NORTHERN STATES POWER CO - 10-K Annual Report

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. Yes [X] No [ ]

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes [ ] No [X]

Northern States Power Co. (a Minnesota corporation), Northern States Power Co. (a Wisconsin corporation), Public Service Co. of Colorado and Southwestern Public Service Co. meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to such Form 10-K.

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. All outstanding common stock is owned beneficially and of record by Xcel Energy Inc., a Minnesota corporation. Shares outstanding at Feb. 21, 2003:

This combined Form 10-K is separately filed by Northern States Power Co., a Minnesota corporation (NSP-Minnesota); Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin); Public Service Co. of Colorado (PSCo); and Southwestern Public Service Co. (SPS). NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are all wholly owned subsidiaries of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the U.S. Securities and Exchange Commission (SEC). Information in this report relating to any individual company is filed by such company on its own behalf. Each registrant makes representation only to itself and makes no representations as to information relating to the other registrants. This report should be read in its entirety.

In 2003, Xcel Energy Inc. (Xcel Energy) directly owned five utility subsidiaries that serve electric and natural gas customers in 11 states. Four of these utility subsidiaries are SEC registrants, including Northern States Power Co., a Minnesota corporation (NSP-Minnesota); Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin); Public Service Co. of Colorado, a Colorado corporation (PSCo); and Southwestern Public Service Co., a New Mexico corporation (SPS).

NSP-Minnesota was incorporated in 2000 under the laws of Minnesota. 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, distributes and sells natural gas to retail customers and transports customer-owned natural gas in Minnesota and North Dakota. NSP-Minnesota provides electric utility service to approximately 1.3 million customers and gas utility service to approximately 440,000 customers.

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 Nuclear Management Co. 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 235,000 customers in northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan. NSP-Wisconsin is also engaged in the distribution, sale and transport of customer-owned natural gas in the same service territory to approximately 95,000 customers.

NSP-Wisconsin owns the following direct subsidiaries: Chippewa and Flambeau Improvement Co., which operates hydro reserves; 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 principally in the generation, purchase, transmission, distribution and sale of electricity and the purchase, transportation, distribution and sale of 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; PSR Investments, Inc., which owns and manages permanent life insurance policies on certain employees; and Green and Clear Lakes Co., 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 38 percent of the total kilowatt-hour sales. A major portion of SPS’ retail electric operating revenues is derived from operations in Texas.

At Dec. 31, 2003, SPS owned a direct subsidiary, Southwestern Public Service Capital I (SPS Capital I), a special purpose financing trust, for which a certificate of cancellation was filed for dissolution on Jan. 5, 2004.

The utility subsidiaries of Xcel Energy are subject to the regulatory oversight of the SEC under the Public Utility Holding Company Act of 1935 (PUHCA). The rules and regulations under the 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.

The Federal Energy Regulatory Commission (FERC) has jurisdiction over rates for electric transmission service in interstate commerce and electric energy sold at wholesale, hydro facility licensing, accounting practices and certain other activities of Xcel Energy’s utility subsidiaries. Federal, state and local agencies also have jurisdiction over many of the utility subsidiaries’ other activities, including regulation of retail rates and environmental matters.

The utility subsidiaries of Xcel Energy are unable to predict the impact on their operating results from the future regulatory activities of any of these agencies. The utility subsidiaries of Xcel Energy are responsible for compliance with all rules and regulations issued by the various agencies.

Retail rates, services and other aspects of NSP-Minnesota’s operations are subject to the jurisdiction of the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC) and the South Dakota Public Utilities Commission (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 and gas supply plans for meeting customers’ future energy needs. The MPUC also certifies the need for generating plants greater than 50 megawatts and transmission lines greater than 100 kilovolts. 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 electricity sales at market-based prices.

The Minnesota Environmental Quality Board (MEQB) is empowered to select and designate sites for new power plants with a capacity of 50 megawatts or more and wind energy conversion plants with a capacity of five megawatts or more. It also designates routes for electric transmission lines with a capacity of 100 kilovolts 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 has 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.

NSP-Wisconsin is subject to regulation by the Public Service Commission of Wisconsin (PSCW) and the Michigan Public Service Commission (MPSC). 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 electricity 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 two-year 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.

PSCo is subject to the jurisdiction of the Colorado Public Utilities Commission (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. Also, 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.

The Public Utility Commission of Texas (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 New Mexico Public Regulation Commission (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.

NSP-Minnesota’s retail electric rate schedules in Minnesota, North Dakota and South Dakota jurisdictions provide for monthly adjustments to billings and revenues for changes in prudently incurred cost of fuel and purchased energy. NSP-Minnesota is permitted to recover these costs through fuel clause mechanisms individually approved by the regulators in each jurisdiction. The fuel clause mechanisms allow NSP-Minnesota to bill customers for the cost of fuel used to generate electricity at its plants and energy purchased from other suppliers. In general, capacity costs are not recovered through the fuel clause adjustment. NSP-Minnesota’s electric wholesale customers do not have a fuel clause provision in their contracts. Instead, the contracts have an annual price escalation factor subject to a rate cap.

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’s retail gas rate schedules for Minnesota and North Dakota include a purchased gas adjustment (PGA) clause that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased gas. The annual difference between the gas costs collected through PGA rates and the actual 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 2 percent of Minnesota electric revenue and 0.5 percent of Minnesota gas revenue on conservation improvement programs. These costs are recovered through an annual cost recovery mechanism for electric and gas conservation and energy management program expenditures. NSP-Minnesota is required to request a new cost recovery level annually.

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

PSCo has several retail adjustment clauses that recover fuel, purchased energy and resource costs:

	•		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. During 2003, the IAC provided for the recovery of prudently incurred fuel and energy costs not included in electric base rates.

	•		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.

	•		Gas Cost Adjustment (GCA) - The GCA allows PSCo to recover its actual costs of purchased gas. The GCA rate is revised at least annually to coincide with changes in purchased gas costs. In 2002, PSCo requested to modify the GCA to allow for monthly changes in gas rates. A final decision in this proceeding is expected in 2004.

	•		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 annually to coincide with changes in fuel costs.

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

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

	•		Qualifying facilities capacity cost adjustment (QFCCA) - The QFCCA provides for recovery of purchased capacity costs from certain qualified facilities not otherwise reflected in base electric rates. The QFCCA expired in April 2003, but remained under collected as of Dec. 31, 2003 by $1.4 million. According to the 2002 PSCo General Rate Case Settlement Agreement, PSCo is entitled to recover the remaining balance through a recovery mechanism to be proposed once the final balance is determined.

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.

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. The Texas retail fuel factors will 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. In 2003, SPS has received approval and implemented two fuel surcharge applications in Texas to recover additional fuel cost under-recoveries totaling approximately $28.9 million.

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 generation and fuel management activities. In May 2003, a stipulation was approved by the PUCT, resolving all issues regarding SPS’ fuel costs and wholesale trading activities from January 2000 through December 2001. The parties agreed that SPS would reduce its December 2001 fuel under-recovery balances by $5.8 million. The net impact to SPS’ income, before tax, was a reduction of $4.7 million recorded in 2003. SPS has agreed to file its next reconciliation for electric generation and fuel management activities for the period from January 2002 through December 2003 by June 2004.

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.

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

See discussions of regional transmission organizations (RTO) at Electric Utility Operations below.

“PLUS” Performance-Based Regulation — In December 2000, the NDPSC approved NSP-Minnesota’s “PLUS” performance-based regulation proposal, effective January 2001, for its electric operations in North Dakota. The plan established operating and service performance standards in the areas of system reliability, customer satisfaction, price and worker safety. NSP-Minnesota’s performance determines the range of allowed return on equity for its North Dakota electric operations. The plan will generate refunds or surcharges when earnings fall outside of the allowed return on equity range. The PLUS plan will remain in effect through 2005. In late 2003, NSP-Minnesota proposed certain changes to the performance indices for the 2004 and 2005 plan years, but it is unknown if the NDPSC will approve the changes.

Metro Emissions Reduction Program (MERP) — On Dec. 18, 2003, the MPUC approved NSP-Minnesota’s 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. The program includes the installation of state-of-the-art pollution control equipment at the A. S. King plant and conversion of the High Bridge and Riverside plants to use natural gas rather than coal. These improvements are expected to significantly reduce air emissions from these facilities, while increasing the capacity at system peak by 300 megawatts. Major construction is expected to start in 2005 and be completed in 2009. 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 return on equity (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.

Other regulatory approvals, such as environmental permitting, are needed before the proposal can be implemented.

The CPUC established an electric Performance-Based Regulatory Plan (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 quality of service plan (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 2001, PSCo did not earn a return on equity in excess of 11 percent and met the electric and gas QSP benchmarks. The CPUC has accepted the QSP components of the PBRP filing and approved the earnings test.

	•		In 2002, PSCo did not earn a return on equity in excess of 10.5 percent, so no refund liability has been recorded. Both electric and gas QSP benchmarks were met. Therefore, no liability has been recorded for the earnings test. A CPUC decision is pending. The CPUC is considering whether PSCo’s cost of debt has been adversely affected by the financial difficulties of NRG, and if so, whether any adjustments to PSCo’s cost of capital should be made. A hearing has been set for August 2004.

	•		PSCo expects to file the 2003 QSP results in April 2004. An estimate of customer refund obligations under the electric QSP plan was recorded in 2003 relating to the electric service unavailability and customer complaint measures. No refund under the gas QSP is anticipated.

In 2003, PSCo filed an application to put into effect a purchased-capacity cost-adjustment mechanism that would allow it to recover 100 percent of its incremental purchased-capacity costs over the level of these costs in rates. As a part of this application, PSCo proposed to modify the PBRP for 2004 through 2006 to provide that 100 percent of any earnings in excess of a 10.75-percent return on equity for electric operations be returned to customers. The application is pending approval of the CPUC.

Texas Earnings Test — Prior to June 2001, SPS operated under an earnings test in Texas, which required all excess earnings to be refunded to retail customers. SPS did not operate under an earnings test in Texas in 2003, 2002 or the remainder of 2001.

Texas Service Reliability — As a result of the order approving the merger to form Xcel Energy in August 2000, the PUCT requires that SPS meet certain service reliability standards and telephone response time standards. If these standards are not met, SPS is subject to a maximum annual rebate to customers of $950,000. The rebate is credited to the customer’s electric bill if they are served by one of the distribution feeders that fail to meet the service reliability standard. However, the rebate for the telephone response time standard, if not met, is refunded on a per capita basis to all customers. Refunds for 2002 and 2001 were $800,000 and $756,000, respectively. The 2003 refunds are expected to be less than $300,000.

Texas-New Mexico Power Company (TNP) Acquisition Surcharge — In September 1995, SPS acquired the Texas Panhandle properties of TNP and has been surcharging the acquisition premium to those specific customers. At the end of 2003, SPS had $214,000 remaining to collect of the $15.3 million total amount related to the TNP acquisition. SPS expects to have collected the remaining TNP acquisition amount in the first quarter of 2004, at which time the surcharge will terminate. The expiration of the TNP Surcharge is expected to reduce revenue by approximately $1.4 million in 2004.

Section 206 Investigation Against of All Wholesale Electric Sellers — In November 2001, 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. NSP-Minnesota, NSP-Wisconsin, PSCo, and SPS previously received FERC authorization to make wholesale sales at market-based rates, and have been engaged in such sales subject to a tariff on file at the FERC. The order proposed that all wholesale electric sales at market-based rates conducted starting 60 days after publication of the FERC order in the Federal Register would be subject to refund conditioned on factors determined by the FERC. In December 2001, the FERC issued a supplemental order delaying the effective date of the subject-to-refund condition, but subject to further investigation and proceedings.

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 makes sales at market-based rates.

Additionally, in connection with their market-based rate authority, NSP-Minnesota, NSP-Wisconsin, PSCo and SPS have an obligation to file, on a periodic basis, an updated market power analysis based on a supply margin assessment (SMA). Xcel Energy, on behalf of itself and the Xcel Energy operating companies with market-based rate authority, filed such an updated market power analysis on Jan. 6, 2004. The analysis shows that the Xcel Energy operating companies with market-based rate authority do not have undue market power, based on application of the FERC market power assessment screen (the SMA screen). However, the FERC is presently evaluating on a generic basis continued use of the SMA screen. The Xcel Energy analysis showed that if the screen is modified to take into account load obligations, the Xcel Energy companies do not possess market power. Depending on what market screen it ultimately adopts, the FERC may deny the Xcel Energy operating companies continued market-based rate authority, or, more likely, make continued authorization subject to certain mitigation in certain geographic markets.

SEC Trading Investigation - Pursuant to a formal order of investigation, on June 26, 2002, the SEC issued a subpoena to Xcel Energy requesting all documents concerning any so-called “round trip trades” with Reliant Resources, Inc. Pursuant to another formal order of investigation, on Oct. 3, 2002, the SEC issued a subpoena to Xcel Energy calling for additional information concerning certain energy trades between Xcel Energy on the one hand and Duke Energy Corporation and Mirant Corporation on the other, involving the same product, quantity and price executed on the same day. Xcel Energy and PSCo have produced documents and have cooperated in these investigations, but cannot predict the outcome of any investigation.

FERC Transmission Inquiry — In October 2002, the FERC Office of Market Oversight and Investigations began a formal, non-public standard industry inquiry relating to the treatment by certain public utility companies of affiliates in generator interconnection and other transmission matters. In connection with the inquiry, the FERC asked Xcel Energy’s utility subsidiaries for certain information and documents. Xcel Energy’s utility subsidiaries have responded to the requests. This standard audit process is pending.

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 basis with an annual true-up.

On Sept. 24, 2003, NSP-Minnesota and the state agencies announced that they had reached a settlement agreement that would be submitted to the MPUC for its approval. Among the provisions are:

	•		$1 million in refunds to Minnesota customers who have experienced the longest duration of outages, which have been accrued at Sept. 30, 2003;

	•		additional actions to improve system reliability in an effort to reduce outage frequency and duration. These actions, including tree trimming and cable replacement, will target the primary outage causes. At least an additional $15 million, above amounts being currently recovered in rates, is to be spent in Minnesota on these outage prevention improvements by Jan. 1, 2005; and

	•		development of a revised service quality plan containing a standard for service outage documentation, new performance measures, new thresholds for current performance measures and a new structure for consequences that will result from failure to meet these performance measures.

On Nov. 14, 2003, NSP-Minnesota submitted a proposed service quality plan and an update regarding certain service quality settlement agreement provisions already implemented by NSP-Minnesota. On Jan. 22, 2004, the MPUC voted to modify the settlement to include an annual independent audit of NSP-Minnesota’s service outage records and under-performance payments for any future finding of inaccurate data by an independent auditor. Both state agencies and NSP-Minnesota have the option to void the settlement if they choose not to accept the MPUC’s modification. On March 10, 2004, the MPUC issued its order formally approving the settlement agreement as modified. All parties to the proceeding have twenty days from the date of the order to seek clarification or rehearing.

South Dakota Service Quality — In 2002, the SDPUC investigated NSP-Minnesota’s electric service quality. In particular, the investigation focused on NSP-Minnesota operations in the Sioux Falls area. NSP-Minnesota committed to a number of actions to improve reliability, which were implemented; and in December 2003 provided the SDPUC with an updated 10-year capacity plan. NSP-Minnesota has completed the commitments made in December 2002 relating to service quality in the Sioux Falls area. In 2002, NSP-Minnesota also worked with the SDPUC to provide information and to answer inquiries regarding service quality. No docket was opened and the matter is resolved.

Renewable Transmission Cost Recovery — In 2002, NSP-Minnesota filed for MPUC approval to establish a Renewable Cost Recovery (RCR) adjustment mechanism to recover the costs of transmission investments incurred to deliver renewable energy resources. 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 $6 million of annual additional transmission costs from May 2004 to December 2004. The request is pending MPUC approval. The RCR adjustment mechanism provides for annual filings to set the RCR adjustment rates using updated transmission cost information.

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. A final decision by the MPUC is expected in the second half of 2004.

2004 General Rate Case — On June 1, 2003, NSP-Wisconsin filed its required biennial rate application with the PSCW requesting no change in Wisconsin retail electric and natural gas base rates. NSP-Wisconsin requested the PSCW approve its application without hearing, pending completion of the Staff’s audit.

On Dec. 22, 2003, the PSCW issued an interim order in the rate case approving NSP-Wisconsin’s request for alternative accounting treatment of the loss on reacquired debt associated with the refinancing of $110 million first mortgage bonds. In November 2003, NSP-Wisconsin had filed a proposal to amortize the loss on reacquired debt over the 15-year term of the new $150 million issue, as opposed to the “revenue neutral” method, which was specified in the PSCW order approving the refinancing and resulted in a shorter amortization period. Because the alternative method approved by the PSCW results in a longer amortization period, NSP-Wisconsin lowered financing costs by $394,000 in 2003 and expects to lower financing costs by $1,894,000 in 2004.

On Feb. 19, 2004, the PSCW verbally approved NSP-Wisconsin’s request for no change in retail electric and natural gas rates and determined to forego a public rate hearing based on the results of the PSCW’s staff audit. A final written order was issued on Feb. 23, 2004. In approving NSP-Wisconsin’s request, the current 11.9 percent return on common equity was retained and the existing fuel credit factor was rolled into base rates, effective March 15, 2004. The PSCW also allowed NSP-Wisconsin the option of filing updated fuel costs in the fall of 2004 for the purpose of resetting the fuel component of rates in 2005.

Incentive Cost Adjustment and Interim Adjustment Clause – PSCo’s ICA mechanism was in place for periods prior to 2003. The CPUC conducted a proceeding to review and approve the incurred and recoverable 2001 costs under the ICA. On July 10, 2003, a stipulation and settlement agreement was filed with the CPUC, which resolved all issues. The stipulation and settlement agreement also provides for a prospective revenue adjustment related to the maximum allowable natural gas hedging costs that will be a part of the electric commodity adjustment for 2004 and is expected to reduce 2004 rates by an estimated $4.6 million. The stipulation and settlement agreement was approved by the CPUC in August 2003. An evaluation of the 2002 recoverable ICA costs is pending before the CPUC with a decision expected no later than September 2004. In 2003, PSCo’s prudently incurred fuel and purchased energy costs are fully recoverable under the IAC and are not subject to sharing; however, they will still be subject to a future review by the CPUC.

Wholesale Electric Rate Case – On June 19, 2003, PSCo filed a wholesale electric rate case with the FERC, proposing to increase the annual electric sales rates charged to wholesale customers, other than Cheyenne Light Fuel & Power Co., a wholly owned subsidiary of Xcel Energy. On Aug. 1, 2003, PSCo submitted a revised filing correcting an error in the calculation of income taxes. The revised filing requested an approximately $2 million annual increase with new rates effective in January 2004, subject to refund. In August 2003, PSCo reached a settlement in principle in this case. In December 2003, PSCo filed the offer of settlement for FERC approval, which was accepted by the FERC in February 2004.

Electric Commodity Trading Investigation – In the comprehensive settlement agreement that concluded the PSCo 2002 general retail rate case, PSCo agreed to file an application with the CPUC in January 2004 for a review of the Colorado regulatory treatment of its wholesale electric commodity trading operations. In the filing, PSCo offered to replace the margin sharing between shareholders and retail customers that resulted from the rate case settlement with a defined trading benefit that would reduce retail electric rates by $2.02 million in 2005 and by $1.3 million in 2006. In return for this defined benefit, PSCo proposed to retain for shareholders all margins earned from electric commodity trading in 2005 and 2006 and to bear all risk of loss associated with electric commodity trading. PSCo’s proposal is pending before the CPUC. A decision is expected in October 2004.

PSCo Wholesale Fuel Adjustment Clause Proceedings - Certain wholesale electric sales customers of PSCo filed complaints with the FERC in 2002 alleging PSCo has been improperly collecting certain fuel and purchased energy costs through the wholesale fuel cost adjustment clause included in their rates related to the periods 1996 through 2002. The FERC consolidated these complaints and set them for hearing. Claims were estimated at approximately $30 million. In August 2003, PSCo reached agreements in principle with all of the complainants under which such claims, as well as issues those customers had raised in response to PSCo’s proposal to change the base demand and energy rates applicable to wholesale requirements sales, were compromised and settled. Under the proposed settlement agreements, PSCo accrued a liability of $1.1 million in 2003 and made either cash payments or billing credits to respective customers in January 2004. The settlements also provide for revisions to the base demand and energy rates filed in the PSCo wholesale electric rate case that is currently pending before the FERC in a separate docket, as discussed above. As a part of the settlement, the customers agreed to withdraw their fuel clause investigation complaints. In January 2004, the customers filed motions to conditionally withdraw their complaints pending approval of the base rate settlement proposals. The settlement proposal is pending FERC acceptance.

Electric Department Earnings Test Proceedings – PSCo has filed with the CPUC its annual electric department earnings test reports for 2002. PSCo did not earn above its allowed authorized return on equity and, accordingly, has not recorded any refund obligations. The CPUC has 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 should be made. The 2002 proceeding has been set for hearing in September 2004.

Capacity Cost Adjustment - In October 2003, PSCo filed with the CPUC an application to recover approximately $31.5 million of incremental capacity costs through a purchased capacity cost adjustment (PCCA) rider beginning March 1, 2004. The purpose of the PCCA is to recover purchased capacity payments to third party power suppliers that will not be recovered in PSCo’s current base electric rates or other recovery mechanisms. In addition, PSCo has proposed to return to its retail customers 100 percent of any electric earnings in excess of its authorized rate of return on equity allowed in the last rate case, currently 10.75 percent. In February 2004, PSCo updated its filing which will reduce the recovery amount from the original filing, and proposed that the PCCA rider become effective in the later part of 2004; a decision by the CPUC is pending.

Home Builders Association of Metropolitan Denver — In February 2001, Home Builders Association of Metropolitan Denver (HBA) filed a complaint with the CPUC seeking a reparations award of $13.6 million for PSCo’s failure to update its gas extension policy construction allowances from 1996 to 2002 under its tariff. On Sept. 24, 2003, the CPUC issued its decision, directing PSCo to pay a portion of the reclaimed reparations to HBA members, including interest, based on a revised construction allowance for the period Feb. 24, 1999, through May 31, 2002. In March 2004, PSCo filed a settlement which, if approved by the CPUC, would provide for payment of approximately $700,000 to HBA.

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 administrative law judge (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. Because of the low volume of sales that PSCo had into California after this date, PSCo’s exposure is estimated at approximately $1.2 million, which is offset by amounts owed by the California ISO to PSCo in excess of that amount.

Certain California parties have sought rehearing of this decision. Among other things, they have 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. PSCo has estimated that the requested earlier effective date could increase PSCo’s refund exposure to approximately $15 million.

In an order issued on October 16, 2003, the FERC determined that the refund effective date should not be reset to an earlier date, and gave clarification how refunds should be determined for the previously set refund period. The proceeding is still pending at the FERC to address the refund level issue. Certain California parties have filed appeals of the FERC’s decision not to establish an earlier refund effective date.

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 partnerships and expand the scope of the show cause order addressing gaming and/or anomalous 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 its Trial Staff’s motions to dismiss certain parties, including PSCo, of the show cause proceedings addressing the use of gaming or anomalous market behavior. The FERC also rejected requests to expand the scope of the show cause proceedings. On February 23, 2004, certain California parties sought rehearing of the FERC’s orders.

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, the FERC reaffirmed this ruling to terminate the proceeding without refunds. Certain purchasers have filed appeals of the FERC’s orders in this proceeding.

CPUC Reliability Inquiry – In January 2004, the CPUC staff issued an initial report regarding its formal inquiry of PSCo’s electric distribution system reliability (Initial Report). The Initial Report makes several recommendations for improving reliability and noted that PSCo had already taken steps toward improvement. In February 2004, PSCo also provided the CPUC with its written and oral responses to the Initial Report describing its action plan to improve electric distribution system reliability. PSCo identified $24.9 million in expenditures directed at this effort that it would make during 2004.

The Initial Report recommends audits of PSCo’s electric distribution system operations and maintenance practices and its IT systems supporting electric distribution reliability. PSCo believes the audits are unnecessary in light of its action plan to address the reliability concerns raised in the Initial Report. The CPUC has taken the Initial Report and PSCo’s response under advisement.

Texas Fuel Surcharge Application — 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 for SPS to collect net under-recoveries experienced through December 2003 of $22 million. The surcharge will go into effect May 2004 and will continue for 12 months. The settlement is pending review and approval by the PUCT.

NMPRC Billing Practices Investigation - In 2003, the NMPRC opened an investigation of SPS’ billing practices as a result of certain customers receiving estimated billings for an extended period of time. The NMPRC ordered SPS to implement temporary billing measures for customers whose bills were estimated, which was completed in 2003. The NMPRC is expected to close its investigation in 2004.

Retail competition and the unbundling of regulated energy service could have a significant financial impact on Xcel Energy’s utility subsidiaries, due to an impairment of assets, a loss of retail customers, lower profit margins and increased costs of capital. During the past several years, there have been several restructuring initiatives initiated in the various states Xcel Energy’s utility subsidiaries operate, as well as the Federal level. However, we believe such risk has been mitigated, to a certain degree, as a result of less focus recently on such initiatives. The total impacts of restructuring may have a significant financial impact on the financial position, results of operation and cash flows of Xcel Energy’s utility subsidiaries. Xcel Energy’s utility subsidiaries cannot predict when they will be subject to changes in legislation or regulation, nor can they predict the impacts of such changes on their financial position, results of operation or cash flows. Xcel Energy believes that the prices its utility subsidiaries charge for electricity and the quality and reliability of their service currently place them in a position to compete effectively in the energy market.

Retail Business Competition — The retail electric business faces 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. Xcel Energy’s utility subsidiaries are taking actions to manage their operating costs and are working with their customers to analyze energy efficiency and load management in order to better position Xcel Energy’s utility subsidiaries to more effectively operate in a competitive environment.

Wholesale Business Competition — The wholesale electric business faces competition in the supply of bulk power, due to federal and state initiatives, to provide open access to utility transmission systems. Under current FERC rules, investor-owned utilities are required to provide wholesale open access transmission services and to unbundle wholesale merchant and transmission operations. Xcel Energy’s utility subsidiaries are operating under a joint tariff in compliance with these rules. To date, these provisions have not had a material impact on the operations of Xcel Energy’s utility subsidiaries.

Utility Industry Changes - The structure of the electric and natural gas 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. The FERC continues to pursue the expansion of competitive wholesale electricity markets through regional transmission organizations and standard market design rules. In addition, the FERC issued a series of regulatory orders in 2003. These orders, among other things, standardized the methods and pricing of power generation interconnections, establish new standards of conduct rules for transmission providers and new market behavioral rules for utilities with wholesale market-based sales rate authority. Xcel Energy has not yet estimated the full impact of the new FERC regulatory orders, but it could be material.

Some states had begun to allow retail customers to choose their electricity supplier, while other states have delayed or canceled industry restructuring. There were no significant retail electric or natural gas restructuring efforts in the states served by Xcel Energy in 2003. In 1999, the state of Texas implemented retail restructuring legislation and major portions of the state have restructured and are providing retail competition. In Xcel Energy’s Texas service area, which is outside the Electric Reliability Council of Texas, retail electric competition has been delayed until at least 2007. The State of New Mexico repealed its Electric Industry Restructuring Act of 1999.

