PSCo stated that it would not object to the entire HVDC facility being placed in rate base.  A hearing examiner for the CPUC issued a recommended decision on Nov. 16, 2005, that reasoned that 100 percent of the HVDC converter be placed in rate base.  The CPUC acted on the recommended decision in February 2006 with generally favorable results.

Quality of Service Plan — The PSCo QSP provides for bill credits to Colorado retail customers, if PSCo does not achieve certain operational performance targets. During the second quarter of 2005, PSCo filed its calendar year 2004 operating performance results for electric service unavailability, phone response time, customer complaints, accurate meter reading and natural gas leak repair time measures.  PSCo did not achieve the 2004 performance targets for the electric service unavailability measure.  The CPUC staff and the OCC disputed the performance results.  The parties agreed PSCo did not achieve the 2004 performance targets for the electric service unavailability measure as filed, creating a bill credit obligation for 2004 of $5.6 million.  Additionally, the agreement provides that PSCo will invest an additional $11 million in 2006 toward improving reliability, and PSCo will not be required to pay any bill credits that may be owed for 2006 performance results for electric service unavailability.  For 2005, PSCo has evaluated its performance under the QSP and has recorded a liability of $13.6 million.  Under the electric QSP, the estimated maximum potential bill credit obligation for calendar 2005 performance is approximately $16.8 million, assuming none of the performance targets are met.  The maximum potential bill credit obligation for the same period related to permanent natural gas leak repair and natural gas meter reading errors is approximately $1.6 million.

Capacity and Demand

Uninterrupted system peak demand for PSCo’s electric utility for each of the last three years and the forecast for 2006, assuming normal weather, are listed below.

The peak demand for PSCo’s system typically occurs in the summer.  The 2005 uninterrupted system peak demand for PSCo occurred on July 21, 2005.

Energy Sources and Related Transmission Initiatives

PSCo expects to meet its system capacity requirements through existing electric generating stations; purchases from other utilities, independent power producers and power marketers; demand-side management options and phased expansion of existing generation at select power plants.

Purchased Power — PSCo has contractual arrangements to purchase power from other utilities and nonregulated energy suppliers.  Capacity, typically measured in KW or MW, is the measure of the rate at which a particular generating source produces electricity.  Energy, typically measured in Kwh or Mwh, is a measure of the amount of electricity produced from a particular generating source over a period of time. Long-term purchase power contracts typically require a periodic payment to secure the capacity from a particular generating source and a charge for the associated energy actually purchased from such generating source.

PSCo also makes short-term firm and non-firm purchases to replace generation from company-owned units that are unavailable due to maintenance and unplanned outages, to provide the utility’s reserve obligation, to obtain energy at a lower cost than that which could be produced by other resource options, including company-owned generation and/or long-term purchase power contracts, and for various other operating requirements.

PSCo Resource Plan — PSCo estimates it will purchase approximately 36 percent of its total electric system energy needs for 2006 and generate the remainder with PSCo-owned resources.  Additional capacity has been secured under contract making additional energy auditable for purchase, if required. PSCo currently has under contract or through owned generation, the resources necessary to meet its anticipated 2006 load obligation.

On April 30, 2004, PSCo filed a least-cost resource plan (LCP) with the CPUC.  PSCo’s plan showed a need to provide for approximately 3,600 MW of additional generation capacity through 2013 to meet load growth and replace expiring power purchase contracts. The LCP proposed to meet these resource needs through a combination of utility built generation, DSM, and power purchases.

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On Dec. 17, 2004, the CPUC approved a settlement agreement between PSCo and intervening parties concerning the LCP.  The CPUC approved PSCo’s plan to construct a 750-MW pulverized coal-fired unit at the existing Comanche power station located near Pueblo, Colo.; transfer up to 250 MW of capacity ownership from the 750-MW unit to Intermountain Rural Electric Association and Holy Cross Energy; and install additional emission control equipment on the two existing Comanche station units.  PSCo has completed permitting the 750 MW Comanche 3 unit and began construction of the facility in December 2005. In the approved settlement, PSCo also agreed to invest in additional demand-side management and fund environmental programs in Pueblo, Colo.

The approved settlement contains a confidential construction cost cap for the Comanche 3 project (i.e., the new unit and the emission controls on existing units 1 and 2) and a regulatory plan that authorizes PSCo to increase the equity component of its capital structure up to 60 percent in its 2006 rate case to offset the debt equivalent value of PSCo’s existing power purchase contracts and to otherwise improve PSCo’s financial strength.  Depending upon PSCo’s senior unsecured debt rating during the time of PSCo general rate cases, the approved settlement permits PSCo to include various amounts of construction work in progress that are associated with the Comanche 3 project in rate base without an offset for allowance for funds used during construction.

PSCo has signed agreements with IREA that define the respective rights and obligations of PSCo and IREA in the transfer of capacity ownership in the Comanche 3 unit.  PSCo continues to discuss the possibility of partnership arrangements with Holy Cross Energy.

PSCo has received the following permits or authorizations for construction and operation of Comanche 3:

•      Final air quality permits (received July 5, 2005);

•      A long-term water supply contract with the Pueblo Board of Water Works (received July 19, 2005);

•      Pueblo City Council approval to annex the Comanche plant into the city (received Sept. 12, 2005) and

•      Use by Special Review permit for onsite disposal of ash over a 50-year period (received Sept. 27, 2005).

The settlement agreement also called for PSCo to acquire the remaining resource needs through an all-source competitive bidding process.  On Feb. 24, 2005, in conjunction with the approved LCP, PSCo released an All-Source solicitation for new supply and demand-side resources.  In May 2005, PSCo received proposals for over 11,000 MW of firm capacity, nearly 4,600 MW of nameplate wind capacity, and almost 900 MW of demand-side management programs.  On Dec. 28, 2005 PSCo filed a report with the CPUC detailing the bids received, the bid evaluation process, and the winning bids. PSCo selected bids for approximately 30 MW of DSM resources, approximately 1300 MW of gas-fired generation resources and approximately 775 MW of wind generation resources.  These bids, together with Comanche 3, and the additional DSM agreed to in the LCP settlement agreement, are expected to meet PSCo’s resource needs through 2012.

