UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

Commission File Number 1-3034

(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 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 an accelerated filer (as defined in Rule 12b-2 of the Act). ý Yes or No o

As of June 30, 2004, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $6,662,420,495 and there were 399,395,315 shares of common stock outstanding.

As of February 22, 2005, there were 400,901,082 shares of common stock outstanding, $2.50 par value.

The Registrant’s Definitive Proxy Statement for its 2005 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

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PART I

Item 1 — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

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COMPANY OVERVIEW

Xcel Energy was incorporated under the laws of Minnesota in 1909 and is a registered holding company under the PUHCA. Xcel Energy is subject to the regulatory oversight of the SEC under PUHCA. The rules and regulations under PUHCA impose a number of restrictions on the operations of registered holding company systems. These restrictions include, subject to certain exceptions, a requirement that the SEC approve securities issuances, payments of dividends out of capital or unearned surplus, sales and acquisitions of utility assets or of securities of utility companies and acquisitions of other businesses. PUHCA also generally limits the operations of a registered holding company to a single integrated public utility system, plus additional energy-related businesses. PUHCA rules require that transactions between affiliated companies in a registered holding company system be performed at cost, with limited exceptions. See additional discussion of PUHCA requirements under Factors Affecting Results of Continuing Operations and Liquidity and Capital Resources in Management’s Discussion and Analysis under Item 7.

In 2004, Xcel Energy 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 WestGas InterState Inc. (WGI), an interstate natural gas pipeline company, these companies comprise our continuing regulated utility operations.  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.

Xcel Energy’s nonregulated subsidiaries in continuing operations include UE, Eloigne and Planergy. Planergy closed and began selling a majority of its business operations in 2003 with all operations ceasing in 2004. On March 2, 2005, Xcel Energy agreed to sell UE. See further discussion under Nonregulated Subsidiaries.

During 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Seren Innovations, Inc. (broadband communications services). Earnings per share for 2004 of $0.87 includes revisions to the impairment reserve associated with Seren, as well as the completed sale of Cheyenne, compared to the previously reported earnings per share of $0.97.

During 2003, Xcel Energy divested its ownership interest in NRG. On May 14, 2003, NRG and certain of its affiliates 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. (an international independent power producer, primarily in Argentina) and e prime inc. (a natural gas marketing and trading company).  NRG, Xcel Energy International, e prime and Seren are accounted for as a component of discontinued operations.

For more information regarding Xcel Energy’s discontinued operations, see Note 3 to the Consolidated Financial Statements.

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

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.  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 1.4 million customers and gas utility service to approximately 454,000 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.

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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-Minnesota owned NSP Financing I, a special purpose financing trust, for which a certificate of cancellation was filed for dissolution on Sept. 15, 2003.

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 240,000 customers in portions of northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan. 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 97,000 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 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.

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. PS Colorado Credit Corp., a finance company that was owned by PSCo and financed certain of PSCo’s current assets, was dissolved in 2002. PSCo owned PSCo Capital Trust I, a special purpose financing trust, for which a certificate of cancellation was filed for dissolution on Dec. 29, 2003.

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 comprise approximately 35 percent of the total Kwh sales in 2004.  A major portion of SPS’ retail electric operating revenues is derived from operations in Texas.  SPS owned a direct subsidiary, Southwestern Public Service Capital I, a special purpose financing trust, for which a certificate of cancellation was filed for dissolution on Jan. 5, 2004.

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.

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ELECTRIC UTILITY OPERATIONS

Electric Utility Trends

Utility Industry Growth — After a decade of cost cutting and efficiency gains in anticipation of industry restructuring and competition; areas of growth for the utility industry are limited.  The most significant areas for earnings growth include increasing regulated rates, increased investment in rate base, diversification, acquisition or modification of rate structures to implement performance-based rates.  Though remaining open to all opportunities to increase shareholder value, 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 and rate case filings with state and federal regulators to increase rates congruent with increasing costs of operations associated with such investments.

Utility Restructuring and Retail Competition — The structure of the utility industry has been subject to change.  Merger and acquisition activity in the past had been significant as utilities combined to capture economies of scale or establish a strategic niche in preparing for the future, although such activity slowed substantially after 2001.  All investor-owned utilities were required to provide nondiscriminatory access to the use of their transmission systems in 1996.  Beginning in the late 1990s, many states began studying or implementing some form of retail electric utility competition.  These states included many of the jurisdictions in which the Xcel Energy Utility Subsidiaries operate.  Much of Texas has implemented retail competition, but it is presently limited to utilities within the Electric Reliability Council of Texas.  Under the 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.  As a result of the failure of the California power market structure and nonregulated investments of many utilities, as well as other factors, most utility retail market restructuring has ceased.  No significant activity has occurred or is expected to occur in the retail jurisdictions in which Xcel Energy Utility Subsidiaries operate, except as noted previously.

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.

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 Uutility Subsidiaries.  State and local agencies have jurisdiction over many of Xcel Energy’s activities, including regulation of retail rates and environmental matters.

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Market Based Rate Authority — The FERC regulates the wholesale sale of electricity.  In addition to FERC’s traditional cost of service methodology for determining the rates allowed to be charged for wholesale electric sales, in the 1990’s FERC began to allow utilities to make sales at market-based rates.  In order to obtain market-based rate authorization from the FERC, utilities such as the Utility Subsidiaries have been required to submit analyses demonstrating that they did not have market power in the relevant markets.  Xcel Energy and the Utility Subsidiaries have been granted market-based rate authority by FERC.

In November 2001, after the market disruptions in California and other regions, the FERC issued an order under Section 206 of the Federal Power Act initiating a generic investigation proceeding against all jurisdictional electric suppliers making sales in interstate commerce at market-based rates.  In November 2003, the FERC issued a final order requiring amendments to the market-based wholesale tariffs of all FERC jurisdictional electric utilities to impose new market behavior rules and requiring submission of compliance tariff amendments in December 2003.  NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each made a timely compliance filing.  Violations of the new tariffs could result in the loss of certain wholesale sales revenues or the loss of authority to make sales at market-based rates.

In 2004, FERC initiated a new proceeding on future market-based rate authorizations and issued interim requirements for FERC jurisdictional electric utilities that have been granted authority to make wholesale sales at market-based rates.  The FERC adopted a new interim methodology to assess generation market power and modified measures to mitigate market power where it is found.  The FERC upheld and clarified the interim requirements on rehearing in an order issued on July 8, 2004.  This methodology is to be applied to all initial market-based rate applications and triennial reviews.  Under this methodology, the FERC has adopted two indicative screens (an uncommitted pivotal supplier analysis and an uncommitted market share analysis) to assess market power.  Passage of the two screens creates a rebuttable presumption that an applicant does not have market power, while the failure creates a rebuttable presumption that the utility does have market power.  An applicant or intervenor can rebut the presumption by performing a more extensive delivered-price test analysis.  If an applicant is determined to have generation market power, the applicant has the opportunity to propose its own mitigation plan or may implement default mitigation established by the FERC.  The default mitigation limits prices for sales of power to cost-based rates within areas where an applicant is found to have market power.