Xcel Energy cannot predict the outcome of restructuring proceedings in the electric utility jurisdictions it serves at this time. The resolution of these matters may have a significant impact on the financial position, results of operations and cash flows of Xcel Energy’s utility subsidiaries.

For more information on the delay of restructuring for SPS in Texas and New Mexico, see Note 10 to the Consolidated Financial Statements.

Midwest ISO Operations — In August 2000, NSP-Minnesota and NSP-Wisconsin joined the Midwest Independent Transmission System Operator, Inc. (MISO). In December 2001, the FERC approved the MISO as the first regional transmission organization (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 kilovolts and above) transmission systems to the MISO. The MISO membership grants MISO functional control over the operations of these facilities and the facilities of neighboring electric utilities.

In October 2001, the FERC issued an order in a separate proceeding to establish the initial MISO regional transmission tariff rates, ruling that all transmission services, with limited exceptions, in the MISO region must be subject to the MISO regional tariff and administrative surcharges to prevent discrimination between wholesale transmission service users. The FERC order unilaterally modified the agreement with the MISO signed in August 2000. The FERC order increased wholesale transmission costs to NSP-Minnesota and NSP-Wisconsin by approximately $9 million per year.

On July 25, 2003, MISO filed proposed changes to its regional open access transmission tariff to implement a new Transmission and Energy Markets Tariff (TEMT) that would establish certain wholesale energy and transmission service rates based on locational marginal cost pricing effective in 2004. NSP-Minnesota and NSP-Wisconsin presently receive transmission services from MISO for service to their retail loads and would be subject to the new tariff, if approved by the FERC. On Oct. 17, 2003, MISO filed to withdraw the TEMT, after numerous parties filed protests to the proposal. The FERC issued an order approving the withdrawal and provided guidance on MISO’s proposals on Oct. 29, 2003. MISO is now conducting a stakeholder consultation process to prepare and submit a revised TEMT in March 2004 to be effective Dec. 1, 2004. Management believes any new tariff, if approved by the FERC, could have a material effect on wholesale power supply or transmission service costs to NSP-Minnesota and NSP-Wisconsin.

Southwest Power Pool (SPP) Restructuring – SPS is a member of the SPP regional reliability council, and SPP acts as 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 Oct. 31, 2003, SPS submitted a conditional notice of withdrawal from SPP in order to preserve flexibility with regard to future RTO membership. On Feb. 10, 2004, the FERC conditionally approved SPP’s proposed formation as an RTO, subject to SPP meeting certain requirements. The order also provides that SPS may only terminate its current membership in SPP with FERC approval. If SPS elects to be a member of the SPP RTO, 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.

TRANSLink Transmission Co., LLC (TRANSLink) — In September 2001, Xcel Energy and several other mid-continent electric utilities applied to the FERC to integrate operations of their electric transmission systems into a single system through the formation of TRANSLink, a for-profit, independent transmission-only company. The utilities were to participate in TRANSLink through a combination of divestiture, leases and operating agreements. TRANSLink was intended to be a cost-effective option to manage transmission and to comply with the Order No. 2000 regulations issued by the FERC that required investor-owned electric utilities to transfer operational control of their transmission system to an independent RTO.

Under the proposal, TRANSLink would have been responsible for planning, managing and operating both local and regional transmission assets. TRANSLink would also have constructed and owned new transmission system additions. In November 2003, however, the formation activity for TRANSLink was suspended due to continued market and regulatory uncertainty.

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. As required by the FERC, Xcel Energy’s utility subsidiaries submitted a compliance filing on Jan. 20, 2004. The FERC approval of the compliance changes to Xcel Energy’s utility subsidiaries’ tariff, the MISO regional tariff, and the SPP regional tariff, which will govern most generation interconnections to Xcel Energy’s utility subsidiaries’ transmission system, are pending. On March 5, 2004, the FERC issued an order on rehearing adopting certain changes to the pricing provisions of the final rules.

Standards of Conduct Rulemaking — In November 2003, the FERC issued final standards of conduct rules affecting all FERC jurisdictional transmission utilities, which will require a greater functional separation of electric transmission functions from the wholesale energy marketing and sales functions and from “energy affiliates”. Xcel Energy’s utility subsidiaries filed their initial compliance plan on Feb. 9, 2004. Full compliance is required by June 1, 2004. Xcel Energy and other parties have requested the FERC to grant clarification or rehearing of certain aspects of the final rules. Management has estimated the cost of compliance with the new standards of conduct rules at approximately $1 million in 2004.

Standard Market Design Rulemaking — In July 2002, the FERC issued a notice of proposed rulemaking on wholesale standard market design (SMD) for regulated utilities. If implemented as proposed, the rulemaking would substantially change how wholesale electric supply markets operate throughout the United States. The proposed rulemaking expands the FERC’s intent to unbundle transmission operations from integrated utilities and ensure robust competition in wholesale markets. The rule contemplates that all wholesale and retail customers will be on a single network transmission service tariff. The rule also contemplates the implementation of a bid-based system for buying and selling energy in wholesale electric markets using location marginal pricing. RTOs or independent transmission providers will administer the market. RTOs will also be responsible for regional plans that identify opportunities to construct new transmission, generation or demand-side programs to reduce transmission constraints and meet regional energy requirements. Finally, the rule envisions the development of regional market monitors responsible for ensuring that individual participants do not exercise unlawful market power. The FERC later extended the comment period, but the final rules could be in

place in 2004 and the contemplated market changes in 2004 or 2005. Recent MISO actions indicate that the MISO plans to establish a market design similar to SMD by December 2004, which would impact wholesale markets on the NSP-Minnesota and NSP-Wisconsin systems. The SPP RTO proposal approved by the FERC in February 2004 anticipates establishing a wholesale electric market applying certain aspects of SMD beginning in 2005, which would impact wholesale markets on the SPS system.

Minnesota Restructuring — In 2001, the Minnesota Legislature passed an energy security bill that included provisions intended to streamline the siting process of new generation and transmission facilities. It also included voluntary benchmarks for achieving renewable energy as a portion of the utility’s supply portfolio; however, the benchmarks are mandatory for NSP-Minnesota (subject to certain conditions). In 2003, the Minnesota Legislature revised the 2001 statute to require Minnesota utilities to develop and submit analyses to the MPUC of the transmission upgrades required to deliver the benchmark quantities of renewable energy as part of biennial transmission planning process established by the 2001 energy security bill. There was no other action on restructuring in 2002 or 2003.

North Dakota Restructuring — In 1997, the North Dakota Legislature established, by statute, an Electric Utility Competition Committee (EUC). While its legislated scope is quite broad, the committee focused much of its initial efforts on the study of the state’s current tax treatment of the electric utility industry. In 2003, the legislature expanded the membership of the committee and extended its life to 2007.

Wisconsin Restructuring — The State of Wisconsin passed legislation in 2001 that reduced the wholesale gross receipts tax on the sale of electricity by 50 percent starting in 2003. This legislation eliminates the double taxation on wholesale sales from non-utility generators. Additional legislation was passed that enables regulated utilities to enter into leased generation contracts with unregulated generation affiliates. The new legislation provides utilities a new financing mechanism and option to meet their customers’ energy needs. In 2002, the PSCW approved the first power plant proposal utilizing the new leased generation contract arrangement. While industry-restructuring changes continue in Wisconsin, the movement towards retail customer choice has virtually ceased.

Michigan Restructuring — Since Jan. 1, 2002, NSP-Wisconsin has been providing its Michigan electric customers with the opportunity to select an alternative electric energy provider. This action was required by Michigan’s Customer Choice and Electricity Reliability Act, which became law in June 2000. NSP-Wisconsin developed and successfully implemented internal procedures, and obtained MPSC approval for these procedures to meet the Jan. 1, 2002 deadline. Key elements of internal procedures included the development of retail open access tariffs and unbundled billing, environmental and fuel disclosure information, and a code of conduct compliance plan. To date, no NSP-Wisconsin retail electric customers have converted to a competing supplier.

Colorado Restructuring — There was no legislative action with respect to restructuring in Colorado during the 2001, 2002 or 2003 legislative sessions. None is expected in 2004.

New Mexico Restructuring — In March 2001, the State of New Mexico enacted legislation that delayed customer choice until 2007 and amended the Electric Utility Restructuring Act of 1999. In April 2003, the State of New Mexico repealed the Electric Utility Restructuring Act of 1999. The repeal legislation provided utilities the opportunity to recover their transition costs incurred to comply with the Restructuring Act of 1999. Utilities may retain these transition costs as a regulatory asset on their books pending recovery, which shall be completed by Jan. 1, 2010. At Dec. 31, 2003, SPS had deferred $5.1 million of New Mexico restructuring costs.

Texas Restructuring — In June 2001, the Governor of Texas signed legislation postponing the retail competition and restructuring of SPS until at least 2007. This legislation amended the 1999 legislation, Senate Bill No. 7 (SB-7), which provided for retail electric competition beginning January 2002. Under the amended legislation, prior PUCT orders issued in connection with the restructuring of SPS are considered null and void. SPS’ restructuring and rate unbundling proceedings in Texas have been terminated. In addition, under the new legislation, SPS is entitled to recover all reasonable and necessary expenditures made or incurred before Sept. 1, 2001, to comply with SB-7.

For more information on restructuring in Texas and New Mexico, see Note 10 to the Consolidated Financial Statements.

Kansas Restructuring — During the 2001 legislative session, several restructuring related bills were introduced for consideration by the state legislature. To date, however, there is no restructuring mandate in Kansas.

Oklahoma Restructuring — In 2001, Senate Bill 440 (SB-440) was signed into law to formally delay electric restructuring until restructuring issues could be studied further and new enabling legislation could be enacted. SB-440 established the Electric Restructuring Advisory Committee. The Advisory Committee submitted a report to the Governor and Legislature on Dec. 31, 2001. During 2002 and 2003, there was no action taken by the Legislature as a result of this report. Oklahoma continues to delay retail competition.

Assuming normal weather during 2004, system peak demand and the net dependable system capacity for Xcel Energy’s electric utility subsidiaries are projected below. The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin are managed as an integrated system (referred to as the NSP System). The system peak demand for each of the last three years and the forecast for 2004 are listed below.

The peak demand for all systems typically occurs in the summer. The 2003 system peak demand for the NSP System occurred on Aug. 20, 2003. The 2003 system peak demand for PSCo occurred on July 24, 2003. The 2003 system peak demand for SPS occurred on Aug. 5, 2003.

Xcel Energy’s utility subsidiaries expect to use the following resources to meet their net dependable system capacity requirements: 1) Xcel Energy utility subsidiary electric generating stations, 2) purchases from other utilities, independent power producers and power marketers, 3) demand-side management options, and 4) phased expansion of existing generation at select power plants.

Xcel Energy’s electric utility subsidiaries have contractual arrangements to purchase power from other utilities and nonregulated energy suppliers. Capacity, typically measured in kilowatts or megawatts, is the measure of the rate at which a particular generating source produces electricity. Energy, typically measured in kilowatt-hours or megawatt-hours, is a measure of the amount of electricity produced from a particular generating source over a period of time. 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.

The utility subsidiaries of Xcel Energy also make short-term 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.

In December 2002, NSP-Minnesota filed its Resource Plan with the MPUC for 2003 to 2017. The plan describes how Xcel Energy intends to meet the energy needs of the NSP System. The plan presented conservation programs to reduce NSP System’s peak demand and conserve electricity, an approximate schedule of power purchase solicitations to meet increasing demand and programs and plans to maintain the reliable operations of existing resources. In summary, the plan includes the following elements:

•

1.7 percent annual growth in the NSP System’s energy and peak demand requirements;

	•		NSP System’s demand side management and conservation program requirements;

	•		various pending legislative and regulatory proceedings affecting over half of the generating capacity necessary to meet the demand for electricity;

	•		additional power purchase solicitation proposals to meet growing demand for electricity; and

	•		updated the status of spent nuclear fuel at the Prairie Island and Monticello plants and describes the alternatives to replace nuclear generation if the two plants must be replaced as the result of spent nuclear fuel storage limitations.

In May 2003, the Minnesota Legislature approved additional dry cask storage for the NSP-Minnesota nuclear power plants. See Nuclear Power Operations and Waste Disposal-High-Level Radioactive Waste Disposal below. In February 2004, the MPUC approved a request by NSP-Minnesota to close the 2002 resource plan docket and address issues in the upcoming 2004 resource plan filing, to be filed in October 2004.

NSP-Minnesota has a 500-megawatt participation power purchase commitment with the Manitoba Hydro Electric Board, which expires in April 2015. The cost, through April 2005, is based on 80 percent of the costs of owning and operating NSP-Minnesota’s Sherco 3 generating unit, adjusted to 1993 dollars. The cost for the period starting May 2005 through April 2015 is based on a base price and will be escalated by the change in the United States Gross National Product to reflect the current year. In addition, NSP-Minnesota and Manitoba Hydro have seasonal diversity exchange agreements, and there are no capacity payments for the diversity exchanges. These commitments represent about 17 percent of Manitoba Hydro’s system capacity and account for approximately 6 percent of NSP-Minnesota’s 2003 electric system capability. The risk of loss from nonperformance by Manitoba Hydro is not considered significant, and the risk of loss from market price changes is mitigated through cost-of-energy rate adjustments.

In November 2003, NSP-Minnesota proposed investing approximately $164 million in generating capacity in Minnesota and South Dakota to ensure adequate electric capacity for its Upper Midwest customers. NSP-Minnesota is requesting authorization for a $100-million project to add two combustion turbines at its Blue Lake peaking plant in Shakopee, Minn., and for a $64-million project to add one turbine at its Angus Anson peaking plant in Sioux Falls, S.D.

Each of the three new turbines would be fired by natural gas and would have a summer capacity of approximately 160 megawatts. Currently, the Blue Lake plant has four units fired by oil and a net dependable capacity of 174 megawatts; the Angus Anson plant has two units that can be fired by either natural gas or oil and a net dependable capacity of 226 megawatts.

The Blue Lake proposal requires a certificate of need from the MPUC, a site permit from the MEQB, and air quality permits from the Minnesota Pollution Control Agency. The Angus Anson expansion requires an amended facility permit from the South Dakota Public Utilities Commission and air quality permits from the South Dakota Department of Environment and Natural Resources. The projects also require approval by MISO with regards to interconnection and transmission service requests. Final approval is not certain, but decisions on the respective projects are expected in 2004.

In December 2001, NSP-Minnesota proposed construction of various transmission system upgrades to provide transmission outlet capacity for up to 825 megawatts of renewable energy generation (wind and biomass) being constructed in southwest and western Minnesota. In March 2003, the MPUC granted three 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 first of the transmission facilities is now pending MEQB approval as to siting and routing; additional MEQB siting/routing applications are expected to be filed in 2004. The actual in-service dates could be affected by regulatory delays or the need to amend the certificates to reflect increased demand for generation interconnection services. In 2003, the MPUC also approved a Renewable Cost Recovery adjustment that will allow NSP-Minnesota to recover the revenue requirements associated with certain transmission investments associated with delivery of renewable energy resources through an automatic adjustment mechanism starting in 2004.

PSCo estimates it will purchase approximately 37 percent of its total electric system energy input for 2004. Approximately 48 percent of the total system capacity for the summer 2004 system peak demand for PSCo will be provided by purchased power.

To meet the demand and energy needs of the rapidly growing economy in Colorado, PSCo added approximately 1,800 megawatts of resources to its system between 2002 and beginning of 2004.

In April 2004, PSCo plans to file a least cost resource plan to serve the growing needs for future years. This resource plan is expected to include a proposal to build a 750-megawatt coal plant at the existing site of the Comanche generating station in Pueblo, Colo. The project would cost approximately $1.3 billion and could begin producing electricity by late 2009. Several public power entities have the option to participate in the ownership of the facility. Such ownership would reduce PSCo’s supply from the plant and its capital investment. Various regulatory approvals are required before any construction could begin.

Xcel Energy’s electric utility subsidiaries have 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 tables show the delivered cost per million British thermal units (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. These reduced coal costs were due to renegotiated coal transportation contracts.

NSP-Minnesota and NSP-Wisconsin normally maintain between 30 and 45 days of coal inventory at each plant site. Estimated coal requirements at NSP-Minnesota’s major coal-fired generating plants are approximately 12.5 million tons per year. NSP-Minnesota and NSP-Wisconsin have long-term contracts providing for the delivery of up to 100 percent of 2004 coal requirements and up to 92 percent of their 2005 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 they burn in 2004 will have an average sulfur content of less than 0.6 percent. NSP-Minnesota and NSP-Wisconsin have contracts for a maximum of 34.7 million tons of low-sulfur coal for the next four years. The contracts are with one Montana coal supplier, three Wyoming suppliers and one Minnesota oil refinery, with expiration dates ranging between 2005 and 2007. NSP-Minnesota and NSP-Wisconsin could purchase approximately 9 percent of coal requirements in the spot market in 2005 if spot prices are more favorable than contracted prices.

NSP-Minnesota and NSP-Wisconsin’s current fuel oil inventory is adequate to meet anticipated 2004 requirements, and they also have access to the spot market to buy more oil, if needed. NSP-Minnesota and NSP-Wisconsin use 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.

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 71 percent of uranium requirements through 2007 with no coverage of requirements for 2008 and beyond. Current contracts for conversion services requirements cover 68 percent of the requirements through 2008 with no coverage of requirements for 2009 and beyond. Current enrichment services contracts cover 79 percent of the requirements through 2006 with no coverage of requirements for 2007 and beyond. These current contracts expire at varying times between 2004 and 2008. 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 2007 for uranium and 2010 for enrichment services. Fuel fabrication is 100 percent committed for Prairie Island Unit 1 through 2007 and through 2006 for Prairie Island Unit 2. Both Prairie Island Units are not contracted for fuel fabrication beyond those dates. NSP-Minnesota is currently in negotiations with various vendors to pursue fuel fabrication for Prairie Island plant needs beyond the current fuel contracts. Fuel fabrication for Monticello is covered through 2010.

PSCo’s generation stations use low-sulfur western coal purchased primarily under long-term contracts with suppliers operating in Colorado and Wyoming. During 2003, PSCo’s coal requirements for existing plants were approximately 10.2 million tons, a substantial portion of which was supplied pursuant to long-term supply contracts. Coal supply inventories at Dec. 31, 2003 were approximately 39 days usage, based on the average burn rate for all of PSCo’s coal-fired plants.

PSCo operates the Hayden station, and has partial ownership in the Craig station in Colorado. All of Hayden station’s coal requirements are supplied under a long-term agreement. Approximately 75 percent of PSCo’s Craig station coal requirements are supplied by two long-term agreements. Any remaining Craig station requirements for PSCo are supplied via spot coal purchases.

PSCo has contracted for coal supplies to supply approximately 100 percent of the Cherokee, Cameo and Valmont stations’ projected requirements in 2004.

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 65 percent of Arapahoe station’s projected requirements for 2004. Any remaining Arapahoe station requirements will be procured via spot market purchases.

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.

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’ 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. TUCO’s current coal handling contract for Harrington station expires on July 31, 2004; however, amendments that will extend that agreement, and TUCO’s coal handling contract for Tolk station, are being negotiated by the parties. At Dec. 31, 2003, coal supplies at

the Harrington and Tolk sites were approximately 37 and 35 days supply, respectively. TUCO has coal supply agreements to supply 100 percent of the projected 2004 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 supplies for SPS’ power plants are procured under short- and intermediate-term contracts to provide an adequate supply of fuel.

Xcel Energy’s utility subsidiaries conduct various trading operations, including the purchase and sale of electric capacity and energy. Participation in short-term wholesale energy markets provides market intelligence and information that supports the energy management of each utility subsidiary. Xcel Energy’s utility subsidiaries reduce commodity price and credit risks by using physical and financial instruments to minimize commodity price and credit risk and hedge supplies and purchases. Optimizing the utility subsidiaries’ physical assets by engaging in short-term sales and purchase commitments results in lowering the cost of supply for the customers and the capturing of additional margins from non-traditional customers. The utility subsidiaries also use these trading operations to capture arbitrage opportunities created by regional pricing differentials, supply and demand imbalances and changes in fuel prices.

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 14 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 substance includes 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 Department of Energy (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 14 to the Consolidated Financial Statements for further discussion of this matter.

NSP-Minnesota has on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear plants. The Prairie Island plant is licensed by the federal Nuclear Regulatory Commission (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, 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 14 in the Consolidated Financial Statements for further discussion of the matter.

Private Fuel Storage - 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, Private Fuel Storage, LLC (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 Atomic Safety and Licensing Board (ASLB) and opportunities for public input. Evidentiary hearings were held in 2000 and 2002. Most of the issues raised by opponents of the project have been favorably resolved or dismissed. On March 10, 2003, the ASLB ruled that the likelihood of certain aircraft crashes into the proposed facility was sufficiently credible that it would have to be addressed before the facility could be licensed and set forth a potential process for addressing this concern. PFS has submitted responses to all NRC concerns. Public hearings with the ASLB are expected to begin in early 2004. 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.

Visual Inspections - Required visual inspections have been performed of 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.

Prairie Island Steam Generator Replacement - In February 2001, NSP-Minnesota signed a contract with Steam Generating Team, Ltd. to perform engineering and construction services for the installation of replacement steam generators at the Prairie Island nuclear power plant. NSP-Minnesota plans to replace both steam generators in Prairie Island Unit 1 in the fall 2004 refueling outage. The total cost of replacing the steam generators is estimated to be approximately $132 million.

During 1999, NSP-Minnesota, Wisconsin Electric Power Co., Wisconsin Public Service Corp. (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 megawatts. WPS is selling its Kewaunee Nuclear Power Plant to a subsidiary of Dominion Resources, Inc., and may not continue to participate in 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 13 and 14 to the Consolidated Financial Statements.

Electric Operating Statistics (SPS)


	Year Ended Dec. 31,
	2003			2002			2001
Electric sales (Millions of Kwh):
Residential		3,294			3,300			3,212
Commercial and industrial		12,245			12,044			12,404
Public authorities and other		556			549			549

Total retail		16,095			15,893			16,165
Sales for resale		10,071			9,045			8,367

Total energy sold		26,166			24,938			24,532

Number of customers at end of period:
Residential		311,223			304,971			306,622
Commercial and industrial		77,377			75,676			74,761
Public authorities and other		5,829			5,615			5,786

Total retail		394,429			386,262			387,169
Wholesale		72			70			55

Total customers		394,501			386,332			387,224

Electric revenues (Thousands of dollars):
Residential	$	209,227		$	192,030		$	236,931
Commercial and industrial		519,194			462,556			595,788
Public authorities and other		32,267			29,104			21,318

Total retail		760,688			683,690			854,037
Wholesale		378,344			287,768			439,817
Other electric revenues		62,305			53,720			91,604

Total electric revenues	$	1,201,337		$	1,025,178		$	1,385,458

Kwh sales per retail customer		40,806			41,146			41,752
Revenue per retail customer	$	1,928.58		$	1,770.02		$	2,205.85
Residential revenue per Kwh		6.35	¢		5.82	¢		7.38	¢
Commercial and industrial revenue per Kwh		4.24	¢		3.84	¢		4.80	¢
Wholesale revenue per Kwh		3.76	¢		3.18	¢		5.26	¢

NATURAL GAS UTILITY OPERATIONS

Competition and Industry Restructuring

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 customers. These customers have greater ability to buy natural gas directly from suppliers and arrange their own pipeline and retail local distribution company (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 LDC’s, 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 LDC’s distribution system.

Capability and Demand

NSP-Minnesota and NSP-Wisconsin

Xcel Energy categorizes its natural gas supply requirements as firm or interruptible (customers with an alternate energy supply). The maximum daily send out (firm and interruptible) for the combined system of NSP-Minnesota and NSP-Wisconsin was 727,354 million British thermal units (MMBtu) for 2003, which occurred on Jan. 20, 2003.

NSP-Minnesota and NSP-Wisconsin purchase 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 610,000 MMBtu/day. In addition, NSP-Minnesota and NSP-Wisconsin have contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 17 percent of winter natural gas requirements and 22 percent of peak day, firm requirements of NSP- Minnesota and NSP-Wisconsin.

NSP-Minnesota and NSP-Wisconsin also own and operate two liquefied natural gas (LNG) plants with a storage capacity of 2.5 Billion cubic feet (Bcf) equivalent and four 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 242,708 MMBtu of natural gas per day, or approximately 30 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 and NSP-Wisconsin are 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 2002-2003 entitlement levels were approved on Feb. 27, 2003, 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 2003-2004 entitlement levels are pending MPUC action. NSP-Wisconsin’s winter 2003-2004 supply plan was approved by the PSCW in October 2003.

PSCo

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 approximately 1,769,706 MMBtu. In addition, firm transportation customers hold 438,560 MMBtu of capacity without supply backup. Total firm delivery obligation for PSCo is 2,208,266 MMBtu per day. The maximum daily delivery for 2003 for firm and interruptible services was 1,588,833 MMBtu on Feb. 24, 2003.

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 1,842,891 MMBtu/day, which includes 816,866 MMBtu of supplies held under third-party underground storage agreements. In addition, PSCo operates three company-owned underground storage facilities, which provide about 45,000 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 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 13 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.

Natural Gas Supply and Costs

Xcel Energy’s utility subsidiaries actively seek 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.

Natural Gas Operating Statistics (PSCo)


	Year Ended Dec. 31,
	2003		2002		2001
Natural gas deliveries (Thousands of Dth):
Residential		91,513		95,882		91,389
Commercial and industrial		41,545		43,449		45,036

Total retail		133,058		139,331		136,425
Transportation and other		104,430		120,626		122,513

Total deliveries		237,488		259,957		258,938

Number of customers at end of period:
Residential		1,089,958		1,063,378		1,032,529
Commercial and industrial		98,066		96,669		95,879

Total retail		1,188,024		1,160,047		1,128,408
Transportation and other		3,264		3,134		2,967

Total customers		1,191,288		1,163,181		1,131,375

Natural gas revenues (Thousands of dollars):
Residential	$	599,883	$	510,890	$	832,320
Commercial and industrial		240,084		192,419		366,048

Total retail		839,967		703,309		1,198,368
Transportation and other		43,085		46,046		53,173

Total natural gas revenues	$	883,052	$	749,355	$	1,251,541

Dth sales per retail customer		112.00		120.11		120.90
Revenue per retail customer	$	707.03	$	606.28	$	1,060.00
Residential revenue per Dth	$	6.56	$	5.33	$	9.11
Commercial and industrial revenue per Dth	$	5.78	$	4.43	$	8.13
Transportation and other revenue per Dth	$	0.41	$	0.38	$	0.43

ENVIRONMENTAL MATTERS

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

Xcel Energy and its utility subsidiaries strive to comply with all environmental regulations applicable to their operations. However, it is not possible at this time to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or, generally, what effect future laws or regulations may have upon their operations. For more information on environmental contingencies, see Note 13 to the Consolidated Financial Statements.

EMPLOYEES

The number of Xcel Energy utility subsidiary employees on Dec. 31, 2003 is presented in the following table. Of the employees listed in the table, 5,577 or 55 percent, are covered under collective bargaining agreements. See Note 9 to the Consolidated Financial Statements for further discussion. Xcel Energy Services Inc. employees provide service to Xcel Energy’s utility subsidiaries.