Renewable Portfolio Standards — In November 2004, an amendment to the Colorado statutes was passed by referendum requiring implementation of a renewable energy portfolio standard for electric service.  The law requires PSCo to generate, or cause to be generated, a certain level of electricity from eligible renewable resources.  Generation of electricity from renewable resources, particularly solar energy, may be a higher-cost alternative to traditional fuels, such as coal and natural gas.  These incremental costs are expected to be recovered from customers.  On March 29, 2005, the CPUC initiated a proceeding and held various hearings to determine the rules and regulations required to implement the renewable portfolio standard.  The CPUC determined that compliance with the renewable energy portfolio standard should be measured through the acquisition of renewable energy credits either with or without the accompanying renewable energy; that the utility purchaser owns the renewable energy credits associated with existing contracts where the power purchase agreement is silent on this issue; that Colorado utilities should be required to file implementation plans, thereby rejecting the proposal to use an independent plan administrator; and the methods utilities should use for determining the budget available for renewable resources.  The CPUC issued proposed rules on Jan. 27, 2006.  Final rules are expected to become effective by the end of the first quarter 2006.

Renewable Energy Standard Adjustment (RESA) – On December 1, 2005, PSCo filed with the CPUC to implement a new 1 percent rider that would apply to each customer’s total electric bill, providing approximately $22 million in annual revenue.  The revenues collected under the RESA will be used to acquire sufficient solar resources to meet the on-site solar system requirements in the Colorado statutes. On Feb. 14, 2006, PSCo and the other parties to the case filed a stipulation agreeing to reduce the RESA rider to 0.60 percent and to provide monthly reports.  Hearings were held on Feb. 17, 2006.  A CPUC decision is pending.  PSCo expects the RESA rider will go into effect in early March 2006.

Purchased Transmission Services — PSCo has contractual arrangements with regional transmission service providers to deliver power and energy to the subsidiaries’ native load customers, which are retail and wholesale load obligations with terms of more than one year.  Point-to-point transmission services typically include a charge for the specific amount of

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transmission capacity being reserved, although some agreements may base charges on the amount of metered energy delivered.  Network transmission services include a charge for the metered demand at the delivery point at the time of the provider’s monthly transmission system peak, usually calculated as a 12-month rolling average.

Fuel Supply and Costs

The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels during such years.

See additional discussion of fuel supply and costs under Factors Affecting Results of Continuing Operations in Management’s Discussion and Analysis under Item 7.

Fuel Sources — Coal inventory levels may vary widely among plants.  However, PSCo normally maintains no less than 30 days of coal inventory at each plant site.  PSCo’s generation stations use low-sulfur western coal purchased primarily under long-term contracts with suppliers operating in Colorado and Wyoming. During 2005, PSCo’s coal requirements for existing plants were approximately 9.8 million tons. Coal supply inventories at Dec. 31, 2005 were approximately 12 days usage, based on the maximum burn rate for all of PSCo’s coal-fired plants.  See Management’s Discussion and Analysis for further discussion of coal delivery disruptions.

PSCo has contracted for coal suppliers to supply 100 percent of the Cherokee, Cameo, and Valmont stations’ projected requirements in 2006.

PSCo has long-term coal supply agreements for the Pawnee and Comanche stations’ projected requirements. Under the long-term agreements the supplier has dedicated specific coal reserves at the contractually defined mines to meet the contract quantity obligations. In addition, PSCo has a coal supply agreement to supply approximately 70 percent of Arapahoe station’s projected requirements for 2006. Any remaining Arapahoe station requirements will be procured via spot market purchases.

PSCo operates the jointly owned Hayden generating plant in Colorado.  All of Hayden’s coal requirements are under contract through the end of 2011.  The coal will be trucked approximately 14 miles under a trucking contract effective through 2009 with an option to extend to the end of 2011.  In addition to Hayden, PSCo has partial ownership in the Craig generating plant in Colorado.  Approximately 70 percent of PSCo’s coal requirements for Craig are supplied by two long-term agreements.  The remaining coal requirements for Craig are purchased on the spot market under short term contracts.  All of 2006 expected requirements for Craig are under contract.

PSCo had a number of coal transportation contracts, which expired over the course of 2005.  PSCo has entered into new transportation agreements at rates substantially higher than its 2005 costs.

PSCo uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas supplies for PSCo’s power plants are procured under short- and intermediate- term contracts, which expire in various years from 2006 through 2025 to provide an adequate supply of fuel.  Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery.  At Dec. 31, 2005, PSCo’s commitments related to these contracts were approximately $205 million.

Commodity Marketing Operations

PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. Participation in short-term wholesale energy markets provides market intelligence and information that supports the energy management of PSCo.  PSCo uses physical and financial instruments to minimize commodity price and credit risk and hedge supplies and purchases. Engaging in short-term sales and purchase commitments results in an efficient use of our plants and the capturing of additional margins from non-traditional customers.  PSCo also uses these marketing operations to capture arbitrage opportunities created by regional pricing differentials, supply and demand imbalances and changes in fuel prices.  See additional discussion under Item 7A — Quantitative and Qualitative Disclosures About Market Risk.

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SPS

Ratemaking Principles

Summary of Regulatory Agencies and Areas of Jurisdiction — The PUCT regulates SPS’ Texas operations as an electric utility and has jurisdiction over its retail rates and services. The municipalities in which SPS operates in Texas have jurisdiction over SPS’ rates in those communities. The NMPRC has jurisdiction over the issuance of securities. The NMPRC, the Oklahoma Corporation Commission and the Kansas Corporation Commission have jurisdiction with respect to retail rates and services and construction of transmission or generation in their respective states.  SPS is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce.  SPS has received authorization from the FERC to make wholesale electricity sales at market-based prices, however, as discussed previously, SPS has filed to withdraw its market-based rate authority with respect to sales in its own control area.