As required by the FERC, Xcel Energy filed the required analysis applying the FERC’s two indicative screens on behalf of itself and the Utility Subsidiaries with the FERC on Feb. 7, 2005.  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.  It is accordingly expected that the FERC will set the market-rate authorizations for the Utility Subsidiaries and Xcel Energy for investigation and hearing under Section 206 of the Federal Power Act.  At that time, the Utility Subsidiaries expect to submit a delivered-price test analysis to support the continuance of market-based rate authority in their control areas.  Xcel Energy also expects that upon the commencement of the MISO Day 2 market (see Electric Transmission Rate Regulation, below for further discussion), NSP-Minnesota and NSP-Wisconsin will be analyzed as part of the larger MISO market, and that those companies will pass both of the FERC’s indicative screens in the larger MISO market.  Xcel Energy does not expect the mitigation measures imposed, if any, to have a significant financial impact on its commodity marketing operations.

In order to enable it and interested parties to monitor each individual utility’s market-based rate authority, the FERC on Feb. 10, 2005 issued a final rule requiring that a utility with market-based rate authority file reports notifying the FERC of changes in status (e.g., additions of certain generating resources) that reflect a departure from the characteristics that the FERC relied upon in granting that utility market-based rate authority within thirty days of the occurrence of a triggering event.

Electric Transmission Rate Regulation — The FERC also regulates the rates charged and terms and conditions for electric transmission services.  Since 1996, the FERC has required the Utility Subsidiaries to provide open access transmission service at rates and tariffs on file with the FERC.  In addition, 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 in October 2005.  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.  PSCo is currently participating with other utilities in the development of an RTO.

Generation Interconnection Rules — In August 2003, the FERC issued final rules requiring the standardization of generation interconnection procedures and agreements for interconnection of new electric generators of 20 megawatts or more to the transmission systems of all FERC-jurisdictional electric utilities, including Xcel Energy’s Utility Subsidiaries. The FERC also established pricing rules for interconnections and related transmission system upgrades, which allow the transmission-owning utility to require the

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interconnecting customer to fund the interconnection costs and network upgrades required by the new generator, but require the transmission utility to provide transmission service credits, with interest, for the full amount of prepayment. The FERC required compliance filings for detailing proposed changes to Xcel Energy Utility Subsidiaries’ tariff, the MISO regional tariff, and the SPP regional tariff, which will govern most generation interconnections to the Xcel Energy Utility Subsidiaries’ transmission system.  In October 2004, the FERC accepted proposed tariff changes for Xcel Energy’s Utility Subsidiaries, subject to certain conditions.  In November 2004, the Utility Subsidiaries submitted a compliance filing.  In December 2004, the FERC issued further modifications to the interconnection rules on rehearing and required Xcel Energy’s Utility Subsidiaries to submit a further compliance filing by February 2005.  The required compliance filing was submitted on Feb. 18, 2005.

NSP-Minnesota

Ratemaking Principles

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s operations are subject to the jurisdiction of 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, 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 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. 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 and is a transmission-owner member of the MISO RTO.

The MEQB is 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 MEQB. 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.

Fuel, Purchased Energy and Conservation Cost Recovery Mechanisms — NSP-Minnesota’s retail electric rate schedules in Minnesota, North Dakota and South Dakota jurisdictions 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.  In general, capacity costs are not recovered through the FCA.  NSP-Minnesota’s electric wholesale customers also have a FCA provision in their contracts.

The MPUC has opened an investigation to consider the continuing usefulness of fuel clause adjustments for electric utilities in Minnesota.  No action has been proposed.  The MPUC has the authority to disallow recovery of certain costs if it finds the utility was not prudent in its procurement activities.

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 also approved NSP-Minnesota’s proposal to recover prudent costs of the projects through a rate adjustment provision applicable to retail electric rates 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 — In August 2000, NSP-Minnesota and NSP-Wisconsin joined the MISO. In December 2001, the FERC approved the MISO as the first RTO in the United States under FERC Order No. 2000. On Feb. 1, 2002, the MISO began interim operations, including regional transmission tariff administration services for the NSP-Minnesota and NSP-Wisconsin electric transmission systems. 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 March 31, 2004, the MISO filed its proposed TEMT, which would establish regional wholesale energy markets using locational marginal cost pricing and FTRs.  NSP-Minnesota and NSP-Wisconsin’s generation plants and transmission systems would operate subject to the TEMT.  The MISO proposed a Dec. 1, 2004 effective date.

On May 26, 2004, the FERC issued an initial procedural order.  The FERC found that certain pre-Order 888 “grandfathered” agreements (GFAs) for transmission service could negatively affect implementation of the TEMT, so FERC delayed the effective date of the energy market to March 1, 2005.  NSP-Minnesota and NSP-Wisconsin submitted compliance filings regarding their approximately 50 GFAs on June 25, 2004.  Approximately 10 GFAs were disputed, and hearings were held June 30, 2004 and July 1, 2004.  The other GFAs are not disputed.  The primary disputed issues related to responsibility for TEMT charges for loads served under the GFAs.  On Sept. 16, 2004, the FERC issued an order ruling that certain GFAs would be “carved out” of the MISO market but that transmission owners would be subject to the TEMT charges for other GFAs.  The FERC has not issued a final decision on rehearing.  On Jan. 13, 2005, several transmission-owning members of the MISO, including NSP-Minnesota and NSP-Wisconsin, filed revisions to the MISO tariff to recover TEMT charges from the customers subject to the “carved out” GFAs, effective March 1, 2005.  NSP-Minnesota and NSP-Wisconsin expect to file for rate changes under certain GFAs to recover TEMT charges from these GFA customers later in 2005.

On Aug. 6, 2004, after completion of the GFA hearings and submission of the ALJ report, the FERC issued its initial substantive order regarding the TEMT.  The FERC approved the TEMT and reaffirmed the March 1, 2005 effective date, but ordered various changes to the filed tariff.  On Sept. 7, 2004, numerous requests for rehearing were filed contesting various FERC decisions.  On Nov. 8, 2004, the FERC issued its order on rehearing largely upholding the August 6^th order.  On or before Jan. 6, 2005, several appeals of the two FERC orders were filed with the District of Columbia Court of Appeals.  Xcel Energy does not believe the outcome of the appeals will have a material financial impact.  In addition, various parties, including NSP-Minnesota and NSP-Wisconsin, have documented their concerns to MISO regarding MISO’s readiness to initiate the new energy market on March 1, 2005.  On Jan. 27, 2005, MISO announced a delay in the full market start date until April 1, 2005.