NSP-Minnesota*			2,938
NSP-Wisconsin			550
PSCo			2,579
SPS			1,044
Xcel Energy Services Inc			2,973


*		NSP-Minnesota employees include 341 employees loaned to the NMC. In addition, the NMC has 817 employees of its own.

Item 3. Legal Proceedings

In the normal course of business, various lawsuits and claims have arisen against the utility subsidiaries of Xcel Energy. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters.

NSP-Minnesota

Department of Energy Complaint — On June 8, 1998, NSP-Minnesota filed a complaint in the Court of Federal Claims against the DOE requesting damages in excess of $1 billion for the DOE’s partial breach of the Standard Contract. NSP-Minnesota requested damages consisting of the costs of storage of spent nuclear fuel at the Prairie Island nuclear generating plant, anticipated costs related to the Private Fuel Storage, LLC and costs relating to the 1994 state legislation limiting the number of casks that can be used to store spent nuclear fuel at Prairie Island. On April 6, 1999, the Court of Federal Claims dismissed NSP-Minnesota’s complaint. On May 20, 1999, NSP-Minnesota appealed to the Court of Appeals for the Federal Circuit. On Aug. 31, 2000, the Court of Appeals for the Federal Circuit reversed and remanded to the Court of Federal Claims. On Dec. 26, 2000, NSP-Minnesota filed a motion with the Court of Federal Claims to amend its complaint and renew its motion for summary judgment on the DOE’s liability. On July 31, 2001, the Court of Federal Claims granted NSP-Minnesota’s motion for summary judgment on liability. On Nov. 28, 2001, the DOE brought a motion of partial summary judgment on the schedule for acceptance of spent nuclear fuel and on Nov. 27, 2001 the DOE’s obligation to accept greater than Class C waste. These motions are pending. Limited discovery with respect to the schedule issues has been conducted. A trial in NSP-Minnesota’s suit against the DOE is not likely to occur before the second quarter of 2004.

St. Cloud Gas Explosion – Twenty-five lawsuits have been filed as a result of a Dec. 11, 1998, gas explosion in St. Cloud, Minn. that killed four persons (including two employees of NSP-Minnesota), injured several others and damaged numerous buildings. Most of the lawsuits name as defendants NSP-Minnesota, Xcel Energy’s Seren subsidiary, Cable Constructors, Inc. (CCI) (the contractor hired by Seren that struck the marked gas line), and Sirti, an architectural/engineering firm hired by Seren for its St. Cloud cable installation project. The court granted the plaintiffs’ request to amend the complaint to seek punitive damages against Seren and CCI. The plaintiffs brought a similar motion against NSP-Minnesota, which was subsequently denied by the court. On Nov. 11, 2003, court-ordered mediation was conducted. As a result of this mediation NSP-Minnesota reached a confidential settlement with a group of plaintiffs representing the most significant claims asserted against NSP-Minnesota. In November and December of 2003 , similar mediations were conducted that resulted in confidential settlements with various plaintiffs representing the most significant claims asserted against Seren. The settlements will be paid primarily by Seren’s insurance carriers. Remaining settlement payments by NSP-Minnesota are not material. A trial date has not been set for the remaining lawsuits although Seren’s insurance carriers have initiated mediation efforts with these plaintiffs.

Light Rail Lawsuit — In February 2001, NSP-Minnesota filed a lawsuit in the federal district court in Minneapolis seeking reimbursement of costs for relocating electric utility lines to allow for construction of a light rail transit (LRT) line in downtown Minneapolis. In May 2001, the Minnesota Department of Transportation and the Metropolitan Council (Defendants) obtained a preliminary injunction requiring NSP-Minnesota to move certain facilities. NSP-Minnesota complied with the preliminary injunction and has relocated the pertinent utility lines. NSP-Minnesota is capitalizing its costs incurred as construction work in progress. In September 2002, the court granted Defendants’ motions for summary judgment and dismissed NSP-Minnesota’s claims. NSP-Minnesota appealed to the United States Court of Appeals for the Eighth Circuit. In February 2004, the court of appeals affirmed the district court decision. NSP-Minnesota reserves its right to seek further appellate review. In collateral matters regarding LRT construction, NSP-Minnesota commenced a mandamus action in state court seeking an order requiring Defendants to commence condemnation proceedings concerning an underground substation, access to which is blocked by LRT. In October 2002, the court dismissed NSP-Minnesota’s petition as premature. NSP-Minnesota appealed, and the Minnesota Court of Appeals reversed the dismissal and remanded for trial. Defendants petitioned for further review and the case is pending before the Minnesota Supreme Court. NSP-Minnesota also has commenced an action in state court alleging that LRT construction violates the Minnesota Environmental Rights Act.

NSP-Wisconsin

On Nov. 13, 2001, Ralph and Karline Schmidt filed a complaint in Clark County, Wisconsin against NSP-Wisconsin. Plaintiffs allege that electricity provided by NSP-Wisconsin harmed their dairy herd resulting in decreased milk production, lost profits and income, property damage and injury to their dairy herd and seek compensatory, punitive and treble damages. Plaintiffs allege compensatory damages of $1.0 million and pre-verdict interest of $1.2 million, for total damages of $2.2 million. A final pretrial has been scheduled for April 1, 2005, at which time a trial date will be determined.

On Nov. 13, 2001, August C. Heeg Jr. and Joanne Heeg filed a complaint in Clark County, Wisconsin against NSP-Wisconsin. Plaintiffs allege that electricity provided by NSP-Wisconsin harmed their dairy herd resulting in decreased milk production, lost profits and income, property damage and injury to their dairy herd and seek compensatory, punitive and treble damages. Plaintiffs allege compensatory damages of $1.9 million and pre-verdict interest of $6.1 million, for total damages of $8.0 million. A final pretrial has been scheduled for Dec. 17, 2004, at which time a trial date will be determined.

On March 1, 2002, NSP-Wisconsin was served with a lawsuit commenced by James and Grace Gumz and Michael and Susan Gumz in Marathon County Circuit Court, Wisconsin, alleging that electricity supplied by NSP-Wisconsin harmed their dairy herd and caused them personal injury. The Gumz’s complaint alleges negligence, strict liability, nuisance, trespass, and statutory violations and seeks compensatory, punitive and treble damages. Plaintiffs allege compensatory damages of $1.7 million and pre-verdict interest of $1.8 million for total damages of $3.5 million. NSP-Wisconsin has filed for summary judgment on several bases, including statute of limitations, failure to state a claim and the filed rate doctrine. Summary judgment will be heard on April 12, 2004. Trial has been set for October 2004.

On Jan. 16, 2003, NSP-Wisconsin was served with a lawsuit commenced by George and Diane Grosjean in the Circuit Court for Ashland County, Wisc. Mr. Grosjean alleges that in connection with his employment for the City of Ashland he was exposed to toxic wastes generated by NSP-Wisconsin and that such exposure resulted in personal injury. The complaint is based on nuisance and negligence and seeks an unspecified amount of damages. Trial has been set for October 2004.

SPS

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. A trial on the merits was held in October 2002, and on May 23, 2003, the PUCT issued an order denying LCEC’s petition for a cease and desist order against SPS. The basis of the decision was the determination that SPS was granted a certificate of convenience and necessity in 1976 to serve the disputed customers. LCEC has filed an appeal of the decision with the District Court in Travis County, Texas. The appeal is expected to include a substantial review of the record evidence introduced at the PUCT proceeding. The Texas Attorney General has responded to the appeal on behalf of the PUCT and SPS, Texaco Exploration and Production Inc. and Apache Corporation have intervened in the proceeding and filed briefs in support of the PUCT’s decision. A hearing on the appeal is currently scheduled for April 9, 2004.

On October 18, 1996, LCEC filed a suit for damages against SPS in the District Court in Lamb County, Texas, based on the same facts as alleged in its petition for a cease and desist order at the PUCT. This suit has been dormant since it was filed, awaiting a final determination at the PUCT of the legality of SPS providing electric service to the disputed customers. The PUCT order of May 23, 2003, found that SPS was legally serving the disputed customers thus collaterally determining the issue of liability contrary to LCEC’s position in the suit. An adverse ruling on the appeal of the May 23, 2003 PUCT order could result in a re-determination of the legality of SPS’ service to the disputed customers.

Other Matters

For more discussion of legal claims and environmental proceedings, see Note 13 to the Consolidated Financial Statements under Item 8, incorporated by reference. For a discussion of proceedings involving utility rates, see Pending Regulatory Matters under Item 1, incorporated by reference.

Item 4. Submission of Matters to a Vote of Security Holders

This is omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

NSP-Minnesota, NSP-Wisconsin, PSCo, and SPS are wholly owned subsidiaries and there is no market for their common equity securities.

NSP-Minnesota’s first mortgage indenture places certain restrictions on the amount of cash dividends it can pay to Xcel Energy, the holder of its common stock. Even with these restrictions, NSP-Minnesota could have paid more than $815 million in additional cash dividends on common stock at Dec. 31, 2003. In addition, NSP-Minnesota has dividend restrictions imposed by state regulatory commissions, debt agreements and the SEC under the PUHCA limiting the amount of dividends NSP-Minnesota can pay to Xcel Energy. These restrictions include, but may not be limited to, the following:

• maintenance of an equity ratio of 43.74 percent to 53.46 percent;

• payment of dividends only from retained earnings; and

• debt covenant restrictions under the credit agreement for debt and interest coverage ratios.

NSP-Wisconsin has dividend restrictions imposed by state regulatory commissions, debt agreements and the SEC under the PUHCA limiting the amount of dividends NSP-Wisconsin can pay to Xcel Energy. These restrictions include, but may not be limited to:

• maintenance of an equity ratio of 52 percent to 57 percent; and

• payment of dividends only from retained earnings.

PSCo has dividend restrictions imposed by state regulatory commissions, debt agreements and the SEC under the PUHCA limiting the amount of dividends PSCo can pay to Xcel Energy. These restrictions include, but may not be limited to, the following:

• maintenance of a minimum equity ratio of 30 percent;

• payment of dividends only from retained earnings; and

• debt covenant restrictions under the credit agreement for debt and interest coverage ratios.

SPS has dividend restrictions imposed by state regulatory commissions, debt agreements and the SEC under the PUHCA limiting the amount of dividends SPS can pay to Xcel Energy. These restrictions include, but may not be limited to, the following:

The dividends declared during 2003 and 2002 were as follows:


(Thousands of dollars)			Quarter Ended
	March 31, 2003		June 30, 2003		Sept. 30, 2003		Dec. 31, 2003
NSP-Minnesota	$	53,569	$	53,331	$	53,468	$	53,852
NSP-Wisconsin	$	12,455	$	12,683	$	12,712	$	12,563
PSCo	$	58,846	$	59,268	$	59,604	$	59,598
SPS	$	24,649	$	24,242	$	23,759	$	23,987


			Quarter Ended
	March 31, 2002		June 30, 2002		Sept. 30, 2002		Dec. 31, 2002
NSP-Minnesota	$	48,348	$	51,049	$	51,822	$	52,280
NSP-Wisconsin	$	11,418	$	12,349	$	12,364	$	12,260
PSCo	$	55,483	$	61,115	$	60,882	$	60,550
SPS	$	23,587	$	24,357	$	24,451	$	24,428

Item 6. Selected Financial Data

This is omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Item 7. Management’s Discussion and Analysis

Discussion of financial condition and liquidity for the utility subsidiaries of Xcel Energy are omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis and the results of operations for the current year as set forth in general instructions I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Forward Looking Information

The following discussion and analysis by management focuses on those factors that had a material effect on the financial condition and results of operations of Xcel Energy’s utility subsidiaries during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the respective accompanying Consolidated Financial Statements and Notes to the Consolidated Financial Statements.

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to:

• general economic conditions, including the availability of credit and its impact on capital expenditures and the ability to obtain financing on favorable terms;

• rating agency actions;

• business conditions in the energy industry;

• competitive factors including the extent and timing of the entry of additional competition;

• unusual weather;

• changes in federal or state legislation;

• geopolitical events, including war and acts of terrorism;

• regulation; and

• the other risk factors listed from time to time by the utility subsidiaries of Xcel Energy in reports filed with the SEC, including Exhibit 99.01 to this Annual Report on Form 10-K for the year ended Dec. 31, 2003.

NSP-Minnesota’s Management’s Discussion and Analysis

Results of Operations

NSP-Minnesota’s net income was approximately $192.9 million for 2003, compared with approximately $200.2 million for 2002.

Electric Utility and Commodity Trading Margins — Electric fuel and purchased power expense tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel cost recovery mechanisms for retail customers, most fluctuations in fuel and purchased power costs do not significantly affect electric utility margin.

NSP-Minnesota has two distinct forms of wholesale sales: short-term wholesale and electric commodity trading. Short-term wholesale refers to electric sales (excluding sales to retail and municipal customers), which are associated with energy produced from NSP-Minnesota’s generation assets or energy and capacity purchased to serve native load. Electric commodity trading refers to the sales for resale activity of purchasing and reselling electric energy to the wholesale market. Margins from electric commodity trading activity conducted at NSP-Minnesota is partially redistributed to PSCo and SPS pursuant to the Joint Operating Agreement (JOA) approved by the FERC. Trading margins, as discussed in Note 1 to the Consolidated Financial Statements, are reported net in the Consolidated Statements of Income. The following table details base electric utility, short-term wholesale and electric commodity trading revenue and margin:


	Base						Electric
	Electric			Short-Term			Commodity			Consolidated
	Utility			Wholesale			Trading			Totals
	(Millions of dollars)
2003
Electric utility revenue	$	2,350		$	128		$	—		$	2,478
Electric fuel and purchased power		(820	)		(68	)		—			(888	)
Electric trading revenue		—			—			89			89
Electric trading costs		—			—			(81	)		(81	)

Gross margin before operating expenses	$	1,530		$	60		$	8		$	1,598

Margin as a percentage of revenue		65.1	%		46.9	%		9.0	%		62.3	%
2002
Electric utility revenue	$	2,264		$	97		$	—		$	2,361
Electric fuel and purchased power		(721	)		(68	)		—			(789	)
Electric trading revenue		—			—			30			30
Electric trading costs		—			—			(28	)		(28	)

Gross margin before operating expenses	$	1,543		$	29		$	2		$	1,574

Margin as a percentage of revenue		68.2	%		29.9	%		6.7	%		65.8	%

The following summarizes the components of the changes in base electric revenue and base electric margin for the year ended Dec. 31:

Base Electric Revenue


(Millions of dollars)	2003 vs 2002
Sales growth (excluding weather impact)	$	27.2
Estimated impact of weather		(13.0	)
Rate reduction for property taxes		(18.2	)
Fuel cost recovery		63.0
Renewable development fund recovery		12.6
Transmission and other		14.4

Total base electric revenue increase (decrease)	$	86.0

Base Electric Margin


(Millions of dollars)	2003 vs 2002
Sales growth (excluding weather impact)	$	21.4
Estimated impact of weather		(10.3	)
Rate reduction for property taxes		(18.2	)
Renewable development fund recovery		12.6
Demand costs		(3.9	)
Transmission and other		(14.6	)

Total base electric margin increase (decrease)	$	(13.0	)

Short-term wholesale and electric commodity trading margins increased in 2003, compared with 2002, due to favorable market conditions.

Natural Gas Utility Margins — The following table details the change in natural gas revenue and margin. The cost of natural gas tends to vary with changing sales requirements and unit cost of natural gas purchases. However, due to purchased natural gas cost recovery mechanisms for retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin.


	2003			2002
	(Millions of
	dollars)
Natural gas utility revenue	$	675		$	490
Cost of natural gas sold and transported		(517	)		(344	)

Natural gas utility margin	$	158		$	146

The following summarizes the components of the changes in natural gas revenue and margin for the year ended Dec. 31:

Natural Gas Revenue


(Millions of dollars)	2003 vs 2002
Sales growth (excluding weather impact)	$	15.1
Estimated impact of weather on firm sales volume		5.9
Purchased gas adjustment clause recovery		165.6
Transportation and other		(1.6	)

Total natural gas revenue increase (decrease)	$	185.0

Natural Gas Margin


(Millions of dollars)	2003 vs 2002
Sales growth (excluding weather impact)	$	5.0
Estimated impact of weather on firm sales volume		1.7
Amortization in 2002 associated with premium on Viking purchase		1.9
Rate changes and conservation cost recovery		1.0
Transportation and other		2.4

Total natural gas margin increase	$	12.0

Other Revenue — Other revenue decreased in 2003, compared with 2002, due to reductions in 2003 street lighting revenue.

Non-Fuel Operating Expense and Other Costs — The following summarizes the components of the changes in other utility operating and maintenance expense for the year ended Dec. 31:


(Millions of dollars)	2003 vs 2002
Higher performance-based compensation	$	14.8
Restricted stock unit grants		11.8
Higher outage costs		7.1
Higher reliability costs		6.3
Higher medical and health care costs		4.3
Lower pension credits		3.5
Lower information technology costs		(8.5	)
Recovery of prior conservation improvement program disallowances included in 2002		(7.6	)
Other		(3.5	)

Total other utility operating and maintenance expense increase (decrease)	$	28.2

Depreciation and amortization expense decreased by approximately $0.8 million, or 0.2 percent, for 2003 compared with 2002. This decrease reflects the extension of the depreciable life and increasing decommissioning costs for the Prairie Island nuclear plant and the full depreciation of Black Dog Unit 2 in 2002. The decrease was partially offset by $13 million of renewable development fund costs, which are largely recovered through NSP-Minnesota’s fuel clause mechanism, and increased software amortization.

As discussed in Note 2 to the Consolidated Financial Statements, in the first quarter of 2002, pretax special charges of $3.7 million were expensed for the costs of staff consolidations. The charges related to NSP-Minnesota’s allocation of severance costs for utility operations resulting from restaffing plans of several operating and corporate support areas of Xcel Energy.

Other income (expense) decreased by approximately $15.2 million due primarily to a gain on the sale of property by a subsidiary of NSP-Minnesota in March 2002, interest income of $11 million from state and federal income tax settlements recorded in 2002, and the 2003 write-off of $4 million of the unamortized balance of an intangible asset related to license/royalty rights in a fixed wireless network. The decrease from 2002 was partially offset by higher allowance for funds used during construction in 2003.

Interest charges and financing costs increased by approximately $21.0 million, or 18.3 percent, for 2003, compared with 2002. The increase is attributed to the full year impact of the issuance of long-term debt in July and August 2002, and the issuance of long-term debt in August 2003, as part of a financing plan to reduce the dependence on short-term debt.

Income tax expense decreased by approximately $31.6 million in 2003, compared with 2002. The effective tax rate for NSP-Minnesota was 28.4 percent in 2003 and 35.1 percent in 2002. The decrease in the effective tax rate was primarily due to $13 million of tax benefits in 2003 reflecting the successful resolution of various open tax audit issues. The resolved issues included the tax deductibility of certain merger costs associated with the merger to form Xcel Energy and the deductibility, for state purposes, of certain tax benefit transfer lease benefits. Tax expense also decreased in 2003 due to the lower income levels.

NSP-Wisconsin’s Management’s Discussion and Analysis

Results of Operations

NSP-Wisconsin’s net income was approximately $57.5 million for 2003, compared with approximately $54.4 million for 2002.

Electric Utility Margins — The following table details the change in electric revenue and margin. Electric production expenses tend to vary with the quantity of electricity sold and changes in the unit costs of fuel and purchased power. The fuel and purchased power cost recovery mechanism of the Wisconsin jurisdiction may not allow for complete recovery of all expenses and, therefore, dramatic changes in costs or periods of extreme temperatures can impact earnings.


	Total Electric
	Utility
	2003			2002
	(Millions of dollars)
Electric utility revenue	$	474		$	459
Electric fuel and purchased power		(225	)		(212	)

Gross margin before operating expenses	$	249		$	247

Margin as a percentage of revenue		52.5	%		53.8	%

The following summarizes the components of the changes in base electric revenue and base electric margin for the year ended Dec. 31:

Base Electric Revenue


(Millions of dollars)	2003 vs 2002
Sales growth (excluding weather impact)	$	7.0
Estimated impact of weather		(0.7	)
Fuel cost recovery		(3.1	)
Interchange Agreement billing to NSP-Minnesota		12.6
Wholesale and other		(0.7	)

Total base electric revenue increase (decrease)	$	15.1

Base Electric Margin


(Millions of dollars)	2003 vs 2002
Sales growth (excluding weather impact)	$	5.3
Estimated impact of weather		(0.5	)
Fuel cost recovery		(6.9	)
Interchange Agreement billing to NSP-Minnesota		6.3
Wholesale and other		(2.1	)

Total base electric margin increase (decrease)	$	2.1

Other income(expense) for 2003 increased by approximately $0.8 million, compared with 2002, largely due to higher allowance for funds used during construction (related to higher construction expenditures) and a 2002 loss on the sale of property, partly offset by lower interest income from economic development investments.

Interest expense decreased by approximately $0.5 million, or 2.2 percent, for 2003 compared with 2002, due to lower interest expense related to the long-term debt refinancing in October 2003 and higher allowance for funds used during construction (related to higher construction expenditures).

Income tax expense decreased by approximately $9.9 million in 2003 compared with 2002. The effective tax rate for NSP-Wisconsin was 32.0 percent in 2003 and 40.4 percent in 2002. The decrease in the effective tax rate was primarily due to favorable tax accrual adjustments and lower pretax income levels.

PSCo’s Management’s Discussion and Analysis

Results Of Operations

PSCo’s net income was approximately $227.9 million for 2003, compared with approximately $264.7 million for 2002.

Electric Utility and Commodity Trading Margins — Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. For 2002, electric utility and trading margins reflect the impact of sharing energy costs and savings between customers and shareholders relative to a target cost per delivered kilowatt-hour under the ICA ratemaking mechanism. For 2003, PSCo is authorized to fully recover its retail electric fuel and purchased energy expense through the IAC and continued to share trading margins with customers. In addition, PSCo has other adjustment clauses, discussed previously, that allow certain costs to be recovered from retail customers. The ratemaking mechanisms do not allow for complete recovery of all variable production expenses and higher costs can adversely affect earnings.

PSCo has two distinct forms of wholesale sales: short-term wholesale and electric commodity trading. Short-term wholesale refers to electric sales (excluding sales to retail and municipal customers) which are associated with energy produced from PSCo’s generation assets or energy and capacity purchased to serve native load. Electric commodity trading refers to the sales for resale activity of purchasing and reselling electric energy to the wholesale market. Margins from electric commodity trading activity conducted at PSCo is partially redistributed to NSP-Minnesota and SPS pursuant to the JOA approved by the FERC. Trading margins reflect the impact of regulatory sharing of certain trading margins under the ratemaking mechanisms for the respective years. Trading margins, as discussed in Note 1 to the Consolidated Financial Statements, are reported net in the Consolidated Statements of Income. The following table details base electric utility, short-term wholesale and electric trading revenue and margin:


	Base						Electric
	Electric			Short-Term			Commodity			Consolidated
(Millions of dollars)	Utility			Wholesale			Trading			Totals
2003
Electric utility revenue	$	2,073		$	45		$	—		$	2,118
Electric fuel and purchased power		(1,107	)		(45	)		—			(1,152	)
Electric trading revenue		—			—			234			234
Electric trading costs		—			—			(235	)		(235	)

Gross margin before operating expenses	$	966		$	—		$	(1	)	$	965

Margin as a percentage of revenue		46.6	%		—	%		(0.4	)%		41.0	%
2002
Electric utility revenue	$	1,779		$	100		$	—		$	1,879
Electric fuel and purchased power		(794	)		(96	)		—			(890	)
Electric trading revenue		—			—			1,498			1,498
Electric trading costs		—			—			(1,499	)		(1,499	)

Gross margin before operating expenses	$	985		$	4		$	(1	)	$	988

Margin as a percentage of revenue		55.4	%		4.0	%		(0.1	)%		29.3	%

Natural Gas Margin


(Millions of dollars)	2003 vs 2002
Sales growth (excluding weather impact)	$	0.3
Estimated impact of weather		(6.4	)
Purchased gas adjustment clause recovery		—
Rate changes		(13.6	)
Transportation and other		(2.3	)

Total natural gas margin increase (decrease)	$	(22.0	)

Non-Fuel Operating Expense and Other Costs — The following summarizes the components of the changes in other utility operating and maintenance expense for the year ended Dec. 31:


(Millions of dollars)	2003 vs 2002
Higher performance-based compensation	$	12.9
Restricted stock grants		10.7
Unfavorable inventory adjustments		7.7
Lower pension credits		8.0
Higher uncollectible accounts		2.4
Higher medical and health care costs		1.6
Lower information technology costs		(10.9	)
Other		1.0

Total non-fuel operating expense and other increase (decrease)	$	33.4

Depreciation and amortization expense decreased by approximately $20.8 million, or 8.4 percent, for 2003 compared with 2002, primarily due to decreased software amortization and certain power plant units becoming fully depreciated in 2002. In addition, effective July 1, 2003, the CPUC lengthened the depreciable lives of certain electric utility plant at PSCo as a part of the general Colorado rate case, resulting in a further reduction of depreciation expense.

Taxes (other than income taxes) increased by approximately $6.3 million, or 8.2 percent, for 2003 compared with 2002, primarily due to higher property taxes for calendar year 2003.

As discussed in Note 2 to the Consolidated Financial Statements, in the first quarter of 2002, pretax special charges of $0.6 million were expensed for the costs of staff consolidations. The charges related to PSCo’s allocation of severance costs for utility operations resulting from restaffing plans of several operating and corporate support areas of Xcel Energy.

Other income (expense) increased by approximately $6.0 million because more Allowance for Funds Used During Construction was capitalized, partially offset by lower earnings on life insurance investments.

Interest charges and financing costs increased by approximately $17.1 million, or 12.0 percent, for 2003 compared with 2002, primarily due to the full year impact of the issuance of $600 million of 7.875 percent first collateral trust bonds in September 2002 to reduce dependence on short-term debt.

Income taxes decreased by approximately $40.5 million in 2003, compared to 2002, mainly due to lower income levels. The effective tax rate for PSCo was 27.9 percent in 2003 and 32.7 percent in 2002. The decrease in the effective tax rate was primarily due to $12 million of adjustments reflecting the successful resolution of various prior year tax issues. The main issue resolved was the tax deductibility of certain merger costs associated with the mergers to form Xcel Energy.

SPS’ Management’s Discussion and Analysis

Results of Operations

SPS’ net income was approximately $82.3 million for 2003, compared with approximately $73.9 million for 2002.

Electric Utility Margins — The following table details the change in electric revenue and margin. Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Fuel and purchased power costs are recoverable in SPS’ Texas jurisdiction through a fixed fuel factor, which is included in rates. In the New Mexico retail jurisdiction, fuel and purchased energy costs are adjusted through a fuel clause and a fixed annual factor. In all other jurisdictions, SPS currently recovers substantially all increases and refunds substantially all decreases in fuel and purchased power costs pursuant to monthly adjustment clauses. Due to these fuel clause cost recovery mechanisms for retail customers and the ability to vary wholesale prices with changing market conditions, most fluctuations in energy costs do not significantly affect electric margin. However, the fuel clause cost recovery does not allow for complete recovery of all variable production expenses and, therefore, changes in costs can affect earnings.

Short-term wholesale refers to electric sales (excluding sales to retail and municipal customers), which are associated with energy produced from SPS’ generation assets or energy and capacity purchased to serve native load.