Fuel, Purchased Energy and Conservation Cost Recovery Mechanisms — Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor, which is part of SPS’ retail electric rates.  The Texas retail fuel factors change each November and May based on the projected cost of natural gas.

If it appears that SPS will materially over-recover or under-recover these costs, the factor may be revised upon application by SPS or action by the PUCT. The regulations require refunding or surcharging over- or under-recovery amounts, including interest, when they exceed 4 percent of the utility’s annual fuel and purchased energy costs, as allowed by the PUCT, if this condition is expected to continue.

PUCT regulations require periodic examination of SPS fuel and purchased energy costs, the efficiency of the use of fuel and purchased energy, fuel acquisition and management policies and purchase energy commitments.  SPS is required to file an application for the PUCT to retrospectively review at least every three years the operations of SPS’ electric generation and fuel management activities.  SPS is scheduled to file for review and reconciliation of its 2004-2005 costs at the end of May 2006.

The NMPRC regulations provide for a fuel and purchased power cost adjustment clause for SPS’ New Mexico retail jurisdiction.  SPS files monthly and annual reports of its fuel and purchased power costs with the NMPRC.  The NMPRC authorized SPS to implement a monthly adjustment factor.

SPS recovers fuel and purchased energy costs from its wholesale customers through a fuel cost adjustment clause accepted for filing by the FERC.

Performance-Based Regulation and Quality of Service Requirements — In Texas, SPS is subject to a quality of service plan requiring SPS to comply with electric service reliability, telephone response and abandoned call performance targets.  If these targets are not met, SPS is required to make refunds to its customers of up to $950,000 per year.  As of Dec. 31, 2005, SPS accrued $800,000 to reflect the expected refund obligation for those measures.

Pending and Recently Concluded Regulatory Proceedings - FERC

PSCo and SPS FERC Transmission Rate Case — On Sept. 2, 2004, Xcel Energy filed on behalf of SPS and PSCo an application to increase wholesale transmission service and ancillary service rates within the Xcel Energy joint open access transmission tariff (OATT).  PSCo and SPS requested an increase in annual transmission service and ancillary services revenues, which was adjusted to reflect a net increase in annual revenues of $4.7 million, of which $1.7 million is attributable to SPS.  The FERC suspended the filing and delayed the effective date of the proposed increase to June 1, 2005.  The interim rates went into effect on June 1, 2005, subject to refund.  On Feb. 6, 2006, the parties in the proceeding submitted to the settlement judge an uncontested offer of settlement that contains stated rates for SPS, with the opportunity to file revised rates effective Oct. 1, 2006, by which time the SPP is expected to have filed a regional formula transmission rate mechanism similar to MISO.  The settlement results in a $1.1 million SPS rate increase effective June 2005.  The offer of settlement is pending FERC approval.

SPS Wholesale Rate Complaints — In November 2004, several wholesale cooperative customers of SPS filed a $3 million rate complaint at the FERC requesting that the FERC investigate SPS’ wholesale power base rates and fuel cost adjustment clause calculations.  In December 2004, the FERC accepted the complaint filing and ordered SPS base rates subject to refund,

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effective Jan. 1, 2005.  Also in November 2004, SPS filed revisions to its wholesale fuel cost adjustment clause.  The FERC set the proposed rate changes into effect on Jan. 1, 2005, subject to refund, and consolidated the proceeding with the wholesale cooperative customers’ complaint proceeding.  The FERC set the consolidated proceeding for hearing and settlement judge procedures, which were terminated when the parties could not reach a settlement.  A hearing judge has been appointed by the FERC.  Hearings began Feb. 24, 2006 and are expected to last several weeks.

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

SPS Wholesale Power Base Rate Application — In December 2005, SPS filed at the FERC for a $4.1 million annual increase in wholesale power rates for many of its requirements and interruptible capacity wholesale customers.  In January 2006, the FERC issued an order conditionally accepting and suspending the proposed rates until July 1, 2006, establishing hearing and settlement judge procedures.

Southwest Power Pool (SPP) Restructuring — SPS is a member of the SPP regional reliability council, and SPP acts as transmission tariff administrator for the SPS system. In October 2003, SPP filed for FERC authorization to transform its operation into an RTO.  On Oct. 1, 2004, the FERC issued an order granting the SPP status as an RTO.  SPS is required to obtain Kansas and NMPRC approval before it can transfer functional control of its electrical transmission system to SPP.  When SPP begins RTO operations and SPS obtains all required approvals, SPS will be required to transfer functional control of its electric transmission system to SPP and take all transmission services, including services required to serve retail native loads, under the SPP regional tariff.

SPP Energy Imbalance Service - On June 15, 2005, SPP filed proposed tariff provisions to establish an Energy Imbalance Service (EIS) wholesale energy market for the SPP region, using a phased approach toward the development of a fully-functional LMP energy market with appropriate FTR’s, to be effective Mar. 1, 2006.  On July 15, 2005, Xcel Energy filed a protest addressing the EIS market proposal and urging FERC to reject the proposal and provide guidance to SPP in its effort to design and implement a fully functional Day 2 market for the SPP region to avoid “seams” between the MISO and SPP regions.  On Sept. 19, 2005, FERC issued an order rejecting the SPP EIS proposal and providing guidance and recommendations to SPP; however, the FERC did not require SPP to implement a full Day 2 market similar to MISO.  On Jan. 4, 2006, SPP filed a revised EIS market proposal, to be effective May 1, 2006.  On Jan. 25, 2006, Xcel Energy protested the revised EIS market proposal, requesting that FERC find SPP’s proposal as incomplete and deficient even as a limited market, and reject it on that basis.  A final FERC decision is expected later in 2006.  SPS has not yet requested NMPRC or PUCT approval regarding accounting and ratemaking treatment of EIS costs.