Xcel Energy opposes certain aspects of the TEMT-related implementation practices as presently designed, and believes the MISO should implement the new market mechanisms only after it demonstrates that it has fully developed all operating procedures necessary to protect reliability.  Xcel Energy cannot at this time estimate the total financial impact of the new market structure.  Xcel Energy also cannot predict at this time whether the numerous remaining issues will be resolved in time to allow the MISO market to commence on the new April 1, 2005 start date, as proposed.

Wisconsin Public Service Corp. vs. MISO — On Dec. 27, 2004, Wisconsin Public Service Corp. (WPS) filed a complaint with the FERC alleging that certain FTRs allocated to NSP-Minnesota in MISO’s FTR nomination and allocation process, associated with the implementation of the new MISO TEMT, improperly granted NSP-Minnesota FTRs to the detriment of WPS.  WPS alleged the FTR allocation to NSP-Minnesota would increase costs to WPS and its customers.  WPS requested accelerated processing of the complaint.  On Jan. 15, 2005, MISO and NSP-Minnesota filed answers asking that the WPS complaint be dismissed.  The complaint is now pending resolution by the FERC.  In a related matter, WPS appealed to the U.S. District Court for the District of Columbia previous FERC orders upholding NSP-Minnesota’s right to the underlying transmission service at issue in the MISO FTR allocation.  The appeal is scheduled to be heard by the court in April 2005.

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MISO Long Term Pricing — 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.  FERC instead ordered the MISO and PJM to file a Seams Elimination Charge Adjustment (SECA) transition mechanism.  The replacement compliance filings were submitted Nov. 24, 2004, to be effective December 1, 2004.  The FERC order eliminates any transition payments and the SECA filings instead provide for both revenues and payments that net to approximately $117,000 in revenues per month to NSP-Minnesota and NSP-Wisconsin in the first three months of 2005.  MISO and PJM are required to update the SECA charges effective April 1, 2005.  The magnitude of the new charges and payments is unknown at this time, but is expected to be similar to the charges and payments for the first three months of 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.  Therefore, the final resolution of the SECA issue and its impact on NSP-Minnesota and NSP-Wisconsin, is not fully known at this time.

Pending and Recently Concluded Regulatory Proceedings - MPUC

Minnesota Service Quality Investigation — In 2002, the MPUC directed the Office of the Attorney General and the Minnesota Department of Commerce (state agencies) to investigate the accuracy of NSP-Minnesota’s electric reliability records, which are summarized and reported to the MPUC on a monthly and annual basis, subject to penalty for not meeting threshold requirements, under the terms of the merger settlement agreements.

In 2003, NSP-Minnesota and the state agencies announced that they had reached a settlement agreement, which was approved with modifications by the MPUC in January 2004.  The settlement required NSP-Minnesota to refund $1 million to customers in Minnesota, which was paid in 2004.  In addition, it required NSP-Minnesota to incur at least $15 million of costs for actions to improve system reliability above amounts being recovered in 2004 rates by Jan. 1, 2005, for which $19 million was expended in 2004.  The MPUC modified the settlement to include an additional under-performance payment for any future finding of inaccurate reliability data.

NRG Tax Complaint — In November 2003, an NSP-Minnesota customer filed a complaint with the MPUC alleging that ratepayers are entitled to a share of the tax benefits attributable to NRG. The customer subsequently supplemented this complaint with sufficient signatures from customers to warrant a formal complaint process by the MPUC. NSP-Minnesota responded to the complaint, arguing that the requested treatment is not allowed by law and is inconsistent with the MPUC’s directives to ensure full separation of NSP-Minnesota and NRG. In August 2004, the MPUC decided not to pursue this complaint. The MPUC affirmed the long-standing precedent to view each utility as a stand-alone business that does not experience positive or negative effects from its affiliates.  The customer filed an appeal of this decision on Jan. 7, 2005, and NSP-Minnesota filed a responsive statement of the case on Jan. 18, 2005.  The Attorney General’s office petitioned to file an advisory brief to the customer’s case.

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 to determine the eligibility of additional transmission projects and to establish the RCR factors for 2005 in February 2005, seeking recovery of $12.9 million of additional revenues in 2005.

Time-of-Use Pilot Project — As required by MPUC orders, NSP-Minnesota has been working to develop a time-of-use pilot project that would attempt to measure customer response and conservation potential of such a program. This pilot project explores providing customers with pricing signals and information that could better inform customers about their use of electricity and its costs. NSP-Minnesota has petitioned the MPUC for recovery of program costs. The 2002 program costs were approximately $2 million. The Department of Commerce has supported deferred accounting to provide for recovery of prudent, otherwise unrecovered and appropriate costs, subject to a normal prudence review process. The Office of the Attorney General has argued that cost recovery should be denied for several reasons. A MPUC hearing was held in January 2004 and requested NSP-Minnesota to further substantiate the prudence and appropriateness of the costs incurred.  The MPUC has voted to allow recovery of the program costs.  An order of the

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MPUC is expected in early 2005.

MISO Cost Recovery Petition — On Dec. 18, 2004, NSP-Minnesota filed a petition to seek recovery of all net costs associated with the implementation of the MISO TEMT through its FCA mechanism.  Under the current mechanism, NSP-Minnesota is allowed full recovery of its fuel and purchased energy costs.  The proposal would allow recovery of locational marginal pricing market costs, including congestion and marginal loss costs, which would be netted by FTR revenues and revenues received that are related to marginal compensation loss costs, as well as MISO energy market operations costs.  NSP-Minnesota has sought recovery effective with the beginning of the Day 2 energy market, scheduled for April 1, 2005 and the deferral of costs incurred prior to MPUC action.  A decision is expected in the second quarter of 2005.

Assuming normal weather during 2005, system peak demand for the NSP System’s electric utility for each of the last three years and the forecast for 2005 is listed below.

The peak demand for the NSP System typically occurs in the summer. The 2004 system peak demand for the NSP System occurred on July 21, 2004.

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 net dependable 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 each 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.

NSP System Resource Plan — On Nov. 1, 2004, NSP-Minnesota filed its 2004 resource plan with 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 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.

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The MPUC initially established a comment period on NSP-Minnesota’s proposed resource acquisition strategy with comments due Dec. 28, 2004 and reply comments due Jan. 17, 2005.  The Department of Commerce has requested an extension to June 1, 2005 to file comments on the overall resource plan.  NSP-Minnesota did not object to this request.

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 are underway and expected to be 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, 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 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.

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 17 to the Consolidated Financial Statements.