	Electric			Short-Term			Consolidated
	Utility			Wholesale			Totals
	(Millions of dollars)
2003
Electric utility revenue	$	1,195		$	6		$	1,201
Electric fuel and purchased power		(705	)		(5	)		(710	)

Gross margin before operating expenses	$	490		$	1		$	491

Margin as a percentage of revenue		41.0	%		16.7	%		40.9	%
2002
Electric utility revenue	$	1,019		$	6		$	1,025
Electric fuel and purchased power		(550	)		(5	)		(555	)

Gross margin before operating expenses	$	469		$	1		$	470

Margin as a percentage of revenue		46.0	%		16.7	%		45.9	%

The following summarizes the components of the changes in base electric revenue and base electric margin for the year ended Dec. 31:

Base Electric Revenue


(Millions of dollars)	2003 vs 2002
Sales growth (excluding weather impact)	$	8.5
Estimated impact of weather		(4.2	)
Capacity sales		12.0
Fuel cost recovery		146.0
Other		13.2

Total base electric revenue increase (decrease)	$	175.5

Base Electric Margin


(Millions of dollars)	2003 vs 2002
Sales growth (excluding weather impact)	$	8.3
Estimated impact of weather		(3.5	)
Capacity sales		12.0
Other		5.2

Total base electric margin increase (decrease)	$	22.0

Non-Fuel Operating Expense and Other Costs — The following summarizes the components of the changes in other utility operating and maintenance expense for the year ended Dec. 31:


(Millions of dollars)	2003 vs 2002
Higher performance-based compensation	$	5.5
Restricted stock grants		4.4
Unfavorable inventory adjustments		6.2
Lower pension credits		4.7
Higher medical and health care costs		2.1
Lower plant outage costs		(4.1	)
Other		(0.8	)

Total other utility operating and maintenance expense increase (decrease)	$	18.0

Depreciation and amortization expense decreased by approximately $1.6 million, or 1.8 percent, for 2003 compared with 2002, primarily due to a change in the estimated useful life of a regulatory asset.

In 2002, special charges of $5.1 million were expensed due to a Texas regulatory recovery adjustment. For more information, see Note 2 to the Consolidated Financial Statements.

Taxes (other than income taxes) decreased by approximately by $7.1 million, or 13.1 percent, for 2003 compared with 2002, primarily due to lower franchise taxes.

Other income(expense) decreased by $1.4 million, or 23.4 percent, for 2003 compared with 2002, primarily due to lower interest income.

Interest charges and financing costs decreased by approximately $0.9 million, or 1.6 percent, for 2003 compared with 2002. The change is the result of the 2003 refinancing of the subordinated debt.

Income taxes increased by approximately $8.0 million, or 18.4 percent, for 2003 compared with 2002. The change is primarily due to higher pretax income levels. The effective tax rate for SPS was 38.4 percent in 2003 and 37.0 percent in 2002. The increase was primarily due to revised estimates of state tax expense.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

Business and Operational Risk — Xcel Energy’s utility subsidiaries are exposed to commodity price risk in their generation, retail distribution and energy trading operations. NSP-Minnesota and SPS recover purchased energy expenses on a dollar-for-dollar basis. NSP-Minnesota and PSCo recover natural gas costs on a dollar-for-dollar basis. NSP-Minnesota is authorized to recover certain financial instrument costs, incurred to mitigate wholesale electric and gas commodity price volatility in rates, through the fuel clause adjustment and purchased gas adjustment. NSP-Wisconsin and PSCo have limited exposure to market price risk for the purchase and sale of electric energy. In these jurisdictions, electric energy expenses are recovered based on fixed-price limits or under established sharing mechanisms.

NSP-Minnesota, PSCo and SPS manage commodity price risk by entering into purchase and sales commitments for electric power and natural gas, long-term contracts for coal supplies and fuel oil, and derivative instruments. Xcel Energy’s risk management policy allows the utility subsidiaries to manage the market price risk within each rate-regulated operation to the extent such exposure exists. Management is limited under the policy to enter into only transactions that manage market price risk where the rate regulation jurisdiction does not already provide for dollar-for-dollar recovery. One exception to this policy exists in which Xcel Energy’s utility subsidiaries use various physical contracts and derivative instruments to reduce the volatility in the cost of natural gas and electricity provided to retail customers even though the regulatory jurisdiction may provide dollar-for-dollar recovery of actual costs. In these instances, the use of derivative instruments and physical contracts is done consistently with the local jurisdictional cost-recovery mechanism.

Interest Rate Risk — Xcel Energy’s utility subsidiaries are subject to the risk of fluctuating interest rates in the normal course of business. Xcel Energy’s policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.

are designated as fair value hedges are recognized in earnings as offsets to the changes in fair values of related hedged assets, liabilities or firm commitments. In order to test the effectiveness of such swaps, a hypothetical swap is used to mirror all the critical terms of the underlying debt and regression analysis is utilized to assess the effectiveness of the actual swap at inception and on an ongoing basis. The assessment is done periodically to ensure the swaps continue to be effective. The fair value of interest rate swaps is determined through counterparty valuations, internal valuations and broker quotes. There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented.

The impacts on pretax income of a 100-basis-point change in the benchmark rate on variable debt at Dec. 31 are as follows:


	2003		2002
	(Millions of Dollars)
NSP-Minnesota	$	0.2	$	2.9
PSCo	$	0.7	$	4.3
SPS	$	0.6	$	0.3

With the exception of short-term borrowings, NSP-Wisconsin does not have variable interest rates; therefore there is limited interest rate risk.

See Note 11 to the Consolidated Financial Statements for a discussion of SPS’ interest rate swaps.

See Note 11 to the Consolidated Financial Statements for a discussion of the various trading and hedging contracts of Xcel Energy’s utility subsidiaries.

Xcel Energy’s trading operations and power marketing activities measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as Value-at-Risk (VaR). VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time, with a given confidence interval under normal market conditions. Xcel Energy’s utility subsidiaries utilize the variance/covariance approach in calculating VaR. The VaR model employs a 95-percent confidence interval level based on historical price movement, lognormal price distribution assumption, delta half-gamma approach for non-linear instruments and various holding periods varying from two to five days.

As of Dec. 31, 2003, the calculated VaRs were:


			During 2003
	Year Ended
Operations	Dec. 31, 2003		Average		High		Low
			(Millions of Dollars)
Electric Commodity Trading (a)	$	0.92	$	0.70	$	1.51	$	0.29

(a) Comprises transactions for both NSP-Minnesota and PSCo.

As of Dec. 31, 2002, the calculated VaRs were:


			During 2002
	Year Ended
Operations	Dec. 31, 2002		Average		High		Low
			(Millions of Dollars)
Electric Commodity Trading (a)	$	0.29	$	0.62	$	3.39	$	0.01

(a) Comprises transactions for both NSP-Minnesota and PSCo.

Credit Risk — In addition to the risks discussed previously, Xcel Energy’s utility subsidiaries are exposed to credit risk in the company’s risk management activities. Credit risk relates to the risk of loss resulting from the nonperformance by a counterparty of its

Item 8. Financial Statements and Supplemental Data

INDEPENDENT AUDITORS’ REPORT

To Northern States Power Company-Minnesota:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Northern States Power Company-Minnesota (a Minnesota corporation) and subsidiaries (the Company) as of December 31, 2003 and 2002, and the related consolidated statements of income, stockholder’s equity and comprehensive income and cash flows for the two years ended December 31, 2003 (which include the disclosures regarding Northern States Power Company-Minnesota included in the combined footnotes to the financial statements). Our audit also included the financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

The consolidated financial statements of Northern States Power Company-Minnesota for the year ended December 31, 2001 were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion and included an explanatory paragraph related to the Company’s adoption of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activity” on those consolidated financial statements and the financial statement schedule in their report dated February 21, 2002.

We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Northern States Power Company-Minnesota and its subsidiaries as of December 31, 2003, and the results of their operations and their cash flows for the two years ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

As discussed in Note 14 to the consolidated financial statement, effective January 1, 2003, Northern States Power Company-Minnesota and subsidiaries adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” and as discussed in Note 12, effective October 1, 2003, Derivatives Implementation Group Issue No. C20 “Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature.”

/S/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 27, 2004

THE FOLLOWING REPORT IS A COPY OF A PREVIOUSLY ISSUED REPORT OF ARTHUR ANDERSEN LLP AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS — NSP-Minnesota

To Northern States Power Company-Minnesota:

We have audited the accompanying consolidated balance sheets and statements of capitalization of Northern States Power Company-Minnesota (a Minnesota corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, stockholder’s equity and cash flows for each of the two years in the period ended December 31, 2001. These financial statements and the schedule referred to below are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Northern States Power Company - Minnesota and its subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States.

As discussed in Note 12 to the consolidated financial statements, effective January 1, 2001 Northern States Power Company-Minnesota and its subsidiaries adopted Statement of Financial Accounting Standard No. 133, “Accounting for Derivative Instruments and Hedging Activity,” which changed its method of accounting for certain commodity contracts and other derivatives.

Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the index of the consolidated financial statements is presented for purposes of complying with the Securities and Exchange Commission’s rules and is not a required part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, fairly states, in all material respects, the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.

/s/ ARTHUR ANDERSEN, LLP

ARTHUR ANDERSEN, LLP

Minneapolis, Minnesota
February 21, 2002

INDEPENDENT AUDITORS’ REPORT

To Northern States Power Company-Wisconsin:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Northern States Power Company-Wisconsin (a Wisconsin corporation) and subsidiaries (the Company) as of December 31, 2003 and 2002, and the related consolidated statements of income, stockholder’s equity and comprehensive income and cash flows for the two years ended December 31, 2003 (which include the disclosures regarding Northern States Power Company-Wisconsin included in the combined footnotes to the financial statements). Our audit also included the financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

The consolidated financial statements of Northern States Power Company-Wisconsin for the year ended December 31, 2001 were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those consolidated financial statements and the financial statement schedule in their report dated February 21, 2002.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Northern States Power Company-Wisconsin and its subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the two years ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

As discussed in Note 14 to the consolidated financial statement, effective January 1, 2003, Northern States Power Company-Wisconsin and subsidiaries adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.”

/S/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 27, 2004

THE FOLLOWING REPORT IS A COPY OF A PREVIOUSLY ISSUED REPORT OF ARTHUR ANDERSEN LLP AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS — NSP-Wisconsin

To Northern States Power Company-Wisconsin:

We have audited the accompanying consolidated balance sheets and statements of capitalization of Northern States Power Company-Wisconsin (a Wisconsin corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, stockholder’s equity and cash flows for each of the two years in the period ended December 31, 2001. These financial statements and the schedule referred to below are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Northern States Power Company-Wisconsin and its subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States.

/s/ ARTHUR ANDERSEN, LLP

ARTHUR ANDERSEN, LLP

Minneapolis, Minnesota
February 21, 2002

INDEPENDENT AUDITORS’ REPORT

To Public Service Company of Colorado:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Public Service Company of Colorado (a Colorado corporation) and subsidiaries (the Company) as of December 31, 2003 and 2002, and the related consolidated statements of income, stockholder’s equity and comprehensive income and cash flows for the three years ended December 31, 2003 (which include the disclosures regarding Public Service Company of Colorado included in the combined footnotes to the financial statements). Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements referred to above present fairly, in all material respects, the financial position of Public Service Company of Colorado and its subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

As discussed in Note 14 to the consolidated financial statement, effective January 1, 2003, Public Service Company of Colorado and subsidiaries adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” and as discussed in Note 12, effective October 1, 2003, Derivatives Implementation Group Issue No. C20 “Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature.”

/S/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 27, 2004

INDEPENDENT AUDITORS’ REPORT

To Southwestern Public Service Company:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Southwestern Public Service Company (a New Mexico corporation) and subsidiary (the Company) as of December 31, 2003 and 2002, and the related consolidated statements of income, stockholder’s equity and comprehensive income and cash flows for the two years ended December 31, 2003 (which include the disclosures regarding Southwestern Public Service Company included in the combined footnotes to the financial statements). Our audit also included the financial statement schedule listed in the Index at Item 15. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audit.

The consolidated financial statements of Southwestern Public Service Company for the years ended December 31, 2001 were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion and included an explanatory paragraph related to the Company’s adoption of Statement of Financial Accounting Standards No. 133 — “Accounting for Derivative Instruments and Hedging Activity” on those consolidated financial statements and the financial statement schedule in their report dated February 21, 2002.

We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such consolidated financial statements referred to above present fairly, in all material respects, the financial position of Southwestern Public Service Company and subsidiary as of December 31, 2003, and the results of their operations and their cash flows for the two years ended in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

As discussed in Note 14 to the consolidated financial statement, effective January 1, 2003, Southwestern Public Service Company and subsidiary adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” and as discussed in Note 12, effective October 1, 2003, Derivatives Implementation Group Issue No. C20 “Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature.”

/S/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 27, 2004

THE FOLLOWING REPORT IS A COPY OF A PREVIOUSLY ISSUED REPORT OF ARTHUR ANDERSEN LLP AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS — SPS

To Southwestern Public Service Company:

We have audited the accompanying consolidated balance sheets and statements of capitalization of Southwestern Public Service Company (a New Mexico corporation) as of December 31, 2001 and 2000, and the related consolidated statements of income, stockholder’s equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements and the schedule referred to below are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwestern Public Service Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States.

As discussed in Note 12 to the consolidated financial statements, effective January 1, 2001 Southwestern Public Service Company adopted Statement of Financial Accounting Standard No. 133, “Accounting for Derivative Instruments and Hedging Activity,” which changed its method of accounting for certain commodity contracts and other derivatives.

Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the index of the consolidated financial statements is presented for purposes of complying with the Securities and Exchange Commission’s rules and is not a required part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, fairly states, in all material respects, the financial data required to be set forth there in relation to the basic financial statements taken as a whole.

/s/ ARTHUR ANDERSEN, LLP

ARTHUR ANDERSEN, LLP

Minneapolis, Minnesota
February 21, 2002

NSP-MINNESOTA

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended Dec. 31,
	2003			2002			2001
	(Thousands of dollars)
Operating activities:
Net income	$	192,942		$	200,222		$	207,865
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		352,630			366,362			358,718
Nuclear fuel amortization		43,401			48,675			41,928
Deferred income taxes		1,561			(26,280	)		10,414
Amortization of investment tax credits		(7,365	)		(7,490	)		(8,046	)
Allowance for equity funds used during construction		(12,674	)		(5,491	)		(4,898	)
Gain on sale of nonutility property		—			(6,785	)		—
Change in accounts receivable		(46,150	)		(5,106	)		54,604
Change in accounts receivable from affiliates		(47,753	)		6,755			18,171
Change in inventories		(6,206	)		(4,296	)		(5,363	)
Change in other current assets		(45,026	)		21,712			62,903
Change in accounts payable		17,757			(12,745	)		(64,722	)
Change in other current liabilities		(75,155	)		59,929			(13,553	)
Change in other assets		(8,205	)		(60,052	)		(110,483	)
Change in other liabilities		(7,404	)		75,677			15,216

Net cash provided by operating activities		352,353			651,087			562,754
Investing activities:
Utility capital/construction expenditures		(352,389	)		(383,857	)		(483,936	)
Allowance for equity funds used during construction		12,674			5,491			4,898
Proceeds from sale of property		—			11,152			—
Investments in external decommissioning fund		(80,581	)		(57,830	)		(54,996	)
Restricted cash		23,000			(23,000	)		—
Other investments — net		(4,138	)		(4,939	)		(5,922	)

Net cash used in investing activities		(401,434	)		(452,983	)		(539,956	)
Financing activities:
Short-term borrowings — net		57,931			(381,115	)		21,995
Proceeds from issuance of long-term debt		372,943			624,892			—
Repayment of long-term debt and trust preferred securities, including reacquisition premiums		(426,568	)		(4,876	)		(155,081	)
Capital contributions from parent		29,100			51,714			282,768
Dividends and cash distributions paid to parent		(212,648	)		(195,550	)		(167,237	)

Net cash provided by (used in) financing activities		(179,242	)		95,065			(17,555	)

Net (decrease) increase in cash and cash equivalents		(228,323	)		293,169			5,243
Cash and cash equivalents at beginning of year		310,338			17,169			11,926

Cash and cash equivalents at end of year	$	82,015		$	310,338		$	17,169

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	120,993		$	75,315		$	84,789
Cash paid for income taxes (net of refunds received)	$	181,701		$	83,636		$	84,957

See disclosures regarding NSP-Minnesota in the Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Business and System of Accounts — This report reflects Xcel Energy’s four largest utility subsidiaries, NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, which are engaged principally in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. Xcel Energy and its subsidiaries are subject to the regulatory provisions of the PUHCA. The utility subsidiaries are subject to regulation by the FERC and state utility commissions. All of the utility companies’ accounting records conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material aspects.

Principles of Consolidation — NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have subsidiaries, which have been consolidated. In the consolidation process, we eliminate all significant intercompany transactions and balances.

NSP-Minnesota and NSP-Wisconsin have subsidiaries for which they use the equity method of accounting for their investments and record their portion of earnings from such investments after subtracting income taxes.

Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based of the reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is determined.

Xcel Energy’s utility subsidiaries have various rate adjustment mechanisms in place that currently provide for the recovery of certain purchased natural gas and electric energy costs. These cost adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically, as prescribed by the appropriate regulatory agencies, for any difference between the total amount collected under the clauses and the recoverable costs incurred. In addition, Xcel Energy’s utility subsidiaries present their revenue, net of any excise or other fiduciary-type taxes or fees. A summary of significant rate adjustment mechanisms follows:

• PSCo’s electric rates in Colorado permitted recovery of 100 percent of prudently incurred 2003 electric fuel and purchased energy expense. In 2002 and 2001, PSCo’s electric rates in Colorado were adjusted under an incentive cost adjustment mechanism, which resulted in the sharing of cost increases and decreases with customers and sharing of trading margins. In 2004, PSCo’s electric rates were adjusted under the electric commodity adjustment mechanism, which uses a historical benchmark formula, updated for projected natural gas commodity costs, as the basis for sharing of cost increases and decreases with retail customers.

• NSP-Minnesota’s rates include a cost-of-fuel and energy and a cost-of-gas recovery mechanism allowing dollar-for-dollar recovery of the respective costs, which are trued-up on a two-month and annual basis, respectively.

• NSP-Wisconsin’s rates include a cost-of-gas adjustment clause for purchased natural gas, but not for purchased electric energy or electric fuel. In Wisconsin, requests can be made for recovery of those electric costs prospectively through the rate review process, which normally occurs every two years, or through an interim fuel cost hearing process.

• In Colorado, PSCo operates under an electric performance-based regulatory plan, which provides for an annual earnings test. NSP-Minnesota and PSCo operate under various service standards, which could require customer refunds if certain criteria are not met. NSP-Minnesota and PSCo’s rates include monthly adjustments for the recovery of conservation and energy management program costs, which are reviewed annually.

• SPS’ rates in Texas provide electric fuel and purchased energy cost recovery. In New Mexico, SPS also has a monthly fuel and purchased power cost recovery factor.

• NSP-Minnesota, NSP-Wisconsin, PSCo and SPS sell firm power and energy in wholesale markets, which are regulated by the FERC. These rates include monthly wholesale fuel cost recovery mechanisms.

Trading Operations — All applicable gains and losses related to energy trading activities, whether or not settled physically, are shown net in the statement of operations. Electric trading costs, including such gains and losses, are reported as an offset to electric trading revenues to present Electric Trading Margin on a net basis. Electric trading costs for the years ended Dec. 31, are as follows:


	2003		2002		2001
	(Millions of dollars)
NSP-Minnesota	$	81	$	28	$	12
PSCo	$	235	$	1,499	$	1,255

Xcel Energy’s electric trading operations are conducted by NSP-Minnesota and PSCo. Pursuant to a joint operating agreement (JOA), approved by the FERC, some of the electric trading activity conducted at NSP-Minnesota and PSCo is apportioned to the other operating utilities of Xcel Energy. Trading revenue and costs do not include the revenue and production costs associated with energy produced from Xcel Energy’s generation assets or energy and capacity purchased to serve native load. Trading results are recorded using mark-to-market accounting. In addition, trading results include the impacts of any margin-sharing mechanism. For more information, see Note 12 to the Consolidated Financial Statements.

Property, Plant, Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and applicable interest expense. The cost of plant retired, plus net removal cost is charged to accumulated depreciation and amortization. Removal costs related to asset retirement obligations that are not legal obligations are reflected in regulatory liabilities for the years ending Dec. 31, 2003 and 2002. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance are charged to expense as incurred. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses. Property, plant and equipment also include costs associated with the engineering design of future generating stations and other property held for future use.

Xcel Energy’s utility subsidiaries determine the depreciation of their plant by using the straight-line method, which spreads the original cost equally over the plant’s useful life. Depreciation expense for Xcel Energy’s utility subsidiaries, expressed as a percentage of average depreciable property, for the years ended December 31, is listed in the following table:


	2003			2002			2001
NSP-Minnesota		3.5	%		3.7	%		4.2	%
NSP-Wisconsin		3.3	%		3.3	%		3.1	%
PSCo		2.5	%		2.5	%		3.0	%
SPS		2.7	%		2.8	%		2.8	%

Allowance for Funds Used During Construction (AFDC) and Capitalized Interest — AFDC, a noncash item, represents the cost of capital used to finance utility construction activity. AFDC is computed by applying a composite pretax rate to qualified construction work in progress. The amount of AFDC capitalized as a utility construction cost is credited to other income and deductions (for equity capital) and interest charges (for debt capital). AFDC amounts capitalized are included in Xcel Energy’s utility subsidiaries rate base for establishing utility service rates. In addition to construction-related amounts, AFDC also is recorded to reflect returns on capital used to finance conservation programs in Minnesota. Interest capitalized as AFDC for Xcel Energy’s utility subsidiaries is listed in the following table:


	2003		2002		2001
	(Millions of dollars)
NSP-Minnesota	$	9.3	$	8.5	$	11.9
NSP-Wisconsin	$	0.7	$	0.4	$	1.1
PSCo	$	9.0	$	8.0	$	12.1
SPS	$	1.4	$	1.0	$	4.4

Decommissioning — NSP-Minnesota adopted Statement of Financial Accounting Standard (SFAS) No. 143, which changed the accounting methodology for nuclear decommissioning costs. Prior to 2003, NSP-Minnesota accounted for the future cost of decommissioning, or retirement, of its nuclear generating plants through annual depreciation accruals using an annuity approach designed to provide for full rate recovery of the future decommissioning costs. The decommissioning calculation covers all expenses, including decontamination and removal of radioactive material, and extends over the estimated lives of the plants. The calculation assumes that NSP-Minnesota and NSP-Wisconsin will recover those costs through rates. The fair value of external nuclear

decommissioning fund investments are estimated based on quoted market prices for those or similar investments. Unrealized gains or losses on the fund’s assets are deferred as regulatory assets or liabilities. For more information on nuclear decommissioning, see Note 14 to the Consolidated Financial Statements.

PSCo also previously operated a nuclear generating plant, which has been decommissioned and repowered using natural gas. PSCo’s costs associated with decommissioning were deferred and are being amortized consistent with the CPUC regulatory recovery.

Nuclear Fuel Expense — Nuclear fuel expense, which is recorded as NSP-Minnesota’s nuclear generating plants consume fuel, includes the cost of nuclear fuel used in the current period, as well as future disposal costs of spent nuclear fuel. In addition, nuclear fuel expense includes fees assessed by the U.S. Department of Energy (DOE) and NSP-Minnesota’s portion of the cost of decommissioning the DOE’s fuel enrichment facility.

Environmental Costs — Environmental costs are recorded when it is probable a utility subsidiary is liable for the costs and the liability can be reasonably estimated. Costs may be deferred as a regulatory asset based on an expectation that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as pollution-control equipment, the cost is capitalized and depreciated over the life of the plant, assuming the costs are recoverable in future rates or future cash flow.

Estimated remediation costs, excluding inflationary increases and possible reductions for insurance coverage and rate recovery, are recorded. The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and remediation proceeds. If several designated responsible parties exist, costs are estimated and recorded only for the utility subsidiary share of the cost. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for these estimated removal costs. However, as discussed further in Note 14 of the Consolidated Financial Statements, removal costs recovered in rates were reclassified to Regulatory Liabilities beginning in 2002.

Income Taxes — Xcel Energy and its utility subsidiaries file consolidated federal and combined and separate state income tax returns. Income taxes for consolidated or combined subsidiaries are allocated to the subsidiaries based on separate company computations of taxable income or loss. In accordance with the PUHCA requirements, the holding company also allocates its own net income tax benefits to its direct subsidiaries based on the positive tax liability of each company in the consolidated federal or combined state returns. Xcel Energy’s utility subsidiaries defer income taxes for all temporary differences between the book and tax bases of assets and liabilities. The tax rates used are those that are scheduled to be in effect when the temporary differences are expected to turn around, or reverse.

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded, the reversal of some temporary differences was accounted for as current income tax expense. Investment tax credits are deferred and their benefits spread over the estimated lives of the related property. Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which are summarized in Note 15 to the Consolidated Financial Statements. For more information on income taxes, see Note 8 to the Consolidated Financial Statements.

Derivative Financial Instruments — Xcel Energy’s utility subsidiaries utilize a variety of derivatives, including interest rate swaps and locks, to reduce exposure to interest rate risk and energy contracts to reduce exposure to commodity price risk. The energy contracts are both financial- and commodity-based. These contracts consist mainly of commodity futures and options, index or fixed price swaps and basis swaps. For more information on the utility subsidiary risk management and derivative activities see Note 12 to the Consolidated Financial Statements.

Use of Estimates — In recording transactions and balances resulting from business operations, Xcel Energy’s utility subsidiaries use estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information is obtained or actual amounts are determinable. Those revisions can affect operating results. Each year the depreciable lives of certain plant assets are reviewed and revised, if appropriate.

Cash and Cash Equivalents — Xcel Energy’s utility subsidiaries consider investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. Those instruments are primarily commercial paper and money market funds. Restricted cash in 2002 at NSP-Minnesota consists of cash collateral for letters of credit and funds held in a collateral trust account to

satisfy the requirements of certain debt agreements. Restricted cash is classified as a current asset as all restricted cash is designated for interest and principal payments due within one year.

Inventory — All inventories are recorded at average cost, with the exception of natural gas in storage at PSCo, which is recorded using last-in-first-out pricing.

Regulatory Accounting — Xcel Energy’s utility subsidiaries account for certain income and expense items using SFAS No. 71. Under SFAS No. 71:

• certain costs, which would otherwise be charged to expense, are deferred as regulatory assets based on the expected ability to recover them in future rates; and

• certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation they will be returned to customers in future rates.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. See more discussion of regulatory assets and liabilities at Note 15 to the Consolidated Financial Statements.