Pending and Recently Concluded Regulatory Proceedings - PUCT

SPS Texas Retail Fuel Cost Reconciliation – Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor.  In May 2004, SPS filed with PUCT its periodic request for fuel and purchased power cost recovery for January 2002 through December 2003.  SPS requested approval of approximately $580 million of Texas-jurisdictional fuel and purchased power costs for the two-year period.  Intervenor testimony contained objections to SPS’ methodology for assigning average fuel costs to certain wholesale sales, among other things.  Recovery of $49 million to $86 million of the requested amount was contested by multiple intervenors.

In 2005, SPS entered into a non-unanimous stipulation with the PUCT staff and several of the intervenors.  The stipulation provided reasonable regulatory certainty for SPS on all key issues raised in this proceeding.  On Dec. 19, 2005, the PUCT issued an order approving the stipulation.  The stipulation reflects a liability of approximately $25 million, which was accrued in 2004.  An additional accrual of $4 million was recorded in 2005 to reflect the impact of the order through Dec. 31, 2005.  Under the terms of the stipulation, SPS will file a Texas base rate case and its next fuel reconciliation application by the end of May 2006.

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

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process that is expected to take place largely in the first quarter of 2006.

Lamb County Electric Cooperative — On July 24, 1995, Lamb County Electric Cooperative, Inc. (LCEC) petitioned the PUCT for a cease and desist order against SPS. LCEC alleged that SPS had been unlawfully providing service to oil field customers and their facilities in LCEC’s singly-certificated area. The PUCT denied LCEC’s petition. See further discussion under Item 3 — Legal Proceedings.

Pending and Recently Concluded Regulatory Proceedings - NMPRC

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

New Mexico Fuel Factor Continuation Filing - The filing to continue the use of SPS’ FPPCAC was made on Aug. 18, 2005.  This filing is required every two years pursuant to the NMPRC rules.  The filing proposes that the FPPCAC continue the current monthly factor cost recovery methodology.  Certain industrial customers have asked the NMPRC to review SPS’ assignment of system average fuel cost to certain wholesale capacity sales.  Customers have also asked the NMPRC to investigate 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.   Hearings have been scheduled for April 2006, and a NMPRC decision is expected in late 2006.

Capacity and Demand

Uninterrupted system peak demand for SPS for each of the last three years and the forecast for 2006, assuming normal weather, are listed below.

The peak demand for the SPS system typically occurs in the summer.  The 2005 uninterrupted system peak demand for SPS occurred on July 25, 2005.

Energy Sources and Related Transmission Initiatives

SPS expects to use existing electric generating stations; purchases from other utilities, independent power producers and power marketers and demand-side management options to meet its net dependable system capacity requirements.

Purchased Power — SPS has contractual arrangements to purchase power from other utilities and nonregulated energy suppliers. Capacity, typically measured in KW or MW, is the measure of the rate at which a particular generating source produces electricity. Energy, typically measured in Kwh or Mwh, is a measure of the amount of electricity produced from a particular generating source over a period of time. Long-term purchase power contracts typically require a periodic payment to secure the capacity from a particular generating source and a charge for the associated energy actually purchased from such generating source.

SPS also makes short-term firm and non-firm purchases to replace generation from company-owned units that are unavailable due to maintenance and unplanned outages, to provide the utility’s reserve obligation, to obtain energy at a lower cost than that which could be produced by other resource options, including company-owned generation and/or long-term purchase power contracts, and for various other operating requirements.

Purchased Transmission Services — SPS has contractual arrangements with regional transmission service providers to deliver power and energy to the subsidiaries’ native load customers, which are retail and wholesale load obligations with terms of more than one year.  Point-to-point transmission services typically include a charge for the specific amount of transmission capacity being reserved, although some agreements may base charges on the amount of metered energy

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delivered.  Network transmission services include a charge for the metered demand at the delivery point at the time of the provider’s monthly transmission system peak, usually calculated as a 12-month rolling average.

Fuel Supply and Costs

The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels during such years.

* The lower 2003 SPS coal costs reflect a prior period fuel credit adjustment. The normalized cost per MMBtu was approximately $1.14.

See additional discussion of fuel supply and costs under Factors Affecting Results of Continuing Operations in Management’s Discussion and Analysis under Item 7.

Fuel Sources — SPS purchases all of its coal requirements for its two coal facilities, Harrington and Tolk electric generating stations, from TUCO, Inc. in the form of crushed, ready-to-burn coal delivered to the plant bunkers. TUCO, in turn, arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to the plant bunkers to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters, and handlers. For the Harrington station, the coal supply contract with TUCO expires in 2016. For the Tolk station, the coal supply contract with TUCO expires in 2017.  At Dec. 31, 2005, coal supplies at the Harrington and Tolk sites were approximately 36 and 40 days supply, respectively.  See Item 7 – Management’s Discussion & Analysis for discussion of coal delivery disruptions.  TUCO has coal supply agreements to supply 100 percent of the projected 2006 requirements for Harrington and Tolk stations.  TUCO has long-term contracts for supply of coal in sufficient quantities to meet the primary needs of the Harrington and Tolk stations.

SPS uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas suppliers for SPS’ power plants are procured under short- and intermediate-term contracts to provide an adequate supply of fuel.

Commodity Marketing Operations

SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. Participation in short-term wholesale energy markets provides market intelligence and information that supports the energy management of SPS.  SPS uses physical and financial instruments to minimize commodity price and credit risk and hedge supplies and purchases. Engaging in short-term sales and purchase commitments results in an efficient use of our plants and the capturing of additional margins from non-traditional customers.  On a limited basis, SPS also uses these marketing operations to capture arbitrage opportunities created by regional pricing differentials, supply and demand imbalances and changes in fuel prices.  See additional discussion under Item 7A — Quantitative and Qualitative Disclosures About Market Risk.

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Xcel Energy Electric Operating Statistics

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NATURAL GAS UTILITY OPERATIONS

Natural Gas Utility Trends

Changes in regulatory policies and market forces have shifted the industry from traditional bundled natural gas sales service to an unbundled transportation and market-based commodity service at the wholesale level and for larger commercial and industrial retail customers. These customers have greater ability to buy natural gas directly from suppliers and arrange their own pipeline and retail LDC transportation service.