Nuclear power plant operation produces gaseous, liquid and solid radioactive substances. The discharge and handling of such substances are controlled by federal regulation.  High-level radioactive substances primarily include used nuclear fuel. Low-level radioactive substance 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 substance. Low-level radioactive substance from NSP-Minnesota’s Monticello and Prairie Island nuclear plants is currently disposed of at the Barnwell facility located in South Carolina (all classes of low-level substance), and 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 substance from out of state.  Envirocare, Inc. operates the Clive facility.  NSP-Minnesota has an annual contract with Barnwell, while NSP-Minnesota uses the Envirocare facility through various low-level substance 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 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 substances. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear substance management. This includes the siting, licensing, construction and operation of a repository for domestically produced spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive substances at a permanent storage or disposal facility. The DOE has accepted none of NSP-Minnesota’s spent nuclear fuel.  See Item 3 — Legal Proceedings and Note 17 to the Consolidated Financial Statements for further discussion of this matter.  The National Commission on Energy Policy, a privately funded coalition, has recommended that the federal government continue to pursue a nuclear waste storage facility in Nevada’s Yucca Mountain and urged them to build multiple above ground dry cask storage sites in the eastern and western United States in case the Yucca Mountain project is delayed or cancelled.

NSP-Minnesota has on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear plants. The Prairie Island plant is 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. The 17 casks, which stand outside the Prairie Island plant, are now full. On May 29,

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2003, the Minnesota Legislature enacted legislation that allows NSP-Minnesota to continue to operate the facility and store spent fuel there until its licenses with NRC expire in 2013 and 2014. This will enable NSP-Minnesota to store at least 12 more casks of spent fuel outside the Prairie Island nuclear generating plant. 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. See Note 17 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. Xcel Energy has placed orders and plans to replace the reactor vessel upper heads of Prairie Island Unit 2 during the 2005 refueling outage and Unit 1 during the 2006 refueling outage.

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 an ASLB and opportunities for public input. Evidentiary hearings were held in 2000 and 2002.  In December 2004, the state of Utah claimed a representative of the DOE stated that it would not accept waste sealed in the type of containers planned by PFS.  PFS responded by providing documents that the DOE will accept fuel stored in dry casks.  The ASLB ruled in February 2005 that it would not reopen the hearing record to consider this issue, indicating it was instead worthy of NRC consideration. The ASLB also issued its decision on the last remaining issue regarding the facility, finding in favor of PFS. NRC commissioners will decide whether to officially issue a license for the site.  The state of Utah has asked the U.S. Supreme Court to consider whether the state of Utah can block PFS from locating a spent fuel storage facility in the state, if the federal government has exclusive control over the storage and transportation of nuclear waste.  The court neither accepted nor declined the appeal filed by the state of Utah, but has sought additional information.  Due to uncertainty regarding NRC and other regulatory and governmental approvals, it is possible that this interim storage may be delayed or not available at all.

Prairie Island Steam Generator Replacement — In the fall of 2004, NSP-Minnesota spent approximately $132 million to successfully replace the steam generators at Unit 1 of the Prairie Island nuclear generating plant.  The steam generators at Unit 2 have not yet been replaced, but will be inspected during a scheduled 2005 outage.

NSP-Minnesota Nuclear Plant Re-licensing — On Aug. 25, 2004, the Xcel Energy board of directors authorized the pursuit of renewal of the operating licenses for the Monticello and Prairie Island nuclear plants. Monticello’s current 40-year license expires in 2010, and Prairie Island’s licenses for its two units expire in 2013 and 2014.  NSP-Minnesota filed its application for Monticello with the MPUC in January 2005 seeking a certificate of need for dry spent fuel storage and plans to file an application in 2005 with the NRC for an operating license extension of up to 20 years.  A decision regarding Monticello re-licensing is expected in 2007. Plant assessments and other work for the Prairie Island applications are planned in the next two or three years.

Nuclear Management Co. (NMC) — During 1999, NSP-Minnesota, Wisconsin Electric Power Co., WPS and Alliant Energy Corp. established NMC. The objective in creating NMC was to enhance operational excellence in nuclear plant operations by consolidating resources, combining talent and gaining efficiencies. The Consumers Power subsidiary of CMS Energy Corp. joined NMC during 2000, and transferred operating authority for the Palisades nuclear plant to NMC in 2001. The five affiliated companies own eight nuclear units on six sites, with total generation capacity exceeding 4,500 MW. WPS is seeking regulatory approval to sell its Kewaunee Nuclear Power Plant to a subsidiary of Dominion Resources, Inc., and may not continue to participate in NMC.  In addition, Alliant Energy has announced that it intends to seek bids to potentially sell the Duane Arnold nuclear plant and, therefore, may not continue to participate in the NMC.

The NRC has approved requests by NMC’s affiliated utilities to transfer operating authority for their nuclear plants to NMC, formally establishing NMC as an operating company. 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. Existing personnel continue to provide day-to-day plant operations, with the additional benefit of implementing best practices from all NMC-operated plants for improved safety, reliability and operational performance.

For further discussion of nuclear issues, see Notes 16 and 17 to the Consolidated Financial Statements.

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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

Fuel Sources — The NSP System normally maintains between 30 and 50 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 13.1 million tons per year. NSP-Minnesota and NSP-Wisconsin have long-term contracts providing for the delivery of up to 97 percent of 2005 coal requirements and up to 59 percent of the 2006 requirements. Coal delivery may be subject to short-term interruptions or reductions due to transportation problems, weather, and availability of equipment.

NSP-Minnesota and NSP-Wisconsin expect that all of the coal burned in 2005 will have an average sulfur content of less than 0.5 percent.  The NSP System has contracts for a maximum of 22.9 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 ranging between 2006 and 2007.  The NSP System could purchase approximately 20 percent of coal requirements in the spot market in 2006 if spot prices are more favorable than contracted prices.

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 46 percent of uranium requirements through 2006 with no coverage of requirements for 2007 and beyond.

•                  Current contracts for conversion services requirements cover 32 percent of the requirements through 2007 with no coverage of requirements for 2008 and beyond.

•                  Current enrichment services contracts cover 55 percent of the requirements through 2010 with no coverage of requirements for 2011 and beyond. These current contracts expire at varying times between 2005 and 2010.

•                  Fuel fabrication for Monticello is covered through 2010.  Fuel fabrication is 100 percent committed for Prairie Island Unit 1 through 2006 and through 2005 for Prairie Island Unit 2.  Both Prairie Island Units are not contracted for fuel fabrication beyond those dates.  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 2010 for uranium and 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- and intermediate-term contracts to provide an adequate supply of fuel.  The NSP System has current fuel oil inventory adequate to meet anticipated 2005 requirements and also has access to the spot market to buy more oil, if needed.

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

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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 subject to regulation 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 and retail gas transmission lines of designated capacities 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.

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.

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 outside a prescribed range, 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.

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

NSP-Wisconsin 2005 Fuel Cost Recovery Filing — On Aug. 2, 2004, NSP-Wisconsin filed an application with the PSCW to reopen its 2004 rate case for the limited purpose of resetting 2005 electric fuel monitoring costs, and to authorize an increase in Wisconsin retail electric rates to recover forecast increases in fuel and wholesale market purchased energy costs.  In its August application, NSP-Wisconsin indicated an increase of $17.3 million was necessary to avoid under-recovering its 2005 fuel costs based on the most recent forecast.  On Dec. 29, 2004, the PSCW issued a final order in the case, authorizing an annual increase of $18.6 million effective Jan. 1, 2005 and resetting the 2005 electric fuel monitoring costs.  Because the PSCW used updated market prices for natural gas, oil and purchased power to forecast 2005 costs, the amount of the increase authorized was greater than initially requested by NSP-Wisconsin.