Deferred Financing Costs — Other assets include deferred financing costs, which were amortized over the remaining maturity periods of the related debt. Xcel Energy’s utility subsidiaries’ deferred financing costs, net of amortization at Dec. 31, are listed in the following table:


	2003		2002		2001
	(Millions of dollars)
NSP-Minnesota	$	17.4	$	21.1	$	12.4
NSP-Wisconsin	$	2.1	$	1.7	$	1.9
PSCo	$	17.2	$	18.9	$	14.2
SPS	$	5.5	$	8.4	$	9.2

FASB Interpretation No. 46 (FIN No. 46) – In January 2003, the Financial Accounting Standards Board (FASB) issued FIN No. 46, requiring an enterprise’s consolidated financial statements to include subsidiaries in which the enterprise has a controlling financial interest. Historically, consolidation has been required only for subsidiaries in which an enterprise has a majority voting interest. Under FIN No. 46, an enterprise’s consolidated financial statements will include the consolidation of variable interest entities, which are entities in which the enterprise has a controlling financial interest. The Xcel Energy utility subsidiaries are party to purchased power agreements, and based on the current guidance, these contracts are not expected to be considered variable interest arrangements under the provisions of FIN No. 46. However, Xcel Energy’s utility subsidiaries are still evaluating the issue. Additionally, Xcel Energy’s utility subsidiaries are evaluating other arrangements based on criteria in FIN No. 46.

Reclassifications - Certain items in the 2001 and 2002 statements of income and the 2002 balance sheet have been reclassified to conform to 2003 presentation. These reclassifications had no effect on net income or earnings per share. The reclassifications were primarily related to the reclassification of asset retirement obligations from Accumulated Depreciation to a liability account for all utility subsidiaries. PSCo financial statements reflect the reclassifications of extraordinary debt defeasance costs to Interest Expense and Income taxes to comply with SFAS No. 145, “Rescission of FASB Statement No. 40 44, and 64, Amendment of FASB Statement No. 13 and Technical Corrections,” as well as reclassification of the presentation of interest expense on company owned life insurance to conform to current year presentation.

2. Special Charges (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

2002 — Regulatory Recovery Adjustment — In late 2001, SPS filed an application requesting recovery of costs incurred to comply with transition to retail competition legislation in Texas and New Mexico. During 2002, SPS entered into a settlement agreement with intervenors regarding the recovery of restructuring costs in Texas, which was approved by the state regulatory commission in May 2002. Based on the settlement agreement, SPS wrote off pretax restructuring costs of approximately $5 million.

2002 and 2001 — Utility Restaffing — During 2001, Xcel Energy expensed pretax special charges of $39 million for expected staff consolidation costs for an estimated 500 employees in several utility operating and corporate support areas of Xcel Energy. In 2002, the identification of affected employees was completed and additional pretax special charges of $9 million were expensed for the final costs of staff consolidations. Approximately $6 million of these restaffing costs were allocated to Xcel Energy’s utility subsidiaries. All 564 of accrued staff terminations have occurred. See the summary of costs by utility subsidiary below.

Accrued Special Charges — The following table summarizes activity related to accrued special charges in 2003 and 2002:


	Dec. 31,							Dec. 31,							Dec. 31,
	2001		Expensed		Payments			2002		Expensed		Payments			2003
	Liability*		2002		2002			Liability*		2003		2003			Liability
	(Millions of dollars)
Special charge activities for utility subsidiaries:
NSP-Minnesota	$	5	$	4	$	(7	)	$	2	$	—	$	(2	)	$	—
NSP-Wisconsin		2		1		(3	)		—		—		—			—
PSCo		2		1		(3	)		—		—		—			—
SPS		1		—		(1	)		—		—		—			—

* Reported on the balance sheets in other current liabilities.

2001 — Postemployment Benefits — PSCo adopted accrual accounting for postemployment benefits under SFAS No. 112 — “Employers Accounting for Postemployment Benefits” in 1994. The costs of these benefits had been recorded on a pay-as-you-go basis and, accordingly, PSCo recorded a regulatory asset in anticipation of obtaining future rate recovery of these transition costs. PSCo recovered its FERC jurisdictional portion of these costs. PSCo requested approval to recover its Colorado retail natural gas jurisdictional portion in a 1996 retail rate case and its retail electric jurisdictional portion in the electric earnings test filing for 1997. In the 1996 rate case, the CPUC allowed recovery of postemployment benefit costs on an accrual basis, but denied PSCo’s request to amortize the transition costs regulatory asset. Following various appeals, which proved unsuccessful, PSCo wrote off $23 million pretax of regulatory assets related to deferred postemployment benefit costs as of June 30, 2001.

3. Short-Term Borrowings (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Notes Payable — Information regarding notes payable for the years ended Dec. 31, 2003 and 2002 is:


	2003			2002
	(Thousands of dollars,
	except interest rates)
NSP — Minnesota
Notes payable to banks	$	58,000		$	69
Weighted average interest rate at year end		4.00	%		4.40	%
PSCo
Notes payable	$	563		$	88,074
Weighted average interest rate at year end		1.00	%		2.42	%

NSP-Wisconsin has an intercompany borrowing arrangement with NSP-Minnesota, with interest charged at NSP-Minnesota’s short-term borrowing rate. At Dec. 31, 2003 and 2002, NSP-Wisconsin had $23.7 million and $6.9 million, respectively, in short-term borrowings related to this intercompany arrangement. The weighted average interest rate for NSP-Wisconsin was 4.0 percent at Dec. 31, 2003 and 4.4 percent at Dec. 31, 2002.

Credit Facilities — At Dec. 31, 2003, NSP-Minnesota, PSCo and SPS had credit facilities with several banks. These lines of credit were paid for with fee payments.


	Maturity	Term	Credit Line		Credit Line Available
	(Millions of dollars)
NSP-Minnesota	May 2004	364 days	$	275	$	175
PSCo	May 2004	364 days	$	350	$	349
SPS	February 2004	364 days	$	100	$	97

The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit, and, depending on credit ratings, provide support for commercial paper borrowings. NSP-Minnesota’s notes payable to banks listed previously reduced the amounts available under these credit lines. Also, $53.9 million of letters of credit were outstanding at Dec. 31, 2003, of which approximately $46 million were outstanding under the various credit facilities, which further reduced amounts available under the lines.

The SPS $100 million facility expired in February 2004 and was replaced with a $125 million unsecured, 364-day credit agreement.

The borrowing rates under these lines of credit are based on either the bank’s published base rate or the applicable London Interbank Offered Rate (LIBOR) plus a euro dollar rate margin. The credit facilities of NSP-Minnesota and PSCo are secured by first mortgage bonds and first collateral trust bonds, respectively.

Beginning in 2004 and upon receiving the necessary state regulatory approvals, NSP-Minnesota, NSP-Wisconsin, PSCo and SPS will participate in a utility money pool which allows excess funds of the holding company to be made available to the utility subsidiaries for short-term borrowing purposes. It also allows excess funds of the utility subsidiaries to be made available to one another; however, the money pool arrangement does not allow loans to the Xcel Energy parent company. The utility money pool is funded with either external or internal funds, or both. The cost of external funds is the underlying cost of credit facility borrowings. The rate for internal funds is the 30-day commercial paper rate for the previous month-end.

4. Long-Term Debt (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Except for SPS and other minor exclusions, all property of Xcel Energy’s utility subsidiaries is subject to the liens of their first mortgage indentures, which are contracts between the companies and their bondholders. In addition, certain SPS payments under its pollution control obligations are pledged to secure obligations of the Red River Authority of Texas.

The utility subsidiaries’ first mortgage bond indentures provide for the ability to have sinking fund requirements. Such sinking fund obligations may be satisfied with property additions or cash. At Dec. 31, 2003, NSP-Minnesota, NSP-Wisconsin and PSCo have no sinking fund requirements for current bonds outstanding.

NSP-Minnesota’s first mortgage indenture places certain restrictions on the amount of cash dividends it can pay Xcel Energy, the holder of its common stock. Even with these restrictions, NSP-Minnesota could have paid more than $815 million in additional cash dividends on common stock at Dec. 31, 2003.

NSP-Minnesota’s 2011 series bonds were redeemable upon seven-days notice at the option of the bondholder. Because the terms allowed the holders to redeem these bonds on short notice, the bonds were classified as a current portion of long-term debt reported under current liabilities on the balance sheet for the year ended Dec. 31, 2002. The bonds were redeemed in October 2003.

Maturities of long-term debt for the utility subsidiaries are listed in the following table:


	NSP-Minnesota		NSP-Wisconsin		PSCo		SPS
	(Millions of dollars)
2004	$	5	$	—	$	147	$	—
2005		75		—		137		—
2006		205		—		127		500
2007		3		—		102		—
2008		3		80		320		—

5. Preferred Stock (PSCo and SPS)

SPS and PSCo have authorized the issue of preferred shares.


	Preferred Shares				Preferred Shares
	Authorized		Par Value		Outstanding
SPS		10,000,000	$	1.00	None
PSCo		10,000,000	$	0.01	None

6. Mandatorily Redeemable Preferred Securities of Subsidiary Trusts (NSP-Minnesota, PSCo and SPS)

Southwestern Public Service Capital I, a wholly owned, special-purpose subsidiary trust of SPS, had $100 million of 7.85-percent trust preferred securities issued and outstanding that were originally scheduled to mature in 2036. Distributions paid by the subsidiary trust on the preferred securities were financed through interest payments on debentures issued by SPS and held by the subsidiary trust, which were eliminated in consolidation. Distributions and redemption payments were guaranteed by SPS. The securities were redeemable at the option of SPS, at 100 percent of the principal amount plus accrued interest. On Oct. 15, 2003, SPS redeemed the $100 million of trust preferred securities. A certificate of cancellation was filed to dissolve SPS Capital I on Jan. 5, 2004.

NSP Financing I, a wholly owned, special-purpose subsidiary trust of NSP-Minnesota, had $200 million of 7.875-percent trust preferred securities issued and outstanding that were originally scheduled to mature in 2037. Distributions paid by the subsidiary trust on the preferred securities were financed through interest payments on debentures issued by NSP-Minnesota and held by the subsidiary trust, which were eliminated in consolidation. Distributions and redemption payments were guaranteed by NSP-Minnesota. The preferred securities were redeemable at the option of NSP-Minnesota at $25 per share, beginning in 2002. On July 31, 2003, NSP-Minnesota redeemed the $200 million of trust preferred securities. A certificate of cancellation was filed to dissolve NSP Financing I on Sept. 15, 2003.

PSCo Capital Trust I, a wholly owned, special-purpose subsidiary trust of PSCo, had $194 million of 7.60-percent trust preferred securities issued and outstanding that were originally scheduled to mature in 2038. Distributions paid by the subsidiary trust on the preferred securities were financed through interest payments on debentures issued by PSCo and held by the subsidiary trust, which were eliminated in consolidation. Distributions and redemption payments were guaranteed by PSCo. The securities were redeemable at the option of PSCo after May 2003, at 100 percent of the principal amount outstanding plus accrued interest. On June 30, 2003, PSCo redeemed the $194 million of trust preferred securities. A certificate of cancellation was filed to dissolve PSCo Capital Trust I on Dec. 29, 2003.

Distributions paid to preferred security holders are reflected as a financing cost in the accompanying Consolidated Statements of Income along with interest expense.

7. Joint Plant Ownership (NSP-Minnesota and PSCo)

Following are the investments by Xcel Energy’s subsidiaries in jointly owned plants and the related ownership percentages as of Dec. 31, 2003:


					Construction
	Plant in		Accumulated		Work in
	Service		Depreciation		Progress		Ownership %
			(Thousands of dollars)
NSP-Minnesota:
Sherco Unit 3	$	617,343	$	311,252	$	500		59.0
Transmission facilities, including substations		2,761		843		—		59.0

Total NSP-Minnesota	$	620,104	$	312,095	$	500

PSCo:
Hayden Unit 1	$	85,828	$	40,764	$	—		75.5
Hayden Unit 2		79,818		43,834		76		37.4
Hayden Common Facilities		27,614		4,010		1,017		53.1
Craig Units 1 and 2		58,224		30,876		80		9.7
Craig Common Facilities, Units 1, 2 and 3		19,109		9,246		9,935		6.5 - 9.7
Transmission facilities, including substations		112,594		40,779		18,380		42.0 - 73.0

Total PSCo	$	383,187	$	169,509	$	29,488

NSP-Minnesota is part owner of Sherco 3, an 860-megawatt coal-fueled electric generating unit. NSP-Minnesota is the operating agent under the joint ownership agreement. NSP-Minnesota’s share of operating expenses and construction expenditures are included in the applicable utility components of operating expenses. PSCo’s assets include approximately 320 megawatts of jointly owned generating capacity. PSCo’s share of operating expenses and construction expenditures are included in the applicable utility components of operating expenses. Each of the respective owners is responsible for the issuance of its own securities to finance its portion of the construction costs.

PSCo

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The reasons for the difference at Dec. 31 are:


	2003			2002			2001
Federal statutory rate		35.0	%		35.0	%		35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit		2.9	%		2.7	%		3.3	%
Tax credits recognized		(2.1	)%		(3.0	)%		(1.4	)%
Life insurance policies		(8.1	)%		(6.2	)%		(5.1	)%
Regulatory differences — utility plant items		2.5	%		2.6	%		2.4	%
Resolution of income tax audits		(2.9	)%		—			—
Other — net		0.6	%		1.6	%		(1.6	)%

Effective income tax rate		27.9	%		32.7	%		32.6	%

Income taxes comprise the following expense (benefit) items:


	2003			2002			2001
	(Thousands of dollars)
Current federal tax expense	$	15,643		$	20,833		$	115,347
Current state tax expense (benefit)		(7,649	)		2,338			20,573
Current tax credits		(2,498	)		(7,087	)		(1,523	)
Deferred federal tax expense		74,885			103,108			1,371
Deferred state tax expense (benefit)		11,863			14,159			(55	)
Deferred investment tax credits		(4,033	)		(4,665	)		(4,152	)

Total income tax expense	$	88,211		$	128,686		$	131,561

The components of deferred income tax at Dec. 31 were:


	2003			2002
	(Thousands of dollars)
Deferred tax expense excluding items below	$	92,351		$	44,898
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities		9,966			10,757
Tax expense allocated to other comprehensive income		(15,569	)		61,613

Deferred tax expense	$	86,748		$	117,268

The components of net deferred tax liability (current and noncurrent portions) at Dec. 31 were:


	2003		2002
	(Thousands of dollars)
Deferred tax liabilities:
Differences between book and tax bases of property	$	629,653	$	567,817
Employee benefits and other accrued liabilities		56,181		56,840
Regulatory assets		40,861		36,469
Other		45,234		35,745

Total deferred tax liabilities	$	771,929	$	696,871

Deferred tax assets:
Deferred investment tax credits	$	26,968	$	28,501
Regulatory liabilities		16,447		17,375
Other comprehensive income		48,760		64,329
Net operating loss carryforward		11,144		—
Other		954		11,362

Total deferred tax assets	$	104,273	$	121,567

Net deferred tax liability	$	667,656	$	575,304

SPS


	2003			2002			2001
Federal statutory rate		35.0	%		35.0	%		35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit		1.2	%		(0.3	)%		1.5	%
Tax credits recognized		(0.2	)%		(0.2	)%		(0.1	)%
Regulatory differences — utility plant items		1.7	%		1.9	%		1.8	%
Extraordinary item		—			—			(0.5	)%
Other — net		0.7	%		0.6	%		(0.5	)%

Effective income tax rate including extraordinary items		38.4	%		37.0	%		37.2	%
Extraordinary items		—			—			0.5	%

Effective income tax rate excluding extraordinary items		38.4	%		37.0	%		37.7	%

Income taxes comprise the following expense (benefit) items:


	2003			2002			2001
	(Thousands of dollars)
Current federal tax expense	$	36,272		$	15,913		$	95,648
Current state tax expense (benefit)		1,700			(2,185	)		5,221
Deferred federal tax expense (benefit)		13,005			28,298			(28,493	)
Deferred state tax expense (benefit)		614			1,587			(951	)
Deferred investment tax credits		(250	)		(250	)		(250	)

Income tax expense excluding extraordinary items		51,341			43,363			71,175
Tax expense (benefit) on extraordinary items		—			—			5,747

Total income tax expense	$	51,341		$	43,363		$	76,922

The components of deferred income tax were:


	2003			2002
	(Thousands of dollars)
Deferred tax expense excluding items below	$	15,294		$	29,994
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities		(3,176	)		(192	)
Tax expense allocated to other comprehensive income		1,502			83

Deferred tax expense	$	13,620		$	29,885

The components of net deferred tax liability (current and noncurrent portions) at Dec. 31 were:


	2003		2002
	(Thousands of dollars)
Deferred tax liabilities:
Differences between book and tax bases of property	$	368,341	$	357,874
Employee benefits and other accrued liabilities		38,420		32,719
Regulatory assets		27,719		27,617
Other		13,088		13,034

Total deferred tax liabilities	$	447,568	$	431,244

Deferred tax assets:
Deferred investment tax credits	$	1,428	$	1,519
Regulatory liabilities		794		844
Other		17,219		16,048

Total deferred tax assets	$	19,441	$	18,411

Net deferred tax liability	$	428,127	$	412,833

9. Benefit Plans and Other Postretirement Benefits (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Xcel Energy offers various benefit plans to its benefit employees. Approximately 51 percent of benefit employees are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2003, NSP-Minnesota had 2,244 and NSP-Wisconsin had 427 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2004 but has been tentatively settled to extend until Dec. 31, 2007. PSCo had 2,167 bargaining employees covered under a collective-bargaining agreement, which expires in May 2006. SPS had 739 bargaining employees covered under a collective-bargaining agreement, which expires in October 2005.

Pension Benefits

Xcel Energy has several noncontributory, defined benefit pension plans that cover almost all employees. Benefits are based on a combination of years of service, the employee’s average pay and Social Security benefits.

Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.

Pension Plan Assets - Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government securities. The target range for our pension asset allocation is 75 percent to 80 percent in equity investments, 5 percent to 10 percent in fixed income investments, no cash investments and 10 percent to 15 percent in nontraditional investments, such as real estate, timber ventures, private equity and venture capital.

The actual composition of pension plan assets at Dec. 31 was:


	2003			2002
Equity securities		75	%		68	%
Debt securities		14			16
Real estate		3			—
Cash		—			4
Nontraditional investments		8			12

		100	%		100	%

During 2003, Xcel Energy entered into a number of hedging arrangements within the pension trust designed to provide protection from a loss of asset value in the event of a broad decline in equity prices. These arrangements are expected to expire at the end of 2004. At Dec. 31, 2003, the mark-to-market value of these arrangements was not material to the value of pension trust assets.

Xcel Energy bases its investment return assumption on expected long-term performance for each of the investment types included in its pension asset portfolio. Xcel Energy considers the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The historical weighted average annual return for the past 20 years for the Xcel Energy portfolio of pension investments is 12.7 percent, which is in excess of the current assumption level. The pension cost determinations assume the continued current mix of investment types over the long-term. The Xcel Energy portfolio is heavily weighted toward equity securities, includes nontraditional investments that can provide a higher-than-average return, and in 2003 includes derivative financial instruments intended to hedge the risk of potentially volatile performance of other investments. As is the experience in recent years, a higher weighting in equity investments can increase the volatility in the return levels actually achieved by pension assets in any year. Investment returns in 2001 and 2002 were below the assumed level of 9.5 percent, but in 2003 investment returns exceeded the assumed level of 9.25 percent. Xcel Energy continually reviews its pension assumptions. For 2004, Xcel Energy has changed the investment return assumption to 9.0 percent to reflect the changing expectations of investment experts in the marketplace.

Benefit Obligations - A comparison of the actuarially computed pension benefit obligation and plan assets, on a combined basis, is presented in the following table:


(Thousands of dollars)	2003			2002
Accumulated Benefit Obligation at Dec. 31	$	2,512,138		$	2,381,214
Change in Projected Benefit Obligation
Obligation at Jan. 1	$	2,505,576		$	2,409,186
Service cost		67,449			65,649
Interest cost		170,731			172,377
Acquisitions		—			7,848
Plan amendments		85,937			3,903
Actuarial loss		82,197			65,763
Settlements		(9,546	)		(994	)
Special termination benefits		—			4,445
Curtailment gain		(26,407	)		—
Benefit payments		(243,446	)		(222,601	)

Obligation at Dec. 31	$	2,632,491		$	2,505,576


(Thousands of dollars)	2003			2002
Change in Fair Value of Plan Assets
Fair value of plan assets at Jan. 1	$	2,639,963		$	3,267,586
Actual return on plan assets		605,978			(404,940	)
Employer contributions – acquisitions		31,712			912
Settlements		(9,546	)		(994	)
Benefit payments		(243,446	)		(222,601	)

Fair value of plan assets at Dec. 31	$	3,024,661		$	2,639,963

Funded Status of Plans at Dec. 31
Net asset	$	392,170		$	134,387
Unrecognized transition asset		(7	)		(2,003	)
Unrecognized prior service cost		273,725			224,651
Unrecognized (gain) loss		9,710			165,927

Xcel Energy net pension amounts recognized on balance sheet	$	675,598		$	522,962

NSP-Minnesota prepaid pension asset recorded	$	317,956		$	263,713
NSP-Wisconsin prepaid pension asset recorded		46,384			38,557
PSCo prepaid pension asset recorded		—			—
PSCo intangible asset recorded – prior service costs		5,724			6,874
PSCo accrued benefit liability recorded		(3,096	)		(3,182	)
PSCo minimum pension liability recorded		(54,647	)		(104,773	)
PSCo accumulated other comprehensive income recorded – pretax		155,574			169,958
SPS prepaid pension asset recorded		121,580			105,044
Other Xcel Energy subsidiaries		86,123			46,771

	$	675,598		$	522,962

Measurement Date	Dec.31,2003			Dec.31,2002
Significant Assumptions Used to Measure Benefit Obligations
Discount rate for year-end valuation		6.25	%		6.75	%
Expected average long-term increase in compensation level		3.50	%		4.00	%

During 2002, one of PSCo’s pension plans became under funded, and at Dec. 31, 2003, had projected benefit obligations of $653.1 million, exceeding plan assets of $563.8 million. PSCo has recorded a minimum pension liability of $54.6 million related to the under funded plan as of that date. A corresponding reduction in Accumulated Other Comprehensive Income, a component of Stockholders’ Equity, also was recorded, as previously recorded prepaid pension assets were reduced to record the minimum liability. Net of the related deferred income tax effects of the adjustments, total PSCo Stockholder’s Equity was reduced by $96.4 million at Dec. 31, 2003, due to the minimum pension liability for the under funded plan. All other Xcel Energy plans in the aggregate had plan assets of $2.5 billion and projected benefit obligations of $2.0 billion on Dec. 31, 2003.

A retirement spending account and Social Security supplement for former New Century Energies, Inc. nonbargaining employees was added July 1, 2003, to align it with the Xcel Energy plan formula. In 2000, New Century Energies, Inc. merged with Northern States Power Co. to become Xcel Energy. Also, the Normal Retirement Age for Xcel Energy’s traditional, account balance, and “pension equity” programs was changed to age 65 with one year of service.

Cash Flows - Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other pertinent calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding in the years 2001 through 2003 for Xcel Energy’s pension plans and is not expected to require cash funding in 2004. PSCo elected to make a voluntary contribution of $30 million to its pension plan for bargaining employees in 2003, and it plans to voluntarily contribute another $10 million to the plan in 2004.

Benefit Costs - The components of net periodic pension cost (credit) are:


(Thousands of dollars)	2003			2002			2001
Service cost	$	67,449		$	65,649		$	57,521
Interest cost		170,731			172,377			172,159
Expected return on plan assets		(322,011	)		(339,932	)		(325,635	)
Curtailment (gain) loss		(17,363	)		—			1,121
Settlement (gain) loss		(1,135	)		—			—
Amortization of transition asset		(1,996	)		(7,314	)		(7,314	)
Amortization of prior service cost		28,230			22,663			20,835
Amortization of net gain		(44,825	)		(69,264	)		(72,413	)

Net periodic pension cost (credit) under SFAS No. 87	$	(120,920	)	$	(155,821	)	$	(153,726	)
NSP-Minnesota
Net periodic pension credit	$	(54,243	)	$	(71,928	)	$	(76,509	)
Credits not recognized due to effects of regulation		51,311			71,928			76,509

Net benefit cost (credit) recognized for financial reporting	$	(2,932	)		—			—
NSP Wisconsin
Net periodic pension credit	$	(7,827	)	$	(9,994	)	$	(10,002	)
PSCo
Net periodic pension credit	$	(4,728	)	$	(14,747	)	$	(17,311	)
SPS
Net periodic pension credit	$	(16,536	)	$	(22,235	)	$	(21,131	)
Significant Assumptions Used to Measure Costs
Discount rate		6.75	%		7.25	%		7.75	%
Expected average long-term increase in compensation level		4.00	%		4.50	%		4.50	%
Expected average long-term rate of return on assets		9.25	%		9.50	%		9.50	%

Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2004 pension cost calculations will be 9.0 percent. The cost calculation uses a market-related valuation of pension assets, which reduces year-to-year volatility by recognizing the differences between assumed and actual investment returns over a five-year period.

Xcel Energy and its operating utilities also maintain noncontributory, defined benefit supplemental retirement income plans for certain qualifying executive personnel. Benefits for these unfunded plans are paid out of their operating cash flows.

Defined Contribution Plans

Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees. The contribution for 2003 included $3.2 million for NSP-Minnesota, $0.7 million for NSP-Wisconsin, $4.7 million for PSCo and $1.4 million for SPS.

Until May 6, 2002, Xcel Energy had a leveraged employee stock ownership plan (ESOP) that covered substantially all employees of NSP-Minnesota and NSP-Wisconsin. Xcel Energy made contributions to this noncontributory, defined contribution plan to the extent it realized tax savings from dividends paid on certain ESOP shares. ESOP contributions had no material effect on Xcel Energy earnings because the contributions were essentially offset by the tax savings provided by the dividends paid on ESOP shares. Xcel Energy allocated leveraged ESOP shares to participants when it repaid ESOP loans with dividends on stock held by the ESOP.

In May 2002, the ESOP was terminated and its assets were combined into the Xcel Energy retirement savings 401(k) Plan. Starting with the 2003 plan year, the ESOP component of the 401(k) Plan is no longer leveraged.

Xcel Energy’s leveraged ESOP held no shares of Xcel Energy common stock at the end of 2003 or 2002, 10.7 million shares of Xcel Energy common stock at May 6, 2002, and 10.5 million shares of Xcel Energy common stock at the end of 2001. Xcel Energy excluded the following average number of uncommitted leveraged ESOP shares from earnings-per-share-calculations: 0.7 million in

2002 and 0.9 million in 2001. On Nov. 19, 2002, Xcel Energy paid off all of the ESOP loans. All uncommitted ESOP shares were released and were used by Xcel Energy for the 2002 employer matching contribution to its 401(k) plan.

Postretirement Health Care Benefits

Xcel Energy has contributory health and welfare benefit plans that provide health care and death benefits to most Xcel Energy retirees. The former NSP discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees of NSP-Minnesota and NSP-Wisconsin who retired after 1999. Employees of the former NCE who retired in 2002 continue to receive employer-subsidized health care benefits. Employees of the former NSP who retired after 1998 are eligible to participate in the Xcel Energy health care program with no employer subsidy.

In conjunction with the 1993 adoption of SFAS No. 106 – “Employers’ Accounting for Postretirement Benefits Other Than Pension,” Xcel Energy elected to amortize the unrecognized accumulated postretirement benefit obligation (APBO) on a straight-line basis over 20 years.