The natural gas delivery/transportation business has remained competitive as industrial and large commercial customers have the ability to bypass the local natural gas utility through the construction of interconnections directly with interstate pipelines, thereby avoiding the delivery charges added by the local natural gas utility.

As LDCs, NSP-Minnesota, NSP-Wisconsin and PSCo provide unbundled transportation service to large customers. Transportation service does not have an adverse effect on earnings because the sales and transportation rates have been designed to make them economically indifferent to whether natural gas has been sold and transported or merely transported. However, some transportation customers may have greater opportunities or incentives to physically bypass the LDCs’ distribution system.

The most significant recent developments in the natural gas operations of the utility subsidiaries was the substantial and continuing increases in wholesale natural gas market prices and the continued trend toward declining use per customer by residential customers as a result of improved building construction technologies and higher appliance efficiencies.  From 1995 to 2005, average annual sales to the typical residential customer declined from 104 Dth per year to 87 Dth per year on a weather-normalized basis.  Although recent wholesale price increases do not directly affect earnings because of gas cost recovery mechanisms, the high prices are expected to encourage further efficiency efforts by customers.

NSP-Minnesota

Ratemaking Principles

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s operations are regulated by the MPUC and the NDPSC within their respective states. The MPUC has regulatory authority over aspects of NSP-Minnesota’s financial activities, including security issuances, certain property transfers, mergers with other utilities and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s gas supply plans for meeting customers’ future energy needs.

Purchased Gas and Conservation Cost Recovery Mechanisms — NSP-Minnesota’s retail natural gas rate schedules for Minnesota and North Dakota include a PGA clause that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased natural gas. The annual difference between the natural gas costs collected through PGA rates and the actual natural gas costs are collected or refunded over the subsequent 12-month period. The MPUC and NDPSC have the authority to disallow recovery of certain costs if they find the utility was not prudent in its procurement activities.

NSP-Minnesota is required by Minnesota law to spend a minimum of 0.5 percent of Minnesota natural gas revenue on conservation improvement programs. These costs are recovered through an annual cost recovery mechanism for natural gas conservation and energy management program expenditures. NSP-Minnesota is required to request a new cost recovery level annually.

Pending and Recently Concluded Regulatory Proceedings

NSP-Minnesota Natural Gas Rate Case - In September 2004, NSP-Minnesota filed a natural gas rate case for its Minnesota retail customers, seeking a rate increase of $9.9 million, based on a return on equity of 11.5 percent.  In August 2005, the MPUC approved an annual rate increase of $5.8 million, based on a return on equity of 10.4 percent. Final rates became effective Dec. 1, 2005.

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Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Minnesota was 611,950 MMBtu for 2005, which occurred on Jan. 5, 2005.

NSP-Minnesota purchases natural gas from independent suppliers. The natural gas is delivered under natural gas transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of 521,854 MMBtu/day. In addition, NSP-Minnesota has contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 21 percent of winter natural gas requirements and 26 percent of peak day, firm requirements of NSP-Minnesota.

NSP-Minnesota also owns and operates one LNG plant with a storage capacity of 2.13 Bcf equivalent and three propane-air plants with a storage capacity of 1.4 Bcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 250,300 MMBtu of natural gas per day, or approximately 34 percent of peak day firm requirements. LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days.

NSP-Minnesota is required to file for a change in natural gas supply contract levels to meet peak demand, to redistribute demand costs among classes or to exchange one form of demand for another. NSP-Minnesota’s 2004-2005 entitlement levels were approved on July 12, 2005 which allow NSP-Minnesota to recover the demand entitlement costs associated with the increase in transportation, supply, and storage levels in its monthly PGA. In June 2005, NSP-Minnesota also filed to add incremental storage to its portfolio.  The increase in storage was approved by the MPUC on Nov. 18, 2005.  The 2005-2006 entitlement levels are pending MPUC action.

Natural Gas Supply and Costs

NSP-Minnesota actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk, and economical rates. This diversification involves numerous domestic and Canadian supply sources with varied contract lengths.

The following table summarizes the average cost per MMBtu of natural gas purchased for resale by NSP-Minnesota’s regulated retail natural gas distribution business:

The cost of natural gas supply, transportation service and storage service is recovered through the PGA cost recovery mechanism.

NSP-Minnesota has firm natural gas transportation contracts with several pipelines, which expire in various years from 2006 through 2027.

NSP-Minnesota has certain natural gas supply and transportation agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2005, NSP-Minnesota was committed to approximately $810 million in such obligations under these contracts.

NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 25 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Minnesota to maintain competition from suppliers and minimize supply costs.

See additional discussion of natural gas costs under Factors Affecting Results of Continuing Operations in Management’s Discussion and Analysis under Item 7.

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NSP-Wisconsin

Ratemaking Principles

Summary of Regulatory Agencies and Areas of Jurisdiction — NSP-Wisconsin is regulated by the PSCW and the MPSC.

The PSCW has a biennial base-rate filing requirement. By June of each odd-numbered year, NSP-Wisconsin must submit a rate filing for the test year period beginning the following January. The filing procedure and review generally allow the PSCW sufficient time to issue an order and implement new base rates effective with the start of the test year.

Natural Gas Cost Recovery Mechanisms — NSP-Wisconsin has a retail gas cost recovery mechanism for Wisconsin operations to recover changes in the actual cost of natural gas and transportation and storage services. The PSCW has the authority to disallow certain costs if it finds the utility was not prudent in its procurement activities.

NSP-Wisconsin’s gas rate schedules for Michigan customers include a gas cost recovery factor, which is based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period.

Pending and Recently Concluded Regulatory Proceedings - PSCW

See NSP-Wisconsin 2006 General Rate Case discussion under Pending and Recently Concluded Regulatory Proceedings - PSCW in NSP-Wisconsin’s Electric Utility Operations section above.