MISO Cost Recovery — In 2005, NSP-Wisconsin filed a petition along with other Wisconsin utilities seeking deferred accounting treatment for net costs of MISO Day 2 energy market implementation, similar to relief already granted to Wisconsin Public Service Company in their most recent rate case.  In addition, the utilities requested that the PSCW begin the process to change their fuel and energy cost recovery rules to accommodate MISO Day 2 charges.

Assuming normal weather during 2005, system peak demand for the NSP System’s electric utility for each of the last three years and the forecast for 2005 is listed below.

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The peak demand for the NSP System typically occurs in the summer. The 2004 system peak demand for the NSP System occurred on July 21, 2004.

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.

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 subject to the jurisdiction of the CPUC with respect to its facilities, rates, accounts, services and issuance of securities.  PSCo 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.  PSCo has received authorization from the FERC to make wholesale electricity sales at market-based prices.

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

•                  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 then 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.

•                  Incentive Cost Adjustment (ICA) and Interim Adjustment Clause (IAC) — The ICA allowed for an equal sharing between retail electric customers and shareholders of certain fuel and purchased energy costs and expired Dec. 31, 2002. The collection of prudently incurred 2002 ICA costs is being amortized over the period June 1, 2002 through March 31, 2005.  For 2003, the IAC provided for the recovery of prudently incurred fuel and energy costs not included in electric base rates.

•                  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 rider provided recovery of $18 million of capacity costs in 2004 and is expected to provide recovery of $31 million in 2005 and $20 million in 2006.  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.

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•                  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. In February 2004, the FERC approved a revised wholesale fuel adjustment clause for PSCo, which PSCo submitted as part of a settlement agreement with certain of its wholesale customers contesting past charges under PSCo’s prior fuel adjustment clause.

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

•                  an annual electric earnings test with the sharing between customers and shareholders of earnings in excess of the following limits:

•                  all earnings above an 11-percent return on equity for 2001 and a 10.50-percent return on equity for 2002;

•                  no earnings sharing for 2003 as PSCo established new rates in its general rate case; and

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

•                  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 2002, PSCo did not earn a return on equity in excess of 10.5 percent, so no refund liability was recorded.  PSCo did not achieve the 2002 performance targets for the electric service unavailability measure, creating a bill credit obligation for 2002 and increasing the maximum bill credit obligation for subsequent years’ performance.  In December 2004, the CPUC approved a settlement resolving the earnings test for 2002.

•                  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 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 2005.  An estimated customer refund obligation under the electric QSP plan was recorded in 2004 related to the electric service unavailability measure.  No refund under the natural gas QSP is anticipated.

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 are seeking 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 is $4.7 million, of which $3.0 million is attributable to PSCo.  In December 2004, the FERC suspended the filing and delayed the effective date of the proposed increase to May 20, 2005.  The rate increase application also includes PSCo and SPS adopting an annual formula rate for transmission service pricing as previously approved by the FERC for other transmission providers. The case has been set for hearing and settlement procedures.

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California Refund Proceeding — A number of parties purchasing energy in markets operated by the California Independent System Operator (California ISO) or the California Power Exchange (PX) have asserted prices paid for such energy were unjust and unreasonable and that refunds should be made in connection with sales in those markets for the period Oct. 2, 2000 through June 20, 2001. PSCo supplied energy to these markets during this period and has been an active participant in the proceedings. The FERC ordered an investigation into the California ISO and PX spot markets and concluded that the electric market structure and market rules for wholesale sales of energy in California were flawed and have caused unjust and unreasonable rates for short-term energy under certain conditions. The FERC ordered modifications to the market structure and rules in California and established an ALJ to make findings with respect to, among other things, the amount of refunds owed by each supplier based on the difference between what was charged and what would have been charged in a more functional market, i.e., the “market clearing price,” which is based on the unit providing energy in an hour with the highest incremental cost. The initial proceeding related to California’s demand for $8.9 billion in refunds from power sellers. The ALJ subsequently stated that after assessing a refund of $1.8 billion for power prices, power suppliers were owed $1.2 billion because the state was holding funds owed to suppliers.

Certain California parties sought rehearing of this decision. Among other things, they asserted that the refund effective date should be set at an earlier date. They have based this request in part on the argument that the use by sellers of certain trading strategies in the California market resulted in unjust and unreasonable rates, thereby justifying an earlier refund effective date. The FERC subsequently allowed the purchasing parties to request from sellers, including PSCo, additional information regarding the market participants’ use of certain strategies and the effect those strategies may have had on the market. Based on the additional information they obtained, these purchasing entities argued to the FERC that use of these strategies did justify an earlier refund effective date. These California entities have contended that PSCo would owe approximately $17 million in refunds, if the FERC set the earlier refund effective date. In October 2003, the FERC determined that the refund effective date should not be reset to an earlier date, and gave clarification of how refunds should be determined for the previously set refund period. Certain California parties appealed the FERC’s decision not to establish an earlier refund effective date to the United States Court of Appeals for the Ninth Circuit.

In a related case, certain California parties also appealed the FERC orders dismissing a complaint by the California Attorney General challenging market-based rates as inconsistent with the Federal Power Act. The California Attorney General also argued that wholesale sellers, including PSCo, were violating their market-based rate authorizations by not reporting their market-based sales on an individual transaction basis. Prior to a clarification of its rules, most sellers, including PSCo, reported their transactions on an aggregate basis. On Sept. 9, 2004, the United States Court of Appeals for the Ninth Circuit issued an opinion rejecting the California Attorney General’s general challenge to market-based rates, but agreeing with its challenge regarding the failure to report individual transactions. It remanded the case to the FERC to consider action to take to address these failures and indicated that the FERC could require refunds.  Several of the intervenors in this appeal filed a petition for rehearing of this decision in October 2004.  The rehearing request is pending at the U.S. Court of Appeals for the Ninth Circuit.

Further, several actions in California state courts involve similar issues, challenging wholesale sales made at market-based rates in the California markets.  These proceedings, filed in federal court in California and in the Superior Court of the State of California for the County of San Francisco, allege, among other causes of action, violations of California Business and Professions Code Section 17200 by Xcel Energy and a number of other suppliers and traders of wholesale power.  The essence of the complaints are that the defendants allegedly manipulated the market for electricity by fixing prices and restricting supply into the California markets, or by engaging in other conduct for the purpose of artificially inflating the price of electricity, and/or by charging unlawful prices for such electricity.  Although these proceedings were dismissed, and appeals were denied by the Ninth Circuit, Petitions for Writ of Certiorari have been filed with the United States Supreme Court.  The Supreme Court has not yet acted on the Writ Petitions.