Regulatory agencies for nearly all of Xcel Energy’s retail and wholesale utility customers have allowed rate recovery of accrued benefit costs under SFAS No. 106. PSCo transitioned to full accrual accounting for SFAS No. 106 costs between 1993 and 1997, consistent with the accounting requirements for rate-regulated enterprises. The Colorado jurisdictional SFAS No. 106 costs deferred during the transition period are being amortized to expense on a straight-line basis over the 15-year period from 1998 to 2012. NSP-Minnesota also transitioned to full accrual accounting for SFAS No. 106 costs, with regulatory differences fully amortized prior to 1997.

Plan Assets - Certain state agencies that regulate Xcel Energy’s utility subsidiaries also have issued guidelines related to the funding of SFAS No. 106 costs. SPS is required to fund SFAS No. 106 costs for Texas and New Mexico jurisdictional amounts collected in rates, and PSCo is required to fund SFAS No. 106 costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. Minnesota and Wisconsin retail regulators required external funding of accrued SFAS No. 106 costs to the extent such funding is tax advantaged. The investment strategy for the postretirement health care fund assets is fairly conservative, with minimal exposure to equity markets and a focus on fixed income and cash equivalents to preserve investment capital while earning modest income.

The actual composition of postretirement benefit plan assets at Dec. 31 was:


	2003			2002
Fixed income/debt securities		2	%		2	%
Equity mutual fund securities		14			12
Cash equivalents		84			85
Other		—			1

		100	%		100	%

Xcel Energy bases its investment return assumption for the postretirement health care fund assets on expected long-term performance for each of the investment types included in its postretirement health care asset portfolio. Given the fairly short time period in which funding has been required, Xcel Energy does not consider the actual historical returns achieved by its postretirement health care fund asset portfolio to be significant in establishing long-term return assumptions. Instead, Xcel Energy considers the long-term return levels projected and recommended by investment experts, weighted for the target mix of asset categories in our portfolio. We do not consider investment return volatility to be a material factor in postretirement health care costs.

Benefit Obligations - A comparison of the actuarially computed benefit obligation and plan assets for Xcel Energy postretirement health care plans that benefit employees of its utility subsidiaries is presented in the following table:

The assumed health care cost trend rate for 2003 for most Xcel Energy plans is approximately 7.5 percent, decreasing gradually to 5.5 percent in 2007 and remaining level thereafter. A 1-percent change in the assumed health care cost trend rate would have the following effects:


				NSP-			NSP-
(Thousands of dollars)	Xcel Energy			Minnesota			Wisconsin			PSCo			SPS
1-percent increase in APBO components at Dec. 31, 2003	$	95.8		$	16.2		$	2.8		$	62.0		$	9.9
1-percent decrease in APBO components at Dec. 31, 2003		(79.4	)		(14.0	)		(2.4	)		(50.6	)		(8.1	)
1-percent increase in service and interest components of the net periodic cost		7.3			1.0			0.2			4.9			0.8
1-percent decrease in service and interest components of the net periodic cost		(6.0	)		(0.8	)		(0.1	)		(4.0	)		(0.7	)

The employer subsidy for retiree medical coverage was eliminated for former New Century Energies, Inc non-bargaining employees who retire after July 1, 2003. Curtailment and settlement gains resulted from activities of some of Xcel Energy’s nonregulated subsidiaries.

Cash Flows - The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy expects to contribute approximately $51.4 million during 2004.

Benefit Costs - The components of net periodic postretirement benefit cost are:


(Thousands of dollars)	2003			2002			2001
Service cost	$	5,893		$	5,967		$	6,160
Interest cost		52,426			48,304			46,579
Expected return on plan assets		(22,185	)		(21,011	)		(18,920	)
Curtailment (gain) loss		(2,128	)		—			—
Settlement (gain) loss		(916	)		—			—
Amortization of transition obligation		15,426			16,771			16,771
Amortization of prior service cost (credit)		(1,533	)		(1,130	)		(1,235	)
Amortization of net loss (gain)		15,409			5,380			1,457

Net periodic postretirement benefit cost (credit) under SFAS No. 106		62,392			54,281			50,812
NSP-Minnesota
Net periodic postretirement benefit cost recognized – SFAS No. 106		16,897			12,667			11,124
NSP-Wisconsin
Net periodic postretirement benefit cost recognized – SFAS No. 106		2,522			1,531			1,155
PSCo
Net periodic postretirement benefit cost recognized – SFAS No. 106		37,146			30,619			29,910
Additional cost recognized due to effects of regulation		3,883			3,890			3,890

Net cost recognized for financial reporting	$	41,029		$	34,509		$	33,800
SPS
Net periodic postretirement benefit cost recognized – SFAS No. 106		6,175			5,542			3,254
Additional cost recognized due to effects of regulation		—			153			(152	)

Net cost recognized for financial reporting	$	6,175		$	5,695		$	3,102
Significant assumptions used to measure costs (income)
Discount rate		6.75	%		7.25	%		7.75	%
Expected average long-term rate of return on assets (before tax)		8.0%-9.0	%		9.0	%		8.0%-9.5	%

Impact of 2003 Medicare Legislation - On Dec. 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act expanded Medicare to include, for the first time, coverage for prescription drugs. This new coverage is generally effective Jan. 1, 2006. Many of Xcel Energy’s retiree medical programs provide prescription drug coverage for retirees over age 65 with coverage at least equivalent to the benefit to be provided under Medicare. While retirees remain in Xcel Energy’s postretirement health care plan without participating in the new Medicare prescription drug coverage, Medicare will share the cost of Xcel Energy’s plan. This legislation has therefore reduced Xcel Energy’s share of the obligation for future retiree medical benefits.

The postretirement health care benefit obligation shown in the chart previously is the actuarial present value, as of Dec. 31, 2003, of Xcel Energy’s share of future retiree medical benefits attributable to service through the current year. This obligation has been reduced to reflect the effects of this legislation. The FASB has not yet issued authoritative guidance on the method it prefers to reflect the Act in these calculations. In addition, regulations implementing this legislation have not yet been issued by Medicare agencies. As a result, when guidance and regulations are issued, the estimates of future costs and obligations could change and previously reported information could be modified.

As of Dec. 31, 2003, Xcel Energy has reduced the postretirement health care benefit obligation by $64.6 million due to the expected sharing of the cost of the program by Medicare under the new legislation. Also, beginning in 2004, it is expected that the annual net periodic postretirement benefit cost will be reduced by approximately $10 million as a result of the expected sharing of the cost of the program by Medicare, with similar savings in subsequent years. This reduction includes both the decrease in the cost of future benefits being earned during this year, and an amortization of the benefit obligation reduction, previously noted, over approximately nine years. These estimated reductions do not reflect any changes that may result in future levels of participation in the plan or the associated per capita claims cost due to the availability of prescription drug coverage for Medicare-eligible retirees. Also, in reflecting this legislation, Medicare cost sharing for a plan has been assumed only if Xcel Energy’s projected contribution to the plan is expected to be at least equal to the Medicare Part D basic benefit.

10. Extraordinary Items (SPS)

In April 2003, New Mexico enacted legislation that repealed its Electric Utility Restructuring Act of 1999, as amended. The legislation provides that a public utility be entitled to an opportunity to recover its transition costs. Utilities, including SPS, may retain the transition costs as a regulatory asset on their books pending recovery, which shall be completed by January 2010.

In June 2001, the Governor of Texas signed legislation postponing retail competition and restructuring of SPS until at least 2007. This legislation amended the 1999 legislation, Senate Bill No. 7 (SB-7), which provided for retail electric competition beginning in Texas in January 2002. Under the amended legislation, prior PUCT orders issued in connection with the restructuring of SPS are considered null and void. In addition, under the new legislation, SPS is entitled to recover all reasonable and necessary expenditures made or incurred before Sept. 1, 2001, to comply with SB-7.

As a result of these legislative developments, SPS reapplied the provisions of SFAS No. 71 for its generation business during the second quarter of 2001. More than 95 percent of SPS’ retail electric revenues are from operations in Texas and New Mexico. Because of the delays to electric restructuring passed by Texas and New Mexico, SPS’ previous plans to implement restructuring, including the divestiture of generation assets, have been abandoned. Accordingly, SPS will continue to be subject to rate regulation under traditional cost-of-service regulation, consistent with its past accounting and ratemaking practices for the foreseeable future, at least until 2007.

During the fourth quarter of 2001, SPS completed a $500-million, medium-term debt financing with the proceeds used to reduce short-term borrowings that had resulted from the 2000 defeasance of first mortgage bonds. In its regulatory filings and communications, SPS proposed to amortize its defeasance costs over the five-year life of the refinancing, consistent with historical ratemaking, and requested incremental rate recovery of $25 million of other restructuring costs in Texas and New Mexico. These nonfinancing restructuring costs have been deferred and are being amortized consistent with rate recovery. Based on these 2001 events, management’s expectation of rate recovery of prudently incurred costs and the corresponding reduced uncertainty surrounding the financial impacts of the delay in restructuring, SPS restored certain regulatory assets totaling $17.6 million as of Dec. 31, 2001, and reported related after-tax extraordinary income of $11.8 million. Regulatory assets previously written off in 2000 were restored only for items currently being recovered in rates and items where future rate recovery is considered probable.

See Note 2 for discussion of special charges related to SPS restructuring in 2002.

11. Financial Instruments (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Fair Values

The estimated Dec. 31 fair values of Xcel Energy’s utility subsidiary recorded financial instruments are:


	2003				2002
	Carrying				Carrying
(Thousands of dollars)	Amount		Fair Value		Amount		Fair Value
NSP-Minnesota
Mandatorily redeemable preferred securities of subsidiary trust	$	—	$	—	$	200,000	$	188,080
Long-term investments		781,951		781,952		619,502		619,452
Long-term debt, including current portion		1,945,460		2,191,052		1,796,400		1,884,050
NSP-Wisconsin
Long-term investments		—		—		10		10
Long-term debt, including current portion		313,444		339,165		313,142		320,884
PSCo
Mandatorily redeemable preferred securities of subsidiary trust		—		—		194,000		178,868
Long-term investments		27,630		27,630		6,598		6,598
Long-term debt, including current portion		2,458,565		2,599,808		2,064,225		2,147,775
SPS
Mandatorily redeemable preferred securities of subsidiary trust		—		—		100,000		96,400
Long-term investments		7,675		8,446		9,622		8,098
Long-term debt, including current portion		825,147		865,033		725,662		748,666

The carrying amount of cash, cash equivalents, short-term investments and other financial instruments approximates fair value because of the short maturity of those instruments. The fair values of Xcel Energy’s utility subsidiaries’ long-term investments, mainly debt securities in an external nuclear decommissioning fund held by NSP-Minnesota, are estimated based on quoted market prices for those or similar investments. The fair value of Xcel Energy’s utility subsidiaries’ long-term debt and the mandatorily redeemable preferred securities are estimated based on the quoted market prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality.

The fair value estimates presented are based on information available to management as of Dec. 31, 2003 and 2002. These fair value estimates have not been comprehensively revalued for purposes of these Consolidated Financial Statements since that date, and current estimates of fair values may differ significantly.

Guarantees

Xcel Energy’s utility subsidiaries had the following guarantees outstanding on Dec. 31, 2003:


Guarantor		NSP-Minnesota

Guarantee amount		$2.1 million

Exposure under guarantee		$2.1 million

Nature of guarantee		NSP-Minnesota sold a portion of its receivables (consisting of customer loans to local and state government entities for energy efficiency improvements) to a third party. Under the sales agreements, NSP-Minnesota is required to guarantee repayment to the third party of the remaining loan balances. Based on prior collection experience of these loans, losses under the loan guarantees, if any, are not believed to have a material impact on the results of operations.


Guarantor		PSCo

Guarantee amount		$0.5 million

Exposure under guarantee		$0.0 million

Nature of guarantee		Primarily bonds to guarantee restoration of sites that have been disturbed to access utility equipment.

Term of guarantee		2004

Triggering events or circumstances requiring performance under the guarantee		Failure of PSCo to perform under the agreement which is the subject of the relevant bond. In addition, per the indemnity agreement between PSCo and the various surety companies, the surety companies have the discretion to demand collateral be posted.

Current carrying amount of the liability		n/a

Nature of any recourse provisions		None

Any assets held as collateral		None

Letters of Credit

Xcel Energy’s utility subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. The following table details the letters of credit outstanding for Xcel Energy’s utility subsidiaries at Dec. 31, 2003. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined by the market.


(Thousands of dollars)	NSP-Minnesota			PSCo		SPS
Letters of credit outstanding		$	43.3	$	1.2	$	9.4

12. Derivative Valuation and Financial Impacts (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Use of Derivatives to Manage Risk

Business and Operational Risk — Xcel Energy’s utility subsidiaries are exposed to commodity price risk in their generation, retail distribution and energy trading operations. NSP-Minnesota and SPS recover purchased energy expenses on a dollar-for-dollar basis. NSP-Minnesota, NSP-Wisconsin and PSCo recover purchased natural gas costs on a dollar-for-dollar basis. However, NSP-Wisconsin and PSCo have limited exposure to market price risk for the purchase and sale of electric energy. In these jurisdictions, electric energy expenses are recovered based on fixed-price limits or under established sharing mechanisms. NSP-Minnesota is authorized to recover certain financial instrument costs, incurred to mitigate wholesale electric and gas commodity price volatility in rates, through the fuel clause adjustment and purchased gas adjustment.

NSP-Minnesota, PSCo and SPS manage commodity price risk by entering into purchase and sales commitments for electric power and natural gas, long-term contracts for coal supplies and fuel oil, and derivative instruments. Xcel Energy’s risk management policy allows the utility subsidiaries to manage the market price risk within each rate-regulated operation to the extent such exposure exists. Xcel Energy’s utility subsidiaries uses various physical contracts and derivative instruments to reduce the volatility in the cost of natural gas and electricity provided to retail customers even though the regulatory jurisdiction may provide dollar-for-dollar recovery of actual costs. In these instances, the use of derivative instruments and physical contracts is done consistently with the local jurisdictional cost-recovery mechanism.

100

Xcel Energy’s utility subsidiaries engage in hedges of cash flow exposure. The fair value of interest rate swaps designated as cash flow hedges are initially recorded in Other Comprehensive Income. Reclassification of unrealized gains or losses on cash flow hedges of variable rate debt instruments from Other Comprehensive Income into earnings occurs as interest payments are accrued on the debt instrument and generally offsets the change in the interest accrued on the underlying variable rate debt. Hedges of fair value exposure are entered into to hedge the fair value of a recognized asset, liability or firm commitment. Changes in the derivative fair values that are designated as fair value hedges are recognized in earnings as offsets to the changes in fair values of related hedged assets, liabilities or firm commitments. In order to test the effectiveness of such swaps, a hypothetical swap is used to mirror all the critical terms of the underlying debt and regression analysis is utilized to assess the effectiveness of the actual swap at inception and on an ongoing basis. The assessment is done periodically to ensure the swaps continue to be effective. The fair value of interest rate swaps is determined through counterparty valuations, internal valuations and broker quotes. There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented.

Trading Risk — NSP-Minnesota and PSCo conduct various trading operations, including the purchase and sale of electric capacity and energy. Xcel Energy’s risk management policy allows the utility subsidiaries to conduct the trading activity within approved guidelines and limitations as approved by the company’s risk management committee, which is made up of management personnel not involved in the trading operations. This trading includes the use of forward contracts, futures and options. PSCo and NSP-Minnesota make purchases and sales at existing market points or combine purchases with available transmission to make sales at other market points. Options and hedges are used to either minimize the risks associated with market prices, or to profit from price volatility related to our purchase and sale commitments.

As discussed in Note 1, PSCo and NSP-Minnesota present the results of their electric trading activity net in operating revenue. The mark-to-market adjustments for these transactions are reported in the Consolidated Statement of Income in Electric Trading Margin.

The fair value of the energy trading contracts as of Dec. 31, 2003 was as follows:


	NSP-
(Millions of dollars)	Minnesota			PSCo
Fair value of trading contracts outstanding at Jan. 1, 2003	$	(0.2	)	$	0.1
Contracts realized or settled during the year		(13.6	)		(0.8	)
Fair value of trading contract additions and changes during the year		17.3			1.4

Fair value of contracts outstanding at Dec. 31, 2003	$	3.5		$	0.7

Fair Value of Derivatives

As of Dec. 31, 2003, the sources of fair value of the energy trading and hedging net assets were as follows:

Trading Contracts


	Futures/Forwards
(Thousands of	Source of		Maturity Less			Maturity		Maturity		Maturity Greater		Total Futures/
dollars)	Fair Value		than 1 Year			1 to 3 Years		4 to 5 Years		than 5 Years		Forwards Fair Value
NSP-Minnesota		1	$	(143	)	$	—	$	—	$	—	$	(143	)
		2		3,163			486		—		—		3,649
PSCo		1		(69	)		—		—		—		(69	)
		2		693			36		—		—		729

Total futures/forwards fair value			$	3,644		$	522	$	—	$	—	$	4,166

101

Hedge Contracts


	Futures/Forwards
(Thousands of	Source of		Maturity Less		Maturity		Maturity		Maturity Greater		Total Futures/
dollars)	Fair Value		than 1 Year		1 to 3 Years		4 to 5 Years		than 5 Years		Forwards Fair Value
NSP-Minnesota futures/forwards fair value		2	$	569	$	—	$	—	$	—	$	569


	Options
(Thousands of	Source of		Maturity Less			Maturity		Maturity		Maturity Greater
dollars)	Fair Value		than 1 Year			1 to 3 Years		4 to 5 Years		than 5 Years		Total Options Fair Value
NSP-Minnesota		2	$	(1,287	)	$	—	$	—	$	—	$	(1,287	)
NSP-Wisconsin		2		168			—		—		—		168
PSCo		2		(11,466	)		848		—		—		(10,618	)

Total options fair value			$	(12,585	)	$	848	$	—	$	—	$	(11,737	)

1 — Prices actively quoted or based on actively quoted prices.

2 — Prices based on models and other valuation methods. These represent the fair value of positions calculated using internal models when directly and indirectly quoted external prices or prices derived from external sources are not available. Internal models incorporate the use of options pricing and estimates of the present value of cash flows based upon underlying contractual terms. The models reflect management’s estimates, taking into account observable market prices, estimated market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors, estimated correlations of energy commodity prices and contractual volumes. Market price uncertainty and other risks also are factored into the model.

In the above tables, only hedge transactions are included for NSP-Minnesota, NSP-Wisconsin and PSCo. Normal purchases and sales transactions, as defined by SFAS No. 133, have been excluded.

Xcel Energy’s utility subsidiaries’ energy marketing operations hedge energy market risks with a combination of electric and gas futures and forward contracts, options, and by holding an inventory of natural gas. At Dec. 31, the notional value and fair value of these contracts were:


	2003								2002 (a)
	NSP-			NSP-					NSP-		NSP-
(Millions of dollars)	Minnesota			Wisconsin		PSCo			Minnesota		Wisconsin		PSCo
Fair value asset (liability)	$	(0.7	)	$	0.2	$	(10.6	)	$	0.5	$	—	$	1.6

(a) 2002 fair values have been restated to be consistent with 2003 risk disclosure grouping.

Derivatives as Hedges

Xcel Energy’s utility subsidiaries record all derivative instruments on the balance sheet at fair value unless exempted, as a normal purchase or sale. Changes in non-exempt derivative instrument’s fair value are recognized currently in earnings unless the derivative has been designated in a qualifying hedging relationship. The application of hedge accounting allows a derivative instrument’s gains and losses to offset related results of the hedged item in the statement of income, to the extent effective. SFAS No. 133, as amended,

102

requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.

Xcel Energy’s utility subsidiaries formally document hedge relationships, including, among other things, the identification of the hedging instrument and the hedged transaction, as well as the risk management objectives and strategies for undertaking the hedged transaction. Derivatives are recorded in the balance sheet at fair value. Xcel Energy’s utility subsidiaries also formally assess, both at inception and at least quarterly thereafter, whether the derivative instruments being used are highly effective in offsetting changes in either the fair value or cash flows of the hedged items.

The impact of the components of hedges, on Xcel Energy’s utility subsidiaries Other Comprehensive Income, included in the Consolidated Statements of Stockholders’ Equity, are detailed in the following table:


	NSP-			NSP-
(Millions of dollars)	Minnesota			Wisconsin			PSCo			SPS
Net unrealized transition gain (loss) at adoption, Jan. 1, 2001	$	—		$	—		$	1.6			$	(2.6	)
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges		0.1			—			(26.3	)			(2.4	)
After-tax net realized losses on derivative transactions reclassified into earnings		—			—			20.4				0.6

Accumulated other comprehensive income (loss) related hedges at Dec. 31, 2001	$	0.1		$	—		$	(4.3	)		$	(4.4	)
After-tax net unrealized gains related to derivatives accounted for as hedges		—			—			10.3				0.3
After-tax net realized gains on derivative transactions reclassified into earnings		(0.1	)		—			(5.0	)			(0.5	)

Accumulated other comprehensive income (loss) related to hedges at Dec. 31, 2002	$	—		$	—		$	1.0			$	(4.6	)
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges		(0.2	)		(1.1	)		18.0				(3.1	)
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		0.2			—			(1.8	)			0.5

Accumulated other comprehensive income (loss) related to hedges at Dec. 31, 2003	$	—		$	(1.1	)	$	17.2			$	(7.2	)

NSP-Minnesota and PSCo enter into derivative instruments to manage variability of future cash flows from changes in commodity prices. These derivative instruments are designated as cash flow hedges for accounting purposes, and the changes in the fair value of these instruments are recorded as a component of Other Comprehensive Income. At Dec. 31, 2003, NSP-Minnesota and PSCo had various commodity-related contracts deemed as cash flow hedges through March 2004 and December 2009, respectively.

Amounts deferred are recorded in earnings as the hedged purchase or sales transaction is settled. This could include the physical purchase or sale of electric energy, the use of natural gas to generate electric energy or gas purchased for resale. As of Dec. 31, 2003, none of the utility subsidiaries had gains or losses accumulated in Other Comprehensive Income that are expected to be recognized in earnings or deferred as regulatory liabilities during the next 12 months related to commodity hedges.

PSCo recorded gains of $0 and $0.4 million related to ineffectiveness on commodity cash flow hedges during the years ended Dec. 31, 2003 and 2002, respectively. NSP-Minnesota, NSP-Wisconsin and SPS did not realize any material impact to earnings related to ineffective hedges during 2003 and 2002.

SPS enters into interest rate swap instruments that effectively fix the interest payments on certain floating rate debt obligations. These derivative instruments are designated as cash flow hedges for accounting purposes, and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. The fair value of this interest rate swap on Dec. 31, 2003 was approximately $(9.5) million. SPS expects to reclassify into earnings during the next 12 months net losses from Other Comprehensive Income of approximately $0.9 million.

103

NSP-Wisconsin, PSCo and SPS also enter into interest rate lock agreements that effectively fix the yield or price on a specified treasury security for a specific period. These derivative instruments are designated as cash flow hedges for accounting purposes, and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. PSCo expects to reclassify into earnings during the next 12 months net gains from Other Comprehensive Income of approximately $1.5 million. NSP-Wisconsin and SPS will not have material amounts to be reclassified into earnings during the next 12 months.

Hedge effectiveness is recorded based on the nature of the item being hedged. Hedging transactions for the sales of electric energy are recorded as a component of revenue; hedging transactions for fuel used in energy generation are recorded as a component of fuel costs; hedging transactions for gas purchased for resale are recorded as a component of gas costs; and hedging transactions for interest rate swaps and interest rate lock agreements are recorded as a component of interest expense. Certain Xcel Energy utility subsidiaries are allowed to recover in electric or gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.

Derivatives Not Qualifying for Hedge Accounting

NSP-Minnesota and PSCo have trading operations that enter into derivative instruments. These derivative instruments are accounted for on a mark-to-market basis in the Consolidated Statements of Operations. The results of these transactions are recorded within Operating Revenues on the Consolidated Statements of Operations.

Normal Purchases or Normal Sales — Xcel Energy’s utility subsidiaries enter into contracts for the purchase and sale of various commodities for use in their business operations. SFAS No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that otherwise meet the definition of a derivative may be exempted from SFAS No. 133 as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. In addition, normal purchase and normal sales contracts must have a price that is clearly and closely related to the asset being sold or purchased. Contracts that meet the requirements of normal are documented and exempted from the accounting and reporting requirements of SFAS No. 133. In June 2003, the Derivatives Implementation Group of FASB issued Implementation Issue No. C20 (C20) to clarify the circumstances when a price is not clearly and closely related to the asset being sold or purchased. Xcel Energy’s implementation of C20 in 2003 had no impact on earnings. However, certain contracts did require a one-time fair value adjustment as of Oct. 1, 2003. The result of this adjustment was the creation of a derivative liability with an offsetting regulatory asset to reflect expected recovery of the amounts from customers. The derivative asset and related regulatory liability will be amortized over the respective lives of the contracts. See Note 15 to the Consolidated Financial Statements.

Xcel Energy’s utility subsidiaries evaluate all of the contracts within regulated operations when such contracts are entered to determine if they are derivatives and, if so, if they qualify and meet the normal designation requirements under SFAS No. 133. None of the contracts entered into within the trading operations qualify for a normal designation.

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

13. Commitments and Contingent Liabilities (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Legislative Resource Commitments (NSP-Minnesota) — In 1994 and 2003, NSP-Minnesota received Minnesota legislative approval for additional on-site temporary spent fuel storage facilities at its Prairie Island nuclear power plant, provided NSP-Minnesota satisfies certain requirements. The use of 29 dry cask containers has been approved. As of Dec. 31, 2003, NSP-Minnesota had loaded 17 of the containers.

In 1994, as a condition of approving 17 dry cask storage containers, the Minnesota Legislature established several energy resource and other commitments for NSP-Minnesota to obtain the Prairie Island temporary nuclear fuel storage facility approval. These commitments can be met by building, purchasing or, in the case of biomass, converting generation resources. Other commitments established by the Legislature included a discount for low-income electric customers, required conservation improvement expenditures and various study and reporting requirements to a legislative electric energy task force. NSP-Minnesota has implemented programs to meet the legislative commitments. NSP-Minnesota’s capital commitments include the known effects of the Prairie Island legislation.

104

On May 29, 2003, the Minnesota Legislature enacted legislation, which will enable NSP-Minnesota to store at least 12 more casks of spent fuel outside the Prairie Island nuclear generating plant. This will allow NSP-Minnesota to continue to operate the facility and store spent fuel there until its licenses with the NRC expire in 2013 and 2014. The legislation transfers the primary authority concerning future spent-fuel storage issues from the state Legislature, 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. The legislation requires NSP-Minnesota to add at least 300 megawatts of additional wind power by 2010 with an option to own 100 megawatts of this power.

The legislation also requires payments during the remaining operating life of the Prairie Island plant. These payments include: $2.25 million per year to the Prairie Island Tribal Community beginning in 2004; 5 percent of NSP-Minnesota’s conservation program expenditures (estimated at $2 million per year) to the University of Minnesota for renewable energy research; and an increase in funding commitments to the previously established Renewable Development Fund from $8.5 million in 2002 to $16 million per year beginning in 2003. The legislation also designated $10 million in one-time grants to the University of Minnesota for additional renewable energy research, which is to be funded from commitments already made to the Renewable Development Fund. All of the cost increases to NSP-Minnesota from these required payments and funding commitments are expected to be recoverable in Minnesota retail customer rates, mainly through existing cost recovery mechanisms. Funding commitments to the Renewable Development Fund would terminate after the Prairie Island plant discontinues operation unless the MPUC determines that NSP-Minnesota failed to make a good faith effort to move the waste, in which case NSP-Minnesota would have to make payments in the amount of $7.5 million per year.