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Wisconsin was 154,040 MMBtu for 2005, which occurred on Jan. 17, 2005.

NSP-Wisconsin purchases natural gas from independent suppliers. The natural gas is delivered under natural gas transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 122,872 MMBtu/day. In addition, NSP-Wisconsin has contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 21 percent of winter natural gas requirements and 29 percent of peak day, firm requirements of NSP-Wisconsin.

NSP-Wisconsin also owns and operates one LNG plant with a storage capacity of 270,000 Mcf equivalent and one propane-air plant with a storage capacity of 2,700 Mcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 18,408 MMBtu of natural gas per day, or approximately 14 percent of peak day firm requirements. LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days.

NSP-Wisconsin is required to file a natural gas supply plan with the PSCW annually to change natural gas supply contract levels to meet peak demand. NSP-Wisconsin’s winter 2005-2006 supply plan was approved by the PSCW in October 2005.

Natural Gas Supply and Costs

NSP-Wisconsin actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk, and economical rates. This diversification involves numerous domestic and Canadian supply sources with varied contract lengths.

The following table summarizes the average cost per MMBtu of natural gas purchased for resale by NSP-Wisconsin’s regulated retail natural gas distribution business:

The cost of natural gas supply, transportation service and storage service is recovered through various cost recovery adjustment mechanisms.

NSP-Wisconsin has firm natural gas transportation contracts with several pipelines, which expire in various years from 2006 through 2027.

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NSP-Wisconsin has certain natural gas supply and transportation agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery.  At Dec. 31, 2005, NSP-Wisconsin was committed to approximately $145 million in such obligations under these contracts.

NSP-Wisconsin purchased firm natural gas supply utilizing short-term agreements from approximately 25 domestic and Canadian suppliers.  This diversity of suppliers and contract lengths allows NSP-Wisconsin to maintain competition from suppliers and minimize supply costs.

See additional discussion of natural gas costs under Factors Affecting Results of Continuing Operations in Management’s Discussion and Analysis under Item 7.

PSCo

Ratemaking Principles

Summary of Regulatory Agencies and Areas of Jurisdiction — PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities.  PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction under the federal Natural Gas Act.

Purchased Gas and Conservation Cost Recovery Mechanisms — PSCo has a GCA mechanism, which allows PSCo to recover its actual costs of purchased gas.  The GCA is revised monthly to allow for changes in gas rates.

Performance-based Regulation and Quality of Service Requirements — The CPUC established a combined electric and natural gas quality of service plan.  See further discussion under Item 1, Electric Utility Operations.

Pending and Recently Concluded Regulatory Proceedings

PSCo Natural Gas Rate Case — In 2005, PSCo filed for an increase of $34.5 million in natural gas base rates in Colorado, based on a return on equity of 11.0 percent with a common equity ratio of 55.49 percent.

On Jan. 19, 2006, the CPUC approved a settlement agreement between PSCo and other parties to the case.  Final rates became effective Feb. 6, 2006. The terms of the settlement include:

•      Natural gas revenue increase of $22 million;

•      Return on common equity of 10.5 percent;

•      Earnings in excess of 10.5 percent return on common equity will be refunded back to customers;

•      Common equity ratio of 55.49 percent; and

•      Customer charges for the residential and commercial sales classes of $10 and $20 per month, respectively.

Capability and Demand

PSCo projects peak day natural gas supply requirements for firm sales and backup transportation, which include transportation customers contracting for firm supply backup, to be 1,792,770 MMBtu. In addition, firm transportation customers hold 489,014 MMBtu of capacity for PSCo without supply backup.  Total firm delivery obligation for PSCo is 2,281,784 MMBtu per day. The maximum daily deliveries for PSCo in 2005 for firm and interruptible services were 1,871,486 MMBtu on Dec. 7, 2005.

PSCo purchases natural gas from independent suppliers. The natural gas supplies are delivered to the respective delivery systems through a combination of transportation agreements with interstate pipelines and deliveries by suppliers directly to each company. These agreements provide for firm deliverable pipeline capacity of approximately 1,802,524 MMBtu/day, which includes 831,866 MMBtu of supplies held under third-party underground storage agreements. In addition, PSCo operates three company-owned underground storage facilities, which provide about 40,000 MMBtu of natural gas supplies on a peak day. The balance of the quantities required to meet firm peak day sales obligations are primarily purchased at the companies’ city gate meter stations and a small amount is received directly from wellhead sources.

PSCo has closed the Leyden Storage Field and is in the monitoring phase of the abandonment process, which is expected to continue until December 2007. See further discussion at Note 14 to the Consolidated Financial Statements.

PSCo is required by CPUC regulations to file a natural gas purchase plan by June of each year projecting and describing the quantities of natural gas supplies, upstream services and the costs of those supplies and services for the period beginning July

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1 through June 30 of the following year. PSCo is also required to file a natural gas purchase report by October of each year reporting actual quantities and costs incurred for natural gas supplies and upstream services for the 12-month period ending the previous June 30.

Natural Gas Supply and Costs

PSCo actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk, and economical rates. This diversification involves numerous supply sources with varied contract lengths.

The following table summarizes the average cost per MMBtu of natural gas purchased for resale by PSCo’s regulated retail natural gas distribution business:

PSCo has certain natural gas supply and transportation agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2005, PSCo was committed to approximately $1.4 billion in such obligations under these contracts, which expire in various years from 2006 through 2025.

PSCo purchases natural gas by optimizing a balance of long-term and short-term natural gas purchases, firm transportation and natural gas storage contracts. During 2005, PSCo purchased natural gas from approximately 37 suppliers.

See additional discussion of natural gas costs under Factors Affecting Results of Continuing Operations in Management’s Discussion and Analysis under Item 7.

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Xcel Energy Gas Operating Statistics

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ENVIRONMENTAL MATTERS

Certain of Xcel Energy’s subsidiary facilities are regulated by federal and state environmental agencies. These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. Xcel Energy has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Company facilities have been designed and constructed to operate in compliance with applicable environmental standards.