PSCo has accrued its estimated minimum liability related to these cases.  Because of the low volume of sales that PSCo had into California, its exposure is estimated to be approximately $7 million.  The FERC has encouraged buyers and sellers in the organized California markets to try to resolve these cases through settlement, and PSCo is presently having settlement negotiations with various California entities to try to reach a comprehensive resolution of these cases.

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.

FERC Investigation Against Wholesale Electric Sellers — On June 25, 2003, the FERC issued two show cause orders addressing alleged improper market behavior in the California electricity markets. In the first show cause order, the FERC found that 24 entities may have worked in concert through partnerships, alliances or other arrangements to engage in activities that constitute gaming and/or anomalous market behavior. The FERC initiated proceedings against these 24 entities requiring that they show cause why their behavior did not constitute gaming and/or anomalous market behavior. PSCo was not named in this order. In a second show cause order, the FERC indicated that various California parties, including the California ISO, have alleged that 43 entities individually engaged in one or more of seven specific types of practices that the FERC has identified as constituting gaming or anomalous market behavior within the meaning of the California ISO and California Power Exchange tariffs. PSCo was listed in an attachment to that show cause order as having been alleged to have engaged in one of the seven identified practices, namely circular scheduling. Subsequent to the show cause order, PSCo provided information to the FERC staff showing PSCo did not engage in circular scheduling. Subsequently, certain California parties requested that FERC make PSCo subject to the show cause proceeding addressing

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partnerships and expand the scope of the show cause order addressing gaming and/or anomalous market behavior to have PSCo address an allegation that it engaged in another of the specified activities, namely “load shift.”

On Aug. 29, 2003, the FERC trial staff filed a motion to dismiss PSCo from the show cause proceeding.  On Jan. 22, 2004, the FERC granted motions to dismiss certain parties, including PSCo, of the show cause proceedings addressing the use of gaming or anomalous market behavior.  The FERC on that same day in a separate order also rejected requests to expand the scope of the show cause proceedings addressing partnerships.  On Feb. 23, 2004, certain California parties sought rehearing of the FERC’s order addressing gaming or anomalous market behavior.  That matter is still pending before the FERC.  Certain California parties also filed appeals of the FERC’s order addressing partnerships, and that matter is pending.

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 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.

Electric Department Earnings Test and CPUC Reliability Inquiry — As a part of PSCo’s annual electric earnings test, the CPUC opened a docket to consider whether PSCo’s cost of debt has been adversely affected by the financial difficulties at NRG and, if so, whether any adjustments to PSCo’s cost of capital are appropriate.

In December 2004, the CPUC approved a settlement resolving the earnings test and providing for PSCo’s recovery of the actual cost of debt.  It requires PSCo to spend an incremental $38 million, which will be included in rate base in future rate filings, in capital expenditures over the next three years to improve system reliability and contribute $2 million to Energy Outreach Colorado, a non-profit energy assistance organization.

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 2004, PSCo filed its calendar year 2003 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 2003 performance targets for the electric service unavailability measure or the customer complaint measure. Additionally, PSCo filed revisions to its previously filed 2002 electric QSP results for the service unavailability measure. Based on the revised results, PSCo did not achieve the 2002 performance targets for the electric service unavailability measure, creating a bill credit obligation for 2002 and increasing the maximum bill credit obligation for subsequent years’ performance.

As of Dec. 31, 2003, PSCo had accrued an aggregate estimated bill credit obligation of $6.4 million for the 2002 and 2003 calendar years. Based on the updated information and filings discussed above, during the second quarter of 2004, PSCo increased its estimated bill credit liability for these years to $13.4 million. PSCo posted the bill credits to retail customer accounts in the third quarter of 2004. For calendar year 2004, PSCo has evaluated its performance under the QSP and has recorded a liability of $11 million.  Under the electric QSP, the estimated maximum potential bill credit obligation for calendar 2004 performance is approximately $15.2 million, assuming none of the performance targets are met.  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.

Incentive Cost Adjustment and Interim Adjustment Clause — PSCo’s ICA mechanism was in place for periods prior to 2003.  The costs included in the ICA were subject to review by the CPUC.  In a CPUC docket reviewing the 2001 ICA, the CPUC approved a settlement that, among other things, provided for a prospective revenue adjustment related to the maximum allowable natural gas hedging costs that would be a part of the electric commodity adjustment for 2004, which reduced 2004 rates by $4.6 million.  In 2004,

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the CPUC approved the 2002 fuel and purchased energy costs reflected in the ICA.  PSCo agreed to amortize the 2002 ICA costs over the period of June 2002 through March 2005.  In 2003, PSCo’s prudently incurred fuel and purchased energy costs were fully recoverable under the IAC and are still subject to a future review by the CPUC.  On Aug. 2, 2004, PSCo applied to the CPUC for approval of its 2003 fuel and purchased energy costs.  This application is pending before the CPUC.

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

PSCo, the staff of the CPUC and the OCC reached full settlement of the disputed issues on Sept. 10, 2004. The CPUC approved the settlement on Oct. 5, 2004. The settlement modifies the rules governing trading transactions to provide more specificity as to transaction priorities, record retention and cost assignment.  The CPUC acknowledged the benefit of commodity trading.  Consequently, the settlement provides for continuation of electric commodity trading as currently conducted by PSCo, and permits PSCo to begin trading natural gas as a risk mitigation measure in support of its electric trading.  PSCo anticipates commencing natural gas trading activities as permitted by the settlement in the first half of 2005.  The settlement also provides for the margin sharing mechanisms that are currently in place in the PSCo retail rates to continue through 2006. Finally, the settlement requires the cooperative development of auditing processes to provide the staff of the CPUC with information regarding PSCo’s trading operations and for the filing of monthly reports with respect to these trading operations.  This proceeding is now complete.

Assuming normal weather during 2005, system peak demand for the PSCo’s electric utility for each of the last three years and the forecast for 2005 is listed below.

The peak demand for PSCo’s system typically occurs in the summer.  The 2004 system peak demand for PSCo occurred on July 13, 2004.

PSCo expects to meet its net dependable 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 each 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 40 percent of its total electric system energy needs for 2005 and generate the remainder with PSCo-owned resources.  Approximately 47 percent of PSCo’s total system electric generation

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capacity for 2005 will be provided by purchased power.

On April 30, 2004, PSCo filed its 2003 least-cost resource plan (LCRP) with the CPUC.  PSCo had identified that it needs to provide for 3,600 MW of capacity through 2013 to meet load growth and replace expiring contracts.  Of the amount needed, PSCo believes 2,000 MW will come from new resources, and 1,600 MW will come from entering into new contracts with existing suppliers whose contracts expire during the resource acquisition period.