Reliability Commitments (NSP-Minnesota) – 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. Initially, the settlement requires NSP-Minnesota to refund $1 million to customers in Minnesota, which has been accrued. In addition, it requires NSP-Minnesota to incur at least $15 million of costs for actions to improve system reliability above amounts being currently recovered in rates by Jan. 1, 2005. The MPUC modified the settlement to include an additional under-performance payment for any future finding of inaccurate reliability data. Both state agencies and NSP-Minnesota have the option to void the settlement. The final order was issued on March 10, 2004, and all parties to the settlement have twenty days from the date of the order to seek clarification or rehearing.

Capital Commitments (NSP-Minnesota) – NSP-Minnesota expects to incur approximately $43 million in capital expenditures and $988 million for environmental improvements related to modifications to reduce the emissions of NSP-Minnesota’s generating plants located in the Minneapolis-St. Paul metropolitan area pursuant to the metropolitan emissions reduction project (MERP). The MERP project will begin major construction in 2005 and finish in 2009. NSP-Minnesota expects cash recovery of the costs of the emission-reduction project through customer rates beginning in 2006.

Tax Matters (PSCo) — PSCo’s wholly owned subsidiary PSR Investments, Inc. (PSRI) owns and manages permanent life insurance policies on PSCo employees, known as corporate-owned life insurance (COLI). At various times, borrowings have been made against the cash values of these COLI policies and deductions taken on the interest expense on these borrowings. The IRS had issued a Notice of Proposed Adjustment proposing to disallow interest expense deductions taken in tax years 1993 through 1997 related to COLI policy loans. A request for technical advice from the IRS National Office with respect to the proposed adjustment had been pending. Late in 2001, Xcel Energy received a technical advice memorandum from the IRS National Office, which communicated a position adverse to PSRI. Consequently, the IRS examination division has disallowed the interest expense deductions for the tax years 1993 through 1997.

After consultation with tax counsel, it is Xcel Energy’s position that the IRS determination is not supported by the tax law. Based upon this assessment, management continues to believe that the tax deduction of interest expense on the COLI policy loans is in full compliance with the tax law. Therefore, Xcel Energy intends to challenge the IRS determination, which could require several years to reach final resolution. Although the ultimate resolution of this matter is uncertain, management continues to believe the resolution of this matter will not have a material adverse impact on Xcel Energy’s financial position, results of operations or cash flows. For these reasons, PSRI has not recorded any provision for income tax or interest expense related to this matter and has continued to take deductions for interest expense related to policy loans on its income tax returns for subsequent years. However, defense of Xcel Energy’s position may require significant cash outlays on a temporary basis, if refund litigation is pursued in U. S. District Court.

105

The total disallowance of interest expense deductions for the period of 1993 through 1997, as proposed by the IRS, is approximately $175 million. Additional interest expense deductions for the period 1998 through 2003 are estimated to total approximately $404 million. Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2003, would reduce earnings by an estimated $254 million after tax.

Leases — Xcel Energy’s utility subsidiaries lease a variety of equipment and facilities used in the normal course of business. Some of these leases qualify as capital leases and are accounted for accordingly. The capital leases expire in 2024 and 2025. The net book value of property under capital leases was approximately $48 million and $50 million at Dec. 31, 2003 and 2002, respectively. Assets acquired under capital leases are recorded as property at the lower of fair-market value or the present value of future lease payments and are amortized over their actual contract term in accordance with practices allowed by regulators. The related obligation is classified as long-term debt. Executory costs are excluded from the minimum lease payments.

The remainder of the leases, primarily leases of coal-hauling railcars, trucks, cars and power-operated equipment are accounted for as operating leases. The amounts paid under operating leases during 2003 for Xcel Energy’s utility subsidiaries are listed in the following table:

Rental expense under operating leases was:


	2003		2002		2001
	(Millions of dollars)
NSP-Minnesota	$	27.1	$	31.0	$	30.7
NSP-Wisconsin		3.8		4.8		4.7
PSCo		22.4		22.6		2.6
SPS		3.5		4.6		0.1

Future commitments under operating leases are:


	2004		2005		2006		2007		2008
			(Millions of dollars)
NSP-Minnesota	$	21.6	$	21.4	$	21.4	$	21.4	$	21.0
NSP-Wisconsin		3.1		3.2		3.2		3.2		3.2
PSCo		8.6		8.4		8.6		8.6		8.6
SPS		2.2		2.2		2.1		2.1		2.1

Future commitments under PSCo’s two capital leases are:


	(Millions of dollars)
2004	$	7
2005		7
2006		7
2007		7
2008		6
Thereafter		72

Total minimum obligation		106
Interest		(58	)

Present value of minimum obligation	$	48

Nuclear Insurance — NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $10.9 billion under the 1988 Price-Anderson amendment to the Atomic Energy Act of 1954. NSP-Minnesota has secured $300 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $10.6 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. NSP-Minnesota is subject to assessments of up to $100.6 million for each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $10 million per reactor during any one year.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL). The coverage limits are $2.0 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of

106

nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $7.5 million for business interruption insurance and $25.6 million for property damage insurance if losses exceed accumulated reserve funds.

Fuel Contracts — The utility subsidiaries of Xcel Energy have contracts providing for the purchase and delivery of a significant portion of their current coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2004 and 2025. In addition, the utility subsidiaries of Xcel Energy are required to pay additional amounts depending on actual quantities shipped under these agreements. The potential risk of loss for the utility subsidiaries of Xcel Energy, in the form of increased costs, from market price changes in fuel is mitigated through the cost-of-energy adjustment provision of the ratemaking process, which provides for recovery of most fuel costs.

The minimum purchase for each utility subsidiary of Xcel Energy, based on fixed and index-based prices under these contracts as of Dec. 31, 2003, is as follows:


					Natural Gas		Gas Storage &
	Coal		Nuclear Fuel		Supply		Transportation
	(Millions of dollars)
NSP-Minnesota and NSP-Wisconsin (combined)	$	352	$	93	$	480	$	142
PSCo	$	660	$	—	$	601	$	644
SPS	$	1,689	$	—	$	19	$	4

Purchased Power Agreements — The utility subsidiaries of Xcel Energy have entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. NSP-Minnesota, PSCo and SPS have various pay-for-performance contracts with expiration dates through the year 2033. In general, these contracts provide for capacity payments, subject to meeting certain contract obligations and energy payments based on actual power taken under the contracts. Most of the capacity and energy costs are recovered through base rates and other cost recovery mechanisms.

At Dec. 31, 2003, the estimated future payments for capacity that the utility subsidiaries of Xcel Energy are obligated to purchase, subject to availability, are as follows (Thousands of dollars):


	NSP-Minnesota*		PSCo		SPS
2004	$	132,220	$	401,917	$	18,150
2005		110,484		425,623		18,477
2006		111,253		418,309		18,425
2007		113,883		430,276		18,758
2008 and thereafter		1,419,726		2,243,601		295,089

Total	$	1,887,566	$	3,919,726	$	368,899

* Includes amounts allocated to NSP-Wisconsin through intercompany charges.

Environmental Contingencies

Xcel Energy and its utility subsidiaries are subject to regulations covering air and water quality, the storage of natural gas and the storage and disposal of hazardous or toxic wastes. We continuously assess our compliance. Regulations, interpretations and enforcement policies can change, which may impact the cost of building and operating our facilities.

Site Remediation — We must pay all or a portion of the cost to remediate sites where past activities of our subsidiaries and some other parties have caused environmental contamination. At Dec. 31, 2003 there were three categories of sites:

107

• third party sites, such as landfills, to which we are alleged to be a potentially responsible party (PRP) that sent hazardous materials and wastes,

• the site of a former federal uranium enrichment facility, and

• sites of former manufactured gas plants (MGP’s) operated by our subsidiaries or predecessors.

We record a liability when we have enough information to develop an estimate of the cost of remediating a site and revise the estimate as information is received. The estimated remediation cost may vary materially.

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

We revise our estimates as facts become known, but at Dec. 31, 2003 our estimated liability for the cost of remediating sites was:


			Current Portion
(Thousands of dollars)	Total Liability		of Liability
NSP-Minnesota	$	15,527	$	5,104
NSP-Wisconsin		20,219		2,764
PSCo		7,422		4,672
SPS		—		—

Some of the cost of remediation may be recovered from:

• insurance coverage;

• other parties that have contributed to the contamination; and

• customers.

Neither the total remediation cost nor the final method of cost allocation among all PRPs of the unremediated sites has been determined. We have recorded estimates of our share of future costs for these sites. We are not aware of any other parties’ inability to pay, nor do we know if responsibility for any of the sites is in dispute.

Federal Uranium Enrichment Facility — Approximately $8.9 million of the long-term liability and $4.5 million of the current liability for NSP-Minnesota, and approximately $1.2 million of the long-term liability for PSCo, relate to a DOE assessment for decommissioning a federal uranium enrichment facility. These environmental liabilities do not include accruals recorded and collected from customers in rates for future nuclear fuel disposal costs or decommissioning costs related to NSP-Minnesota’s nuclear generating plants. See Note 14 to Consolidated Financial Statements for further discussion of nuclear obligations.

Asbestos Removal — Some of our facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. Since we intend to operate most of these facilities indefinitely, we cannot estimate the amount or timing of payments for its final removal. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

NSP-Minnesota

MGP Sites — NSP-Minnesota has investigated and remediated MGP sites in Minnesota and North Dakota. The MPUC allowed NSP-Minnesota to defer, rather than immediately expense, certain remediation costs of four active remediation sites in 1994. This deferral accounting treatment may be used to accumulate costs that regulators might allow us to recover from our customers. The costs are deferred as a regulatory asset until recovery is approved, and then the regulatory asset is expensed over the same period as the regulators have allowed us to collect the related revenue from our customers. In September 1998, the MPUC allowed the recovery of a portion of these MGP site remediation costs in natural gas rates. Accordingly, NSP-Minnesota has been amortizing the related deferred remediation costs to expense. In 2001, the North Dakota Public Service Commission allowed the recovery of part of the cost of remediating another former MGP site in Grand Forks, N.D. The recoverable cost of remediating that site, $2.9 million, was accumulated in a regulatory asset that is now being expensed evenly over eight years. NSP-Minnesota may request recovery of costs to remediate other sites following the completion of preliminary investigations.

108

Plant Emissions — On Dec. 10, 2001, the Minnesota Pollution Control Agency issued a notice of violation to NSP-Minnesota alleging air quality violations related to the replacement of a coal conveyor and violations of an opacity limitation at the A.S. King generating plant. NSP-Minnesota has responded to the notice of violation and is working to resolve its allegations.

NSP-Minnesota New Source Review (NSR) Information Request – On Nov. 3, 1999, the U. S. Department of Justice filed suit, related to alleged modifications of electric generating stations located in the South and Midwest, against a number of electric utilities for alleged violations of the Clean Air Act’s NSR requirements. Subsequently, the EPA also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities, including Xcel Energy, seeking to determine whether these utilities engaged in activities that may have been in violation of the NSR requirements. In 2001, Xcel Energy responded to the EPA’s initial information requests related to NSP-Minnesota plants in Minnesota. On May 22, 2002, the EPA issued a follow-up information request to Xcel Energy seeking additional information regarding NSR compliance at its plants in Minnesota. Xcel Energy completed its response to the follow-up information request during the fall of 2002.

NSP-Wisconsin

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

The Wisconsin Department of Natural Resources (WDNR) and NSP-Wisconsin have each developed several estimates of the ultimate cost to remediate the Ashland site. The estimates vary significantly, between $4.0 million and $93.0 million, because different methods of remediation and different results are assumed in each. The Environmental Protection Agency (EPA) and WDNR have not yet selected the method of remediation to use at the site. Until the EPA and the WDNR select a remediation strategy for all operable units at the site and determine the level of responsibility of each PRP, we are not able to accurately determine our share of the ultimate cost of remediating the Ashland site.

In the interim, NSP-Wisconsin has recorded a liability of $18.5 million for its estimate of its share of the cost of remediating the Ashland site, using information available to date and reasonably effective remedial methods. NSP-Wisconsin has deferred, as a regulatory asset, the remediation costs accrued for the Ashland site because we expect that the Public Service Commission of Wisconsin (PSCW) will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site, and has authorized recovery of similar remediation costs for other Wisconsin utilities. External MGP costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed as part of the Wisconsin biennial retail rate case process for prudence. Once approved by the PSCW, deferred MGP amounts, less carrying costs, are historically amortized over four or six years. In addition, the Wisconsin Supreme Court rendered a ruling that reopens the possibility that NSP-Wisconsin may be able to recover a portion of the remedial costs from its insurance carriers.

As an interim action, Xcel Energy proposed, and the EPA and WDNR have approved, a coal tar removal and groundwater treatment system for one operable unit at the site for which NSP-Wisconsin has accepted responsibility. The groundwater treatment system began operating in the fall of 2000. In 2002, NSP-Wisconsin installed additional monitoring wells in the deep aquifer to better characterize the extent and degree of contaminants in that aquifer while the coal tar removal system is operational. In 2002, a second interim response action was also implemented. As approved by the WDNR, this interim response action involved the removal and capping of a seep area in a city park. Surface soils in the area of the seep were contaminated with tar residues. The interim action also included the diversion and ongoing treatment of groundwater that contributed to the formation of the seep.

On Sept. 5, 2002, the Ashland site was placed on the National Priorities List (NPL). The NPL is intended primarily to guide the EPA in determining which sites require further investigation. On Nov. 14, 2003, the EPA and NSP-Wisconsin signed an Administrative Order on Consent requiring NSP-Wisconsin to complete the remedial investigation and the feasibility study for the site. Resolution of Ashland remediation issues is not expected until 2006 or 2007.

NSP-Wisconsin continues to work with the WDNR to access state and federal funds to apply to the ultimate remediation cost of the entire site.

Plant Emissions — In October 2000, the EPA reversed a prior decision and found that the French Island plant, an NSP-Wisconsin facility that burns a fuel derived from solid waste, was subject to the federal large combustor regulations. On March 29, 2001, the

109

EPA issued a finding of violation to NSP-Wisconsin. On April 2, 2001, a conservation group also sent NSP-Wisconsin a notice of intent to sue under the citizen suit provisions of the Clean Air Act. On Oct. 20, 2003, the U.S. District Court entered a consent decree settling the EPA’s claims against us related to the French Island plant. Pursuant to the terms of that consent decree, NSP-Wisconsin paid a penalty of $500,000. Under the consent decree, the court retains jurisdiction over the plant for several years to monitor compliance with the emission limits and other requirements contained in the decree. Installation of the emission control equipment has been completed and source tests confirm that the plant is now in compliance with the state and federal dioxin standards. NSP-Wisconsin has reached an agreement with La Crosse County through which La Crosse County, the source of the plant’s refuse derived fuel, will pay for the emissions equipment through increased waste disposal fees.

PSCo

Leyden Gas Storage Facility – In February 2001, the CPUC approved PSCo’s plan to abandon the Leyden natural gas storage facility (Leyden) after 40 years of operation. In July 2001, the CPUC decided that the recovery of all Leyden costs would be addressed in a future rate proceeding when all costs were known. In 2003, PSCo began flooding the facility with water, as part of an overall plan to convert Leyden into a municipal water storage facility owned and operated by the city of Arvada, Colo. In August 2003, the Colorado Oil and Gas Conservation Commission approved the closure plan, the last formal regulatory approval necessary before conversion. Leyden is expected to close by Dec. 31, 2005, and the city of Arvada will take over the site. PSCo is obligated to monitor the site for two years after closure. As of Dec. 31, 2003, PSCo has incurred approximately $4.7 million of costs associated with engineering buffer studies, damage claims paid to landowners and other initial closure costs. PSCo has accrued an additional $4.7 million of costs expected to be incurred through 2006 to complete the decommissioning and closure of the facility. PSCo has deferred these costs as a regulatory asset and believes that these costs will be recovered through future rates. Any costs that are not recoverable from customers will be expensed.

Fort Collins Manufactured Gas Plant Site - Prior to 1926, Poudre Valley Gas Co., a predecessor of PSCo, operated a MGP in Fort Collins, Colo. not far from the Cache la Poudre River. In 1926, after acquiring the Poudre Valley Gas Co., PSCo shut down the gas site and, years later, sold most of the property. In the mid-1990s, contamination associated with MGP operations was discovered on the gas plant site, and PSCo paid for a portion of a partial cleanup. Recently, an oily substance similar to MGP by-products has been discovered in the Cache la Poudre River. The source of this substance has not yet been identified. PSCo is working with the EPA, the Colorado Department of Public Health and Environment, the current site owner and the City of Fort Collins (owner of a former landfill property between the River and the plant site) to address the substance found in the river as well as other environmental issues found on the property. The scope of the investigation has expanded as a result of negotiations with the EPA, and PSCo estimates that the cost of initial removal and investigation activities will be approximately $1.5 million, although the actual cost will vary depending on site conditions. PSCo lacks sufficient information at this time to estimate its ultimate liability, if any, for this site.

PSCo Notice of Violation — As discussed above, on Nov. 3, 1999, the United States Department of Justice filed suit against a number of electric utilities for alleged violations of the NSR requirements related to alleged modifications of electric generating stations located in the South and Midwest. Subsequently, the EPA also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities, including Xcel Energy, seeking to determine whether these utilities engaged in activities that may have been in violation of the NSR requirements. In 2001, Xcel Energy responded to the EPA’s initial information requests related to PSCo plants in Colorado.

On July 1, 2002, PSCo received a Notice of Violation (NOV) from the EPA alleging violations of the NSR requirements of the Clean Air Act at the Comanche and Pawnee Stations in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process. PSCo believes it acted in full compliance with the Clean Air Act and NSR process. It believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. PSCo also believes that the projects would be expressly authorized under the EPA’s NSR equipment replacement rulemaking promulgated in October 2003. On Dec. 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit stayed this rule while it considers challenges to it. PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position. As required by the Clean Air Act, the EPA met with Xcel Energy in September 2002 to discuss the NOV.

If the EPA is successful in any subsequent litigation regarding the issues set forth in the NOV or any matter arising as a result of its information requests, it could require PSCo to install additional emission control equipment at the facilities and pay civil penalties. Civil penalties are limited to not more than $25,000 to $27,500 per day for each violation, commencing from the date the violation began. The ultimate financial impact to PSCo is not determinable at this time.

110

Legal Contingencies

In the normal course of business, Xcel Energy’s utility subsidiaries are party to routine claims and litigation arising from prior and current operations. Xcel Energy’s utility subsidiaries are actively defending these matters and have recorded an estimate of the probable cost of settlement or other disposition.

NSP-Minnesota

SchlumbergerSema, Inc. v. Xcel Energy Inc. - Under a 1996 data services agreement, SchlumbergerSema, Inc. (SLB) provides automated meter reading, distribution automation, and other data services to NSP-Minnesota. In September 2002, NSP-Minnesota issued written notice that SLB committed events of default under the agreement, including SLB’s nonpayment of approximately $7.4 million for distribution automation assets. In November 2002, SLB demanded arbitration and asserted various claims against NSP-Minnesota totaling $24 million for alleged breach of an expansion contract and a meter purchasing contract. In the arbitration, NSP-Minnesota asserts counterclaims against SLB including those related to SLB’s failure to meet performance criteria, improper billing, failure to pay for use of NSP-Minnesota owned property and failure to pay $7.4 million for NSP-Minnesota distribution automation assets, for total claims of approximately $41 million. NSP-Minnesota also seeks a declaratory judgment from the arbitrators that would terminate SLB’s rights under the data services agreement. The arbitration panel is scheduled to hear dispositive motions in March 2004. In the event the matter is not disposed of on the motions, a hearing to arbitrate the dispute will likely occur in second quarter 2004.

NSP-Wisconsin

NSP-Wisconsin is the defendant in suits claiming electricity and/or stray voltage from NSP-Wisconsin’s system has harmed plaintiffs’ dairy herds and caused other damage and injuries. Total damages claimed in these proceedings are approximately $13.7 million. The ultimate outcome of these claims is not determinable at this time, and NSP-Wisconsin has recorded an estimate of costs necessary to settle or otherwise resolve these matters.

PSCo

Colorado Wildfires - In late October 2003, there were two wildfires in Colorado, one in Boulder County and the other in Douglas County. There was no loss of life, but there was property damage associated with these fires. Parties have asserted that trees falling into Xcel Energy distribution lines may have caused one or both fires. Litigation has been filed on behalf of 44 plaintiffs, including individuals and insurance companies, relating to the fire in Boulder County. The amount of damages is not yet known, however an adverse result in this matter could be material. The ultimate financial impact to PSCo is not determinable at this time.

Other Contingencies

SPS

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. A trial on the merits was held in October 2002, and on May 23, 2003, the PUCT issued an order denying LCEC’s petition for a cease and desist order against SPS. The basis of the decision was the determination that SPS was granted a certificate of convenience and necessity in 1976 to serve the disputed customers. LCEC has filed an appeal of the decision with the District Court in Travis County, Texas. The appeal is expected to include a substantial evidence review of the record evidence introduced at the PUCT proceeding. The Texas Attorney General has responded to the appeal on behalf of the PUCT and SPS, Texaco Exploration and Production Inc. and Apache Corporation have intervened in the proceeding in support of the PUCT’s decision. A hearing on the appeal is currently scheduled for April 9, 2004.

111

NMPRC Billing Practices Investigation – Beginning in April 2003, SPS estimated electricity usage for approximately 9,500 customers in two New Mexico cities. Estimated bills were sent to these customers for between two and five months. On Sept. 25, 2003, the NMPRC entered an order opening an investigation into SPS’ practices regarding estimated billing. The commission ordered SPS to show cause why it is not in violation of the commission rule that limits the use of estimated meter readings.

As part of the Sept. 25, 2003 order, the NMPRC also implemented temporary billing measures for customers whose bills were estimated. The temporary billing measures: (i) require SPS to apply the lowest fuel and purchased power cost adjustment factor that was applicable during the period when bills were being estimated, (ii) allow customers 6 months to pay bills in full without additional charges or disconnection, (iii) prohibited disconnection of service until Nov. 1, 2003 for any customer that received an estimated bill, (iv) require SPS to work with the NMPRC staff on a written explanation of the fuel calculation used under the order, and (v) order a report of the amount of fuel and purchased power costs foregone as a result of interim relief, which amount will not be allowed to be recovered from customers. Through January 2004, SPS refunded $326,000 to affected New Mexico retail customers. The deadline for intervention has passed and no parties other than SPS and the NMPRC staff are parties to the investigation proceeding. The hearings examiner has not set a procedural schedule.

14. Nuclear Obligations (NSP-Minnesota)

Accounting Change – SFAS No. 143 - Xcel Energy adopted Statement of Financial Accounting Standard (SFAS) No. 143 — “Accounting for Asset Retirement Obligations” effective Jan. 1, 2003. As required by SFAS No. 143, future plant decommissioning obligations were recorded as a liability at fair value as of Jan. 1, 2003, with a corresponding increase to the carrying values of the related long-lived assets. This liability will be increased over time by applying the interest method of accretion to the liability, and the capitalized costs will be depreciated over the useful life of the related long-lived assets.

The impact of the adoption of SFAS No. 143 for Xcel Energy’s utility subsidiaries is described later. The adoption had no income statement impact due to the deferral of the cumulative effect adjustments required under SFAS No. 143, through the establishment of a regulatory asset pursuant to SFAS No. 71.

Asset retirement obligations were recorded for the decommissioning of two NSP-Minnesota nuclear generating plants, the Monticello plant and the Prairie Island plant. A liability was also recorded for decommissioning of an NSP-Minnesota steam production plant, the Pathfinder plant. Monticello began operation in 1971 and is licensed to operate until 2010. Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively, and are licensed to operate until 2013 and 2014, respectively. Pathfinder operated as a steam production peaking facility from 1969 until its retirement.

A summary of the accounting for the initial adoption of SFAS No. 143 as of Jan. 1, 2003, is as follows:


	Increase (decrease) in:
	Plant			Regulatory			Long-Term
(Thousands of dollars)	Assets			Assets			Liabilities
Reflect retirement obligation when liability incurred	$	130,659		$	—		$	130,659
Record accretion of liability to adoption date		—			731,709			731,709
Record depreciation of plant to adoption date		(110,573	)		110,573			—
Recharacterize previously recorded decommissioning accruals		—			(662,411	)		(662,411	)

Net impact of SFAS No. 143 on balance sheet	$	20,086		$	179,871		$	199,957

A reconciliation of the beginning and ending aggregate carrying amount of NSP-Minnesota’s asset retirement obligations recorded under SFAS No. 143 are shown in the table below for the twelve months ended Dec. 31, 2003:


	Beginning								Revisions		Ending
	Balance		Liabilities		Liabilities				To Prior		Balance
(Thousands of dollars)	Jan. 1, 2003		Incurred		Settled		Accretion		Estimates		Dec. 31, 2003
Steam plant retirement	$	2,725	$	—	$	—	$	135	$	—	$	2,860
Nuclear plant decommissioning		859,643		—		—		58,341		103,685		1,021,669

Total liability	$	862,368	$	—	$	—	$	58,476	$	103,685	$	1,024,529

The adoption of SFAS No. 143 resulted in the recording of a capitalized plant asset of $131 million for the discounted cost of asset retirement as of the date the liability was incurred. Accumulated depreciation on this additional capitalized cost through the date of adoption of SFAS No. 143 was $111 million. A regulatory asset of $842 million was recognized for the accumulated SFAS No. 143 costs for accretion of the initial liability and depreciation of the additional capitalized cost through adoption date. This regulatory asset was partially offset by $662 million for the reversal of the decommissioning costs previously accrued for these plants prior to the implementation of SFAS No. 143. The net regulatory asset of $180 million at Jan. 1, 2003, reflects the excess of costs that would have been recorded in expense under SFAS No. 143 over the amount of costs recorded consistent with ratemaking cost recovery for NSP-Minnesota. This regulatory asset is expected to reverse over time since the costs to be accrued under SFAS No. 143 are expected to be the same as the costs to be recovered through current NSP-Minnesota ratemaking. Consequently, no cumulative effect adjustment to earnings or shareholder’s equity has been recorded for the adoption of SFAS No. 143 in 2003 as all such effects have been deferred as a regulatory asset.

In August 2003, prior estimates for the nuclear plant decommissioning obligations were revised to incorporate the assumptions made in NSP-Minnesota’s updated 2002 nuclear decommissioning filing with the Minnesota Public Utilities Commission (MPUC). The revised estimates resulted in an increase of $104 million to both the regulatory asset and the long-term liability, as discussed previously. The revised estimates reflected changes in cost estimates due to changes in the escalation factor, changes in the estimated start date for decommissioning and changes in assumptions for storage of spent nuclear fuel. The changes in assumptions for the estimated start date for decommissioning and changes in the assumptions for storage of spent nuclear fuel are a result of recent Minnesota legislation that authorized additional spent nuclear fuel storage.