Xcel Energy and its subsidiaries strive to comply with all environmental regulations applicable to its operations. However, it is not possible at this time to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or, generally, what effect future laws or regulations may have upon Xcel Energy’s operations. For more information on environmental contingencies, see Notes 14 and 15 to the Consolidated Financial Statements, environmental matters in Management’s Discussion and Analysis under Item 7 and the matter discussed below.

Levee Station Manufactured Gas Plant Site — A portion of NSP-Minnesota’s High Bridge plant coal yard is located on the site of the former Levee Station MGP site. The Levee Station was a coke-oven gas purification, storage and distribution facility.  The Levee Station supplied manufactured gas to the city of St. Paul from 1918 to the early 1950s.  In the 1950s, the facility was demolished, and the High Bridge coal yard was extended onto the property.  In the 1990s, the site was investigated and partially remediated at a cost of approximately $2.9 million.  In 2006, NSP-Minnesota plans to commence construction of the High Bridge Combined Cycle Generating Plant, as part of the MERP, on the site of the Levee Station. The construction of the new plant required the removal of buried structures and soil and groundwater remediation. Remediation activities were essentially completed in 2005 at a cost of $3.5 million, which will be accounted for as a capital expenditure of the MERP project.

CAPITAL SPENDING AND FINANCING

For a discussion of expected capital expenditures and funding sources, see Management’s Discussion and Analysis under Item 7.

EMPLOYEES

The number of full-time Xcel Energy employees in continuing operations at Dec. 31, 2005, is presented in the table below. Of the full-time employees listed below, 5,459 or 56 percent, are covered under collective bargaining agreements.

* NSP-Minnesota full-time employees include 347 employees loaned to the NMC. In addition, the NMC has 712 full-time employees of its own.

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EXECUTIVE OFFICERS

Richard C. Kelly, 59, Chairman of the Board, Xcel Energy Inc., December 2005 to present; Chief Executive Officer, Xcel Energy Inc., July 2005 to present; President, Xcel Energy Inc., October 2003 to present. Previously, Chief Operating Officer, Xcel Energy Inc., October 2003 to June 2005, Vice President and Chief Financial Officer, Xcel Energy Inc., August 2002 to October 2003 and President — Enterprises Business Unit, Xcel Energy, August 2000 to August 2002.

Paul J. Bonavia, 54, President — Utilities Group, Xcel Energy, November 2005 to present; Vice President, Xcel Energy Services Inc., September 2000 to present. Previously, President — Commercial Enterprises Business Unit, Xcel Energy, December 2003 to October 2005 and President — Energy Markets Business Unit, Xcel Energy, August 2000 to December 2003.

Benjamin G.S. Fowke III, 47, Chief Financial Officer, Xcel Energy Inc., October 2003 to present; Vice President, Xcel Energy Inc., November 2002 to present.  Previously, Treasurer, Xcel Energy Inc., November 2002 to May 2004 and Vice President and Chief Financial Officer — Energy Markets Business Unit, Xcel Energy, August 2000 to November 2002.

Gary L. Gibson, 64, President, SPS, December 2000 to present; Chief Executive Officer, SPS, August 2001 to present.

Raymond E. Gogel, 55, Vice President, Xcel Energy Services Inc., April 2002 to present; Chief Information Officer, Xcel Energy Services Inc., April 2002 to February 2006 Vice President Customer and Enterprise Solutions Group, Chief Human Resource Officer and Chief Administrative Officer, November 2005 to present.  Previously, Vice President and Senior Client Services Principal, IBM Global Services, April 2001 to April 2002 and Senior Project Executive, IBM Global Services, April 1999 to April 2001.

Cathy J. Hart, 56, Vice President and Corporate Secretary, Xcel Energy Inc., August 2000 to present; Vice President, Corporate Services Group, November 2005 to present.

Gary R. Johnson, 59, Vice President and General Counsel, Xcel Energy Inc., August 2000 to present.

Cynthia L. Lesher, 57, President and Chief Executive Officer, NSP-Minnesota, October 2005 to present. Previously, Chief Administrative Officer, Xcel Energy, August 2000 to October 2005 and Chief Human Resources Officer, Xcel Energy, July 2001 to October 2005.

Teresa S. Madden, 49, Vice President and Controller, Xcel Energy Inc., January 2004 to present. Previously, Vice President of Finance — Customer and Field Operations Business Unit, Xcel Energy, August 2003 to January 2004, Interim CFO, Rogue Wave Software, Inc., February 2003 to July 2003 and Corporate Controller, Rogue Wave Software, Inc., October 2000 to February 2003.

Michael L. Swenson, 55, President and Chief Executive Officer, NSP-Wisconsin, February 2002 to present. Previously, State Vice President for North Dakota and South Dakota, August 2000 to February 2002.

George E. Tyson II, 40, Vice President and Treasurer, Xcel Energy Inc., May 2004 to present.  Previously, Managing Director and Assistant Treasurer, Xcel Energy, July 2003 to May 2004; Director of Origination — Energy Markets Business Unit, Xcel Energy, May 2002 to July 2003; Associate and Vice President, Deutsche Bank Securities, December 1996 to April 2002.

Patricia K. Vincent, 47, President and Chief Executive Officer, PSCo, October 2005 to present.  Previously, President — Customer and Field Operations Business Unit, Xcel Energy, July 2003 to October 2005, President — Retail Business Unit, Xcel Energy, March 2001 to July 2003 and Vice President of Marketing and Sales, Xcel Energy Services Inc., August 2000 to March 2001.

David M. Wilks, 59, Vice President, Xcel Energy Services, Inc., September 2000 to present; President — Energy Supply Group, Xcel Energy, August 2000 to present.

No family relationships exist between any of the executive officers or directors.

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Item 1A — Risk Factors

Risks Associated with Our Business

Our profitability depends in part on the ability of our utility subsidiaries to recover their costs from their customers and there may be changes in circumstances or in the regulatory environment that impair the ability of our utility subsidiaries to recover costs from their customers.