On Dec. 17, 2004, the CPUC approved a settlement agreement between PSCo and many intervening parties concerning the LCRP.  PSCo received the formal written decision of the CPUC in January 2005.  The CPUC approved PSCo’s plan to construct a 750-MW pulverized coal-fired unit at the Comanche Station located near Pueblo, Colo. and transfer up to 250 MW of capacity ownership from the 750-MW unit to Intermountain Rural Electric Association and Holy Cross Energy, if negotiations with those entities are successful.  The settlement agreement also enables PSCo to acquire resources through an all-source competitive bidding process.

Among other things, the approved settlement allows for additional emission controls to be installed and associated costs to be collected from customers at Comanche Station’s two existing coal-fired units.  The settlement contains a confidential construction cost cap for the construction of the 750-MW Comanche 3 unit.  It also includes a regulatory plan that authorizes PSCo to increase the equity component of its capital structure to 56 percent in its 2006 rate case to offset the debt equivalent value of PSCo’s existing purchased power agreements and to otherwise improve PSCo’s financial strength.  Depending upon PSCo’s senior unsecured debt rating during the time of PSCo general rates cases, the approved settlement permits PSCo to include various amounts of construction work in progress in rate base without an allowance for funds used during construction offset associated with the Comanche 3 generating unit, additional emission controls on the Comanche 1 and 2 generating units and associated transmission.  PSCo agreed to invest in additional demand-side management, accelerate the completion of an ongoing wind-saturation study and fund environmental programs in Pueblo, Colo.

In a separate docket, the CPUC granted PSCo’s request for approval of a 500-MW renewable energy solicitation.  PSCo issued a request for proposal, with bids to be submitted in November 2004.  PSCo is currently negotiating contracts with bidders of approximately 328 MW of renewable energy.

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 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.

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.

Fuel Sources  — PSCo’s generation stations use low-sulfur western coal purchased primarily under long-term contracts with suppliers operating in Colorado and Wyoming. During 2004, PSCo’s coal requirements for existing plants were approximately 9.8 million tons, a substantial portion of which was supplied pursuant to long-term supply contracts. Coal supply inventories at Dec. 31, 2004 were approximately 41 days usage, based on the average burn rate for all of PSCo’s coal-fired plants.

PSCo operates the Hayden generating plant in Colorado.  All of Hayden’s coal requirements are supplied under a long-term agreement.  The Hayden facility is located in close proximity to a coal mine, which has historically provided the coal to fulfill Hayden’s fuel requirements under the long-term agreement.  The mine operator has announced that the mine will close near the end of

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2005.  PSCo is currently investigating a number of alternatives to provide for an uninterrupted, economical fuel supply to the facility.  It is anticipated that total fuel costs will increase following the closure of the mine, however, the amount of increased costs, if any, cannot be determined at this time.  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.

PSCo has contracted for coal suppliers to supply approximately 98 percent of the Cherokee, Cameo, Valmont and remaining Craig stations’ projected requirements in 2005.

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 94 percent of Arapahoe station’s projected requirements for 2005. Any remaining Arapahoe station requirements will be procured via spot market purchases.

PSCo has a number of coal transportation contracts, which expire over the course of 2005.  PSCo is currently in the process of negotiating new transportation agreements.  The ability to negotiate for coal transportation is not anticipated to impede the operation of PSCo’s coal-based generation facilities.  However, it is expected that coal transportation costs will increase.  Currently, the impact or extent of the increase cannot be determined.

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 to provide an adequate supply of fuel.

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.

SPS

Ratemaking Principles

Summary of Regulatory Agencies and Areas of Jurisdiction — The PUCT has jurisdiction over SPS’ Texas operations as an electric utility and over its retail rates and services. The municipalities in which SPS operates in Texas have original 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.

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.  In July 2003, a unanimous settlement was reached providing for the implementation of an expedited procedure for revising the fixed fuel factors on a semi-annual basis.  As a result, 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 such fuel and purchased energy, fuel acquisition and management policies and purchase energy commitments.  Under the PUCT’s regulations, SPS is required to file an application for the PUCT to retrospectively review at least every three years the operations of SPS’ electric

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generation and fuel management activities.

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 beginning with the February 2002 billing cycle.  In accordance with the NMPRC regulations, SPS must file its next New Mexico fuel factor continuation case no later than August 2005 for the period from October 2001 through April 2005.

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, 2004, SPS accrued  $800,000 to reflect the expected refund obligation for those measures.

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 OATT. PSCo and SPS are seeking 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 is $4.7 million, of which $1.7 million is attributable to SPS.  In December 2004, the FERC suspended the filing and delayed the effective date of the proposed increase to May 20, 2005.  The FERC also initiated a complaint proceeding against SPS, which would allow the FERC to order reductions below SPS’ currently effective rates.  The rate increase application also includes PSCo and SPS adopting an annual formula rate for transmission service pricing as previously approved by the FERC for other transmission providers. The case has been set for hearing and settlement procedures.

SPS Wholesale Rate Complaint — 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 clause calculations.  In December 2004, the FERC accepted the complaint filing and ordered SPS base rates subject to refund, effective Jan. 1, 2005.  Also in November 2004, SPS filed revisions to its wholesale fuel cost adjustment clause.  The FERC set the proposed rate changes into effect on Jan. 1, 2005, subject to refund, and consolidated the proceeding with the wholesale cooperative customers’ complaint proceeding.  The FERC set the consolidated proceeding for hearing and settlement judge procedures.

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 under FERC Order No. 2000. In addition, SPP made unilateral changes to the existing SPP membership agreement, which increases the current costs of SPS membership in SPP by approximately $1.5 million per year, in order to fund the start of RTO operations. On Feb. 10, 2004, the FERC conditionally approved SPP’s proposed formation as an RTO, subject to SPP meeting certain requirements.  On Oct. 1, 2004, the FERC issued a further order granting the SPP status as an RTO.  SPP is expected to commence RTO operations on Oct. 1, 2005.  SPS is required to obtain NMPRC approval before it can transfer functional control of its electrical transmission system.  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.

Texas Retail Fuel Cost  — Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor.  In May 2004, SPS filed with the PUCT its periodic request for fuel and purchased power cost recovery for electric generation and fuel management activities for the period from January 2002 through December 2003.  SPS requested approval of approximately $580 million of Texas-jurisdictional fuel and purchased power costs for the two-year period.  Intervenor and PUCT staff testimony was filed in October 2004 and hearings were held in December 2004.  Intervenor testimony contained objections to SPS’ methodology for assigning average fuel costs to wholesale sales, among other things.  Recovery of $49 million to $86 million of the requested amount was contested by multiple intervenors.  SPS has recorded its best estimate of any potential liability related to the impact of this proceeding.  In January 2005, SPS filed its post-hearing briefs disputing the intervenor objections.  Reply briefs were

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filed on Feb. 15, 2005, the administrative law judge is expected to issue his recommended proposal for decision by the end of April 2005, and PUCT action is expected by the end of May 2005.  SPS is pursuing a settlement agreement with the parties involved.