We are subject to comprehensive regulation by several federal and state utility regulatory agencies, which significantly influences our operating environment and our ability to recover our costs from utility customers. The utility commissions in the states where our utility subsidiaries operate regulate many aspects of our utility operations including siting and construction of facilities, customer service and the rates that we can charge customers.

The profitability of our utility operations is dependent on our ability to recover costs related to providing energy and utility services to our customers.  Our public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions.  These rates are generally regulated based on an analysis of the utility’s expenses incurred in a test year.  Thus, the rates a utility is allowed to charge may or may not match its expenses at any given time.  While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs.   Although we believe that the current regulatory environment applicable to our business would permit us to recover the costs of our utility services, it is possible that there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers. 

State utility commissions generally possess broad powers to ensure that the needs of the utility customers are being met. The state utility commissions also may seek to impose restrictions on the ability of our utility subsidiaries to pay dividends to us. If successful, this could materially and adversely affect our ability to meet our financial obligations, including paying dividends on our common stock.

The FERC has jurisdiction over wholesale rates for electric transmission service, electric energy sold at wholesale in interstate commerce, hydro facility licensing and certain other activities of our utility subsidiaries. Federal, state and local agencies also have jurisdiction over many of our other activities, including regulation of retail rates and environmental matters. 

We are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including paying dividends on our common stock.

We are subject to commodity price risk, credit risk and other risks associated with energy markets.

We engage in wholesale sales and purchases of electric capacity, energy and energy-related products and, accordingly, are subject to commodity price risk, credit risk and other risks associated with these activities.

We are exposed to market and credit risks in our generation, distribution, commodity acquisition, short-term wholesale and commodity trading activities.  To minimize the risk of market price fluctuations and product availability, we enter into physical and financial contracts to hedge both price and availability risk associated with purchase and sale commitments, fuel requirements and inventories of coal, natural gas, fuel oil and energy and energy-related products.  However, these contracts do not completely eliminate risks, including commodity price changes, market supply shortages, credit risk and interest rate changes. The impact of these variables could result in our inability to fulfill contractual obligations, significantly higher energy or fuel costs relative to corresponding sales commitments or increased interest expense.

Credit and performance risk includes the risk that counterparties that owe us money or product will breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses.

We mark commodity trading derivatives to estimated fair market value on a daily basis (mark-to-market accounting), which causes earnings variability. Quoted market prices are utilized in determining the value of these derivative commodity instruments.  For positions for which market prices are not available, we utilize models based on forward price curves. These

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models incorporate estimates and assumptions as to a variety of factors such as pricing relationships between various energy commodities and geographic locations. Actual experience can vary significantly from these estimates and assumptions.

Our subsidiary, PSCo, has received a notice from the Internal Revenue Service (IRS) proposing to disallow certain interest expense deductions that PSCo claimed in 1993 through 1999. Should the IRS ultimately prevail on this issue, our liquidity position and financial results could be materially adversely affected.

PSCo’s wholly owned subsidiary PSR Investments, Inc. (PSRI) owns and manages permanent life insurance policies on some of PSCo’s employees, known as corporate-owned life insurance (COLI). At various times, borrowings have been made against the cash values of these COLI policies and deductions taken on the interest expense on these borrowings. The IRS has challenged the deductibility of such interest expense deductions and has disallowed the deductions taken in tax years 1993 through 1999.

We believe that the tax deduction of interest expense on the COLI policy loans is in full compliance with the law. Accordingly, PSRI has not recorded any provision for income tax or related interest or penalties that may be imposed by the IRS and has continued to take deductions for interest expense related to policy loans on its income tax returns for subsequent years.

In April 2004, Xcel Energy filed a lawsuit against the government in the U.S. District Court for the District of Minnesota to establish its right to deduct the policy loan interest expense that had accrued during tax years 1993 and 1994 on policy loans related to its COLI policies.

After Xcel Energy had filed this suit, the IRS sent it two statutory notices of proposed deficiency of tax, penalty, and interest for taxable years 1995 through 1999.  Xcel Energy then timely filed two Tax Court petitions challenging those notices.  Xcel Energy anticipates that the dispute relating to its claimed interest expense deductions for tax years 1993 and later will be resolved in the refund suit that is pending in the Minnesota federal district court and that the two Tax Court petitions will be held in abeyance pending the outcome of the refund litigation.

On Oct. 12, 2005, the district court denied Xcel Energy’s motion for summary judgment on the grounds that there were disputed issues of material fact that required a trial for resolution.  At the same time, the district court denied the government’s motion for summary judgment that was based on its contention that PSCo had lacked an insurable interest in the lives of the employees insured under the COLI policies.  However, the district court granted Xcel Energy’s motion for partial summary judgment on the grounds that PSCo did have the requisite insurable interest.  The case is expected to proceed to trial and the litigation could take another two or more years.

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 that may be imposed by the IRS and has continued to take deductions for interest expense related to policy loans on its income tax returns for subsequent years.  As discussed above, the litigation could require several 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.  Although the ultimate resolution of this matter is uncertain, it 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 Dec. 31, 2005, would reduce retained earnings by an estimated $361 million.  In 2004, Xcel Energy received formal notification that the IRS will seek penalties. If penalties (plus associated interest) also are included, the total exposure through Dec. 31, 2005, is approximately $428 million.  Xcel Energy annual earnings for 2006 would be reduced by approximately $44 million, after tax, which represents 10 cents per share, if COLI interest expense deductions were no longer available.

We are subject to environmental laws and regulations, compliance with which could be difficult and costly.

We are subject to a number of environmental laws and regulations affecting many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the management of wastes and hazardous substances.  These laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals.  Environmental laws and regulations can also require us to perform environmental remediations and to install pollution control equipment at our facilities.  Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us.  We must pay all or a portion of the cost to remediate sites where our past activities, or the activities of certain other parties, caused environmental

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