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

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

On Nov. 5, 2004, SPS submitted another fuel cost surcharge application with the PUCT for $30 million of fuel cost under-recoveries accrued from April 2004 through September 2004.  These under-recoveries under the Texas retail fixed fuel collection process are primarily the result of higher than expected natural gas prices.  SPS is also proposing in its November 2004 filing to increase its semi-annual fuel factors to take into account the increased cost of natural gas at its gas-fueled power plants.  In January 2005, parties to the application reached a settlement agreement allowing SPS to collect the $30 million fuel cost under-recoveries through a surcharge during the 12-month period beginning May 2005.  The PUCT is expected to approve the settlement in March 2005.

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.

Assuming normal weather during 2005, system peak demand for the SPS’ electric utility for each of the last three years and the forecast for 2005 is listed below.

The peak demand for the SPS system typically occurs in the summer.  The 2004 system peak demand for SPS occurred on Aug. 4, 2004.

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 each 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

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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 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.

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.

Fuel Sources — SPS purchases all of its coal requirements for 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’s 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 Dec. 31, 2016. For the Tolk station, the coal supply contract with TUCO expires Dec. 31, 2017.  At Dec. 31, 2004, coal supplies at the Harrington and Tolk sites were approximately 25 and 24 days supply, respectively. TUCO has coal supply agreements to supply 100 percent of the projected 2005 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.

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.  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, and the purchase of natural gas from, 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 are 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 1994 to 2004, average annual sales to the typical residential customer declined from 108 Dth per year to 89 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 subject to the jurisdiction of 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 has the authority to disallow recovery of certain costs if it finds 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.

NSP-Minnesota Retail Gas Rate Case — On Sept. 17, 2004, NSP-Minnesota submitted a $10 million natural gas general rate increase request to the MPUC with a requested ROE of 11.5 percent.  An interim rate increase, subject to refund, of approximately $6.4 million was implemented effective Dec. 1, 2004.  The administrative law judge held a pre-hearing conference and established a procedural schedule, with an MPUC decision expected in mid-2005.  The Department of Commerce filed testimony in February 2005 recommending an increase of $1 million.  NSP-Minnesota plans to file its rebuttal testimony on March 15, 2005.

North Dakota Retail Gas Rate Case — On Nov. 2, 2004, NSP-Minnesota submitted a natural gas general rate increase application to the NDPSC.  The filing proposes an overall increase in annual revenues of $1.3 million, exclusive of natural gas supply costs, or 1.8

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percent.  On Dec. 1, 2004, the NDPSC issued an order approving a $0.7 million interim rate increase, or 1.1 percent, effective Jan. 1, 2005.  The NDPSC staff is scheduled to file its testimony in March 2005, and the NDPSC will conduct evidentiary hearings in April 2005.  The NDPSC is required to issue its order by June 2, 2005.  On Feb. 17, 2005, NSP-Minnesota and the NDPSC staff filed a settlement agreement with the NDPSC.  Under the terms of the settlement, the NDPSC can elect one of two alternatives.  The alternatives are a $745,000 rate increase and a $15.70 monthly residential service charge or an $887,000 rate increase with an $8.75 monthly residential service charge.  The NDPSC is expected to consider the settlement agreement at a hearing in March 2005.

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 647,547 MMBtu for 2004, which occurred on Jan. 29, 2004.

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 approximately 506,391 MMBtu/day. In addition, NSP-Minnesota has contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 16 percent of winter natural gas requirements and 19 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 2003-2004 entitlement levels were approved on Sep. 2, 2004, which allow NSP-Minnesota to recover the demand entitlement costs associated with the increase in transportation, supply, and storage levels in its monthly PGA. The 2004-2005 entitlement levels are pending MPUC action.

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 various cost recovery adjustment mechanisms.

NSP-Minnesota has firm natural gas transportation contracts with several pipelines, which expire in various years from 2005 through 2017.

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, 2004, NSP-Minnesota was committed to approximately $1.09 billion in such obligations under these contracts.

NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 35 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Minnesota to maintain competition from suppliers and minimize supply costs.

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NSP-Wisconsin

Ratemaking Principles

Summary of Regulatory Agencies and Areas of Jurisdiction — NSP-Wisconsin is subject to retail rate and other regulation by the PSCW and the MPSC.  In addition, each of the state commissions certifies the need for new retail gas transmission lines of designated capacities to be located within the respective states before the facilities may be sited and built.

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.

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 153,423 MMBtu for 2004, which occurred on Jan. 29, 2004.

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 124,492 MMBtu/day. In addition, NSP-Wisconsin has contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 23 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 2004-2005 supply plan was approved by the PSCW in October 2004.

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.

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NSP-Wisconsin has firm natural gas transportation contracts with several pipelines, which expire in various years from 2005 through 2013.

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, 2004, NSP-Wisconsin was committed to approximately $129 million in such obligations under these contracts.

NSP-Wisconsin purchased firm natural gas supply utilizing long-term and short-term agreements from approximately 35 domestic and Canadian suppliers.  This diversity of suppliers and contract lengths allows NSP-Wisconsin to maintain competition from suppliers and minimize supply costs.

PSCo

Ratemaking Principles

Summary of Regulatory Agencies and Areas of Jurisdiction — PSCo is subject to the jurisdiction of 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. Effective Nov. 1, 2004, the GCA is revised monthly to allow for changes in gas rates.  Previously, the GCA rate was revised at least annually to coincide with changes in purchased gas costs.

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.

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 1,781,088 MMBtu. In addition, firm transportation customers hold 477,419 MMBtu for PSCo of capacity without supply backup.  Total firm delivery obligation for PSCo is 2,258,507 MMBtu per day. The maximum daily deliveries for PSCo in 2004 for firm and interruptible services were 1,860,958 MMBtu on Jan. 5, 2004.

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 1,792,543 MMBtu/day, which includes 826,866 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 received approval and is in the process of closing the Leyden Storage Field. The field’s 110,000 MMBtu peak day capacity was replaced with additional third-party storage and transportation capacity. See further discussion at Note 16 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 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.

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.

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The following table summarizes the average cost per MMBtu of natural gas purchased for resale by PSCo’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.

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, 2004, PSCo was committed to approximately $1.5 billion in such obligations under these contracts, which expire in various years from 2005 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. PSCo also utilizes a mixture of fixed-price purchases and index-related purchases to provide a less volatile, yet market-sensitive, price to its customers. During 2004, PSCo purchased natural gas from approximately 37 suppliers.

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Xcel Energy Gas Operating Statistics

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NONREGULATED SUBSIDIARIES

Through non-utility subsidiaries, Xcel Energy invested in and operated several nonregulated businesses in a variety of industries.  At Dec. 31, 2004, Xcel Energy has divested its ownership interest in all significant non-utility subsidiaries.  The following is an overview of nonregulated businesses, which are reported as components of continuing operations.