The pro forma liability to reflect amounts as if SFAS No. 143 had been applied as of Dec. 31, 2002, was $862 million, the same as the Jan. 1, 2003, amounts discussed previously. The pro forma liability to reflect adoption of SFAS No. 143 as of Jan. 1, 2002, the beginning of the earliest period presented, was $810 million.

Pro forma net income has not been presented for the years ended Dec. 31, 2002, because the pro forma application of SFAS No. 143 to prior periods would not have changed net income of NSP-Minnesota due to the regulatory deferral of any differences of past cost recognition and SFAS No. 143 methodology, as discussed previously.

The fair value of NSP-Minnesota assets legally restricted for purposes of settling the nuclear asset retirement obligations is $900 million as of Dec. 31, 2003, including external nuclear decommissioning investment funds and internally funded amounts.

Removal Costs - The adoption of SFAS No. 143 in 2003 also affects Xcel Energy’s utility subsidiaries’ accrued plant removal costs for other generation, transmission and distribution facilities for its utility subsidiaries. Although SFAS No. 143 does not recognize the future accrual of non-legal removal obligations as a liability, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long periods over which the amounts were accrued and the changing of rates through time, the utility subsidiaries have estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates.

Accordingly, the recorded amounts of estimated future removal costs are considered Regulatory Liabilities under SFAS No. 71. Removal costs by entity are as follows at Dec. 31:


(Millions of dollars)	2003		2002
NSP-Minnesota	$	324	$	304
NSP-Wisconsin		75		70
PSCo		351		329
SPS		102		97

Fuel Disposal — NSP-Minnesota is responsible for temporarily storing used or spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from NSP-Minnesota’s nuclear plants as well as from other U.S. nuclear plants. NSP-Minnesota has funded its portion of the DOE’s permanent disposal program since 1981. The fuel disposal fees are based on a charge of 0.1 cent per kilowatt-hour sold to customers from nuclear generation. Fuel expense includes DOE fuel disposal assessments of approximately $13 million in 2003, $13 million in 2002 and $11 million in 2001. In total, NSP-Minnesota had paid approximately $321 million to the DOE through Dec. 31, 2003. However, it is not determinable whether the amount and method of the DOE’s assessments to all utilities will be sufficient to fully fund the DOE’s permanent storage or disposal facility.

The Nuclear Waste Policy Act required the DOE to begin accepting spent nuclear fuel no later than Jan. 31, 1998. In 1996, the DOE notified commercial spent-fuel owners of an anticipated delay in accepting spent nuclear fuel by the required date and conceded that a permanent storage or disposal facility will not be available until at least 2010. NSP-Minnesota and other utilities have commenced lawsuits against the DOE to recover damages caused by the DOE’s failure to meet its statutory and contractual obligations.

NSP-Minnesota has its own temporary, on-site storage facilities for spent fuel at its Monticello and Prairie Island nuclear plants, which consists of storage pools and a dry cask facility. With the dry cask storage facility licensed by the NRC, which was approved in 1994 and again in 2003, management believes it has adequate storage capacity to continue operation of its Prairie Island nuclear plant until at least the end of its license terms in 2013 and 2014. The Monticello nuclear plant has storage capacity in the pool to continue operations until 2010. Storage availability to permit operation beyond these dates is not known at this time. All of the alternatives for spent-fuel storage are being investigated until a DOE facility is available, including pursuing the establishment of a private facility for interim storage of spent nuclear fuel as part of a consortium of electric utilities.

Nuclear fuel expense includes payments to the DOE for the decommissioning and decontamination of the DOE’s uranium enrichment facilities. In 1993, NSP-Minnesota recorded the DOE’s initial assessment of $46 million, which is payable in annual installments from 1993 to 2008. NSP-Minnesota is amortizing each installment to expense on a monthly basis. The most recent installment paid in 2003 was $4.5 million; future installments are subject to inflation adjustments under DOE rules. NSP-Minnesota is obtaining rate recovery of these DOE assessments through the cost-of-energy adjustment clause as the assessments are amortized. Accordingly, the unamortized assessment of $16.8 million at Dec. 31, 2003, is deferred as a regulatory asset.

Plant Decommissioning — Decommissioning of NSP-Minnesota’s nuclear facilities is planned for the years 2010 through 2048, using the prompt dismantlement method. Upon implementation of SFAS No. 143, the decommissioning costs in Accumulated Depreciation and ongoing recoveries are reclassified to a regulatory liability account. The total decommissioning cost obligation is recorded as an asset retirement obligation in accordance with SFAS No. 143. See Accounting Change – SFAS No. 143 for additional information.

Monticello began operation in 1971 and is licensed to operate until 2010. Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively, and are licensed to operate until 2013 and 2014, respectively. In 2003, the Minnesota Legislature changed a law that had limited expansion of on-site storage. NSP-Minnesota will make a decision on whether to pursue license renewal for the

112

Monticello and Prairie Island plants. Applications for license renewal must be submitted to the NRC at least five years prior to license expiration. Preliminary scoping efforts for license renewal of the Monticello plant have begun, including data collection and review. The Prairie Island license renewal process has not yet begun. NSP-Minnesota’s decision whether to apply for license renewal approval could be contingent on incremental plant maintenance or capital expenditures, recovery of which would be expected from customers through the respective rate-recovery mechanisms. Management cannot predict the specific impact of such future requirements, if any, on its results of operations.

Consistent with cost recovery in utility customer rates, NSP-Minnesota records annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding. Cost studies quantify decommissioning costs in current dollars. Funding presumes that current costs will escalate in the future at a rate of 4.19 percent per year. The total estimated decommissioning costs that will ultimately be paid, net of income earned by external trust funds, is currently being accrued using an annuity approach over the approved plant-recovery period. This annuity approach uses an assumed rate of return on funding, which is currently 5.5 percent, net of tax, for external funding and approximately 8 percent, net of tax, for internal funding. Unrealized gains on nuclear decommissioning investments are deferred as Regulatory Liabilities based on the assumed offsetting against decommissioning costs in current ratemaking treatment.

The MPUC last approved NSP-Minnesota’s nuclear decommissioning study request in December 2003, using 2002 cost data. An original filing was submitted to the MPUC in October 2002 and updated in August 2003; final approval was received in December 2003. The most recent cost estimate represents an annual increase in external fund accruals, along with the extension of Prairie Island cost recovery to the end of license life in 2014. The MPUC also approved the Department of Commerce recommendation to accelerate the internal fund transfer to the external funds effective July 1, 2003, ending on Dec. 31, 2005. These approvals increased the fund cash contribution by approximately $29 million in 2003, but may not have a statement of operations impact. Expecting to operate Prairie Island through the end of each unit’s licensed life, the approved capital recovery will allow for the plant to be fully depreciated, including the accrual and recovery of decommissioning costs, in 2014. NSP-Minnesota believes future decommissioning cost accruals will continue to be recovered in customer rates.

The total obligation for decommissioning currently is expected to be funded 100 percent by external funds, as approved by the MPUC. Contributions to the external fund started in 1990 and are expected to continue until plant decommissioning begins. The assets held in trusts as of Dec. 31, 2003, primarily consisted of investments in fixed income securities, such as tax-exempt municipal bonds and U.S. government securities that mature in one to 20 years, and common stock of public companies. NSP-Minnesota plans to reinvest matured securities until decommissioning begins.

At Dec. 31, 2003, NSP-Minnesota had recorded and recovered in rates cumulative decommissioning accruals of $722 million. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation at Dec. 31, 2003:


	2003
	(Thousands
	of dollars)
Estimated decommissioning cost obligation from most recently approved study (2002 dollars)	$	1,716,618
Effect of escalating costs to 2003 dollars (at 4.19 percent per year)		71,926

Estimated decommissioning cost obligation in current dollars		1,788,544
Effect of escalating costs to payment date (at 4.19 percent per year)		2,004,821

Estimated future decommissioning costs (undiscounted)		3,793,365
Effect of discounting obligation (using risk-free interest rate)		(2,274,469	)

Discounted decommissioning cost obligation		1,518,896
Assets held in external decommissioning trust		779,382

Discounted decommissioning obligation in excess of assets currently held in external trust	$	739,514

113

Any portion of the business that is not rate regulated cannot use SFAS No. 71 accounting. Efforts to restructure and deregulate the utility industry may further reduce or end our ability to apply SFAS No. 71 in the future, and write-offs and material changes to Xcel Energy’s utility subsidiaries balance sheet, income and cash flows may result.

The components of unamortized regulatory assets and liabilities on the balance sheets of Xcel Energy’s utility subsidiaries are:

(a)		Earns a return on investment in the ratemaking process. These amounts are amortized consistent with recovery in rates.

(b)		Excludes current portion expected to be returned to customers within 12 months of $3.1 million for 2003, and expected to be recovered from customers within 12 months of $12.1 million for 2002.

(c)		These costs do not relate to NSP-Minnesota’s nuclear plants. They relate to assessments to pay for the decommissioning of a federal uranium enrichment facility.

(g)		Regulatory assets and liabilities created by the implementation of C20. See Note 12.

(d)

Earns a return on investment in the ratemaking process. These amounts are amortized consistent with recovery in rates.

(e)		Earns a return on investment in the ratemaking process. These amounts are amortized consistent with recovery in rates.

(f)		Excludes current portion expected to be recovered within the next 12 months of $55.8 and $54.2 million for 2003 and 2002, respectively.

(g)		Regulatory assets and liabilities created by the implementation of C20. See Note 12.

(h)		These costs relate to unamortized costs for PSCo’s Fort St. Vrain nuclear plant decommissioning.

(g)		Regulatory assets and liabilities created by the implementation of C20. See Note 12.

(h)		Earns a return on investment in the ratemaking process. These amounts are amortized consistent with recovery in rates.

16. Segment and Related Information (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Xcel Energy’s Utility Subsidiaries each have two reportable segments, Regulated Electric Utility and Regulated Natural Gas Utility, with the exception of SPS, which only has a Regulated Electric Utility reportable segment.

	•		Xcel Energy’s Regulated Electric Utility generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas, New Mexico, Wyoming, Kansas and Oklahoma. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Electric Regulated Utility also includes NSP-Minnesota’s and PSCo’s electric trading operations.

	•		Xcel Energy’s Regulated Natural Gas Utility transmits, transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado.

Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the All Other category. Those primarily include steam revenue (PSCo), appliance repair services (NSP-Minnesota and PSCo), nonutility real estate activities (NSP-Minnesota) and revenues associated with processing solid waste into refuse-derived fuel (NSP-Minnesota).

To report net income for regulated electric and regulated natural gas utility segments, Xcel Energy must assign or allocate all costs and certain other income. In general, costs are:

	•		directly assigned wherever applicable;

	•		allocated based on cost causation allocators wherever applicable; or

	•		allocated based on a general allocator for all other costs not assigned by the above two methods.

The accounting policies of the segments are the same as those described in Note 1 to the Consolidated Financial Statements. Xcel Energy evaluates performance by each legal entity based on profit or loss.

In 2003, the process to allocate common costs of the Regulated Electric and Regulated Natural Gas Utility segments was revised. Segment results for 2002 and 2001 have been restated to reflect the revised cost allocation process.

SPS has only one reportable segment. SPS operates in the regulated electric utility industry providing wholesale and retail electric service in the states of Texas, New Mexico, Kansas and Oklahoma. Revenues from external customers were $1,201.3 million, $1,025.2 million and $1,385.5 million for the years ended Dec. 31, 2003, 2002 and 2001, respectively.

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy, including its utility subsidiaries. The services are provided and billed to each subsidiary in accordance with Service Agreements approved by the SEC and executed by each subsidiary. Costs are charged directly to the subsidiary which uses the service whenever possible, and are allocated using an SEC approved method if they cannot be directly assigned.

In 2004 NSP-Minnesota, NSP-Wisconsin, PSCo and SPS expect to create a “utility money pool” as described in Note 3 to the Consolidated Financial Statements. Under the money pool arrangement, the cash positions of Xcel Energy and its utility subsidiaries can be matched, potentially resulting in lower borrowing costs and related financing expenses.

Viking Gas Transmission Co. (Viking), a subsidiary of Xcel Energy until it was sold Jan. 17, 2003, transports gas purchased by NSP-Minnesota from various suppliers. NSP-Minnesota paid Viking $4.6 million in 2002 and $5.8 million in 2001 for gas transportation services NSP Wisconsin purchased $1.6 million of transportation service from Viking during 2002.

NSP-Minnesota purchased gas from e prime, another subsidiary of Xcel Energy, paying $2.7 million in 2002 and $3.5 million in 2001. In addition NSP-Minnesota sold transportation services to e prime for $0.1 million in 2002 and $0.4 million in 2001 for gas delivered into the Minnesota operating area.

Utility Engineering Corp., an additional Xcel Energy subsidiary, provided construction services to NSP-Minnesota, for which it was paid $5.9 million in 2003, $7.0 million in 2002 and $6.7 million in 2001.

The electric production and transmission costs of the entire NSP system are shared by NSP-Minnesota and NSP-Wisconsin. A FERC approved agreement (called the “Interchange Agreement”) between the two companies provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs. Billings under the Interchange Agreement, which are included in the Consolidated Statements of Income, are as follows:

(a)

Other operations expense includes $266,560, $272,825, and $289,339 paid to Xcel Energy Services Inc. in 2003, 2002 and 2001.

(a)

Other operations expense includes $43,570, $36,695, and $28,816 paid to Xcel Energy Services Inc. in 2003, 2002 and 2001.

NSP-Wisconsin obtains short-term borrowings from NSP-Minnesota at NSP-Minnesota’s average daily interest rate, including the cost of NSP-Minnesota’s compensating balance requirements. Corresponding interest charges on NSP-Wisconsin’s statement of income and other income on NSP-Minnesota’s statement of income include $0.1 million, $0.2 million, and $0.4 million for 2003, 2002, and 2001.

NSP-Minnesota’s receivables from affiliates include amounts receivable from NSP-Wisconsin for the Interchange Agreement and short-term borrowings. NSP-Minnesota’s payable to affiliates primarily represents amounts payable to Xcel Energy Services Inc. for NSP-Minnesota’s allocation of support services from Xcel Energy Services Inc.

NSP-Wisconsin’s receivable from affiliates primarily represents amounts receivable from NSP-Minnesota for the Interchange Agreement. NSP-Wisconsin’s notes payable to affiliates represents amounts payable to NSP-Minnesota.

For 37 years Cheyenne Light, Fuel and Power (Cheyenne), an Xcel Energy subsidiary, had purchased all of its electricity from PacifiCorp, but the contract expired in early 2001. Cheyenne was unable to execute a new agreement with PacifiCorp and consequently PSCo began supplying Cheyenne’s power requirements in February 2001.

In the past, SPS purchased gas from e prime to fuel electric generation plants. SPS has not purchased natural gas from e prime since December 2002.

PSCo sells firm and interruptible transportation services to e prime for gas delivered into the Denver/ Pueblo operating area. PSCo also purchases gas from e prime for its gas utility system supply.

PSCo and SPS receive construction services from Utility Engineering. In addition, PSCo and SPS pay interest expense on any short-term borrowings from Xcel Energy.

SPS purchases electricity from Borger Energy Associates, which is partially owned by one of Xcel Energy’s subsidiaries.

The table below contains significant affiliate transactions among the companies and related parties for the years ended Dec. 31:

(a)

Operating expense includes $259,788, $208,402, and $232,902 paid to Xcel Energy Services Inc. in 2003, 2002 and 2001.

(a)

Operating expense includes $86,812, $68,045, and $72,259 paid to Xcel Energy Services Inc. in 2003, 2002 and 2001.

18. Summarized Quarterly Financial Data (Unaudited) (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

(a) 2002 results include special charges as discussed in Note 2 to the Consolidated Financial Statements. First quarter results were decreased by $4 million for a pretax special charge related to final employee restaffing costs.

(a) 2002 results include special charges as discussed in Note 2 to the Consolidated Financial Statements. First quarter results were decreased by $5 million for a pretax special charge related to restructuring costs.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

During 2002 and 2003, and through the date of this report, there were no disagreements with the independent public accountants for NSP-Minnesota, NSP-Wisconsin, PSCo and SPS on accounting principles or practices, financial disclosures or audit scope or procedures.

Xcel Energy’s utility subsidiaries each maintain a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of the Xcel Energy’s utility subsidiaries’ management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that the Company’s disclosure controls and procedures are effective.

No change in Xcel Energy’s utility subsidiaries’ internal control over financial reporting has occurred during the Company’s most recent fiscal year that has materially affected, or is reasonably likely to affect the Xcel Energy’s utility subsidiaries’ internal control over financial reporting.

Items 10, 11, 12 and 13 of Part III of Form 10-K have been omitted from this report for Xcel Energy’s utility subsidiaries in accordance with conditions set forth in general instructions I (1) (a) and (b) of Form 10-K for wholly-owned subsidiaries.

Item 10. Directors and Executive Officers of the Registrant (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Item 11. Executive Compensation (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Item 12. Security Ownership of Certain Beneficial Owners and Management (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Item 13. Certain Relationships and Related Transactions (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)

Information concerning fees paid to the principal accountant for each of the last two years is contained in the Xcel Energy Proxy Statement for its 2004 Annual Meeting of Shareholders, which is incorporated by reference.

Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)


10.27*	Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Xcel Energy Form U5B (file no. 001-03034) dated Nov. 16, 2000).

NSP-Minnesota

(a) 1. Financial Statements and Schedules


				Page
		Reports of Independent Auditors for the years ended Dec. 31, 2003, 2002 and 2001		49
		Statements of Income for the three years ended Dec. 31, 2003		56
		Statements of Cash Flows for the three years ended Dec. 31, 2003		57
		Balance Sheets, Dec. 31, 2003 and 2002		58
		Notes to Financial Statements		80
		Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2003, 2002 and 2001		135


2.		Exhibits

*		Indicates incorporation by reference.

2.01	*	Agreement and Plan of Merger, dated as of March 24, 1999, by and between Northern States Power Co. (a Minnesota corporation) and New Century Energies, Inc. (Exhibit 2.1 to New Century Energies, Inc. Form 8-K (file no. 001-12907) dated March 24, 1999).

3.01	*	Articles of Incorporation and Amendments of Northern Power Corp. (renamed Northern States Power Co. (a Minnesota corporation) on Aug. 21, 2000)(Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).

3.02	*	By-Laws of Northern States Power Co. (a Minnesota corporation) (Exhibit 3.02 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).

4.01	*	Trust Indenture, dated Feb. 1, 1937, from Northern States Power Co. (a Minnesota corporation) to Harris Trust and Savings Bank, as Trustee. (Exhibit B-7 to File No. 2-5290).

4.02	*	Supplemental and Restated Trust Indenture, dated May 1, 1988, from Northern States Power Co. (a Minnesota corporation) to Harris Trust and Savings Bank, as Trustee. (Exhibit 4.02 to Form 10-K (file no. 001-03034) for the year 1988).

		Supplemental Indentures between NSP-Minnesota and said Trustee, supplemental to Exhibit 4.02, dated as follows:

4.03	*	June 1, 1942 (Exhibit B-8 to File No. 2-97667).

4.04	*	Feb. 1, 1944 (Exhibit B-9 to File No. 2-5290).

4.05	*	Oct. 1, 1945 (Exhibit 7.09 to File No. 2-5924).

4.06	*	July 1, 1948 (Exhibit 7.05 to File No. 2-7549).

4.07	*	Aug. 1, 1949 (Exhibit 7.06 to File No. 2-8047).

4.08	*	June 1, 1952 (Exhibit 4.08 to File No. 2-9631).

4.09	*	Oct. 1, 1954 (Exhibit 4.10 to File No. 2-12216).

4.10	*	Sept. 1, 1956 (Exhibit 2.09 to File No. 2-13463).

4.11	*	Aug. 1, 1957 (Exhibit 2.10 to File No. 2-14156).

4.12	*	July 1, 1958 (Exhibit 4.12 to File No. 2-15220).

4.13	*	Dec. 1, 1960 (Exhibit 2.12 to File No. 2-18355).

4.14	*	Aug. 1, 1961 (Exhibit 2.13 to File No. 2-20282).

4.15	*	June 1, 1962 (Exhibit 2.14 to File No. 2-21601).

4.16	*	Sept. 1, 1963 (Exhibit 4.16 to File No. 2-22476).

4.17	*	Aug. 1, 1966 (Exhibit 2.16 to File No. 2-26338).

4.18	*	June 1, 1967 (Exhibit 2.17 to File No. 2-27117).

4.19	*	Oct. 1, 1967 (Exhibit 2.01R to File No. 2-28447).

4.20	*	May 1, 1968 (Exhibit 2.01S to File No. 2-34250).

4.21	*	Oct. 1, 1969 (Exhibit 2.01T to File No. 2-36693).

4.22	*	Feb. 1, 1971 (Exhibit 2.01U to File No. 2-39144).

4.23	*	May 1, 1971 (Exhibit 2.01V to File No. 2-39815).

4.24	*	Feb. 1, 1972 (Exhibit 2.01W to File No. 2-42598).

4.25	*	Jan. 1, 1973 (Exhibit 2.01X to File No. 2-46434).

4.26	*	Jan. 1, 1974 (Exhibit 2.01Y to File No. 2-53235).

4.27	*	Sept. 1, 1974 (Exhibit 2.01Z to File No. 2-53235).

4.28	*	April 1, 1975 (Exhibit 4.01AA to File No. 2-71259).

127


4.29	*	May 1, 1975 (Exhibit 4.01BB to File No. 2-71259).

4.30	*	March 1, 1976 (Exhibit 4.01CC to File No. 2-71259).

4.31	*	June 1, 1981 (Exhibit 4.01DD to File No. 2-71259).

4.32	*	Dec. 1, 1981 (Exhibit 4.01EE to File No. 2-83364).

4.33	*	May 1, 1983 (Exhibit 4.01FF to File No. 2-97667).

4.34	*	Dec. 1, 1983 (Exhibit 4.01GG to File No. 2-97667).

4.35	*	Sept. 1, 1984 (Exhibit 4.01HH to File No. 2-97667).

4.36	*	Dec. 1, 1984 (Exhibit 4.01II to File No. 2-97667).

4.37	*	May 1, 1985 (Exhibit 4.36 to Form 10-K for the year 1985, File No. 001-03034).

4.38	*	Sept. 1, 1985 (Exhibit 4.37 to Form 10-K for the year 1985, File No. 001-03034).

4.39	*	July 1, 1989 (Exhibit 4.01 to Form 8-K dated July 7, 1989, File No. 001-03034).

4.40	*	June 1, 1990 (Exhibit 4.01 to Form 8-K dated June 1, 1990, File No. 001-03034

4.41	*	Oct. 1, 1992 (Exhibit 4.01 to Form 8-K dated Oct. 13, 1992, File No. 001-03034).

4.42	*	April 1, 1993 (Exhibit 4.01 to Form 8-K dated March 30, 1993, File No. 001-03034).

4.43	*	Dec. 1, 1993 (Exhibit 4.01 to Form 8-K dated Dec. 7, 1993, File No. 001-03034).

4.44	*	Feb. 1, 1994 (Exhibit 4.01 to Form 8-K dated Feb. 10, 1994, File No. 001-03034).

4.45	*	Oct. 1, 1994 (Exhibit 4.01 to Form 8-K dated Oct. 5, 1994, File No. 001-03034).

4.46	*	June 1, 1995 (Exhibit 4.01 to Form 8-K dated June 28, 1995, File No. 001-03034).

4.47	*	April 1, 1997 (Exhibit 4.47 to Form 10-K for the year 1997, File No. 001-03034).

4.48	*	March 1, 1998 (Exhibit 4.01 to Form 8-K dated March 11, 1998, File No. 001-03034).

4.49	*	May 1, 1999 (Exhibit 4.49 to Form 10 of NSP-Minnesota, File No. 000-31709).

4.50	*	June 1, 2000 (Exhibit 4.50 to Form 10 of NSP-Minnesota, File No. 000-31709).

4.51	*	Aug. 1, 2000 (Assignment and Assumption of Trust Indenture) (Exhibit 4.51 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).

4.52	*	Trust Indenture, dated July 1, 1999, between Northern States Power Co. (a Minnesota corporation) and Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated July 21, 1999).

4.53	*	Supplemental Trust Indenture dated July 15, 1999, between Northern States Power Co. (a Minnesota corporation) and Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.02 to Form 8-K (file no. 001-03034) dated July 21, 1999).

4.54	*	Supplemental Trust Indenture dated Aug. 18, 2000, among Xcel Energy, Northern States Power Co. (a Minnesota corporation) and Wells Fargo Bank Minnesota, National Association, as Trustee. (Exhibit 4.63 to Form 10 (file no. 000-31709) dated Oct. 5, 2000).

4.55	*	Supplemental Trust Indenture dated June 1, 2002, between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Co., as successor trustee. (Exhibit 4.05 to Form 10-Q (file no. 000-31709) dated Sept. 30, 2002).

4.56	*	Supplemental Trust Indenture dated July 1, 2002, between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Co., as successor trustee. (Exhibit 4.06 to Form 10-Q (file no. 000-31709) dated Sept. 30, 2002).

4.57	*	Supplemental Trust Indenture dated July 1, 2002, between Northern States Power Co. (a Minnesota corporation) and Wells Fargo Bank Minnesota, National Association, as Trustee. (Exhibit 4.01 to Form 8-K (file no. 000-31709) dated July 8, 2002).

4.58	*	Supplemental Trust Indenture dated Aug. 1, 2002, between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Co., as Trustee. (Exhibit 4.01 to Form 8-K (file no 000-31709) dated Aug. 22, 2002).

4.59	*	Credit Agreement between Northern States Power Co. (a Minnesota corporation), Bank One National Association and Wells Fargo Bank Minnesota National Association and other financial institutions party thereto dated May 16, 2003 (Exhibit 4.01 to Form 10-Q (file no. 001-31387) dated Aug. 14, 2003).

4.60	*	Supplemental Trust Indenture dated Aug. 1, 2003 between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1, 1988 (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 6, 2003).

4.61	*	Supplemental Trust Indenture dated May 1, 2003 between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1, 1988 (Exhibit 4.73 to Xcel Energy Form 10-K (file no. 001-03034) dated March 15, 2004).

10.01	*	Facilities Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kilovolt (kv) line. (Exhibit 5.06I to File No. 2-54310).

10.02	*	Transactions Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kv line. (Exhibit 5.06J to File No. 2-54310).

10.03	*	Coordinating Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kv line. (Exhibit 5.06K to File No. 2-54310).

128


10.04	*	Ownership and Operating Agreement, dated March 11, 1982, between Northern States Power Co. (a Minnesota corporation), Southern Minnesota Municipal Power Agency and United Minnesota Municipal Power Agency concerning Sherburne County Generating Unit No. 3. (Exhibit 10.01 to Form 10-Q (file no. 001-03034) for the quarter ended Sept. 30, 1994).

10.06	*	Power Agreement, dated June 14, 1984, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board, extending the agreement scheduled to terminate on April 30, 1993, to April 30, 2005.(Exhibit 10.03 to Form 10-Q (file no. 001-03034) for the quarter ended Sept. 30, 1994).

10.07	*	Power Agreement, dated August 1988, between Northern States Power Co. (a Minnesota corporation) and Minnkota Power Co. (Exhibit 10.08 to Form 10-K (file no. 001-03034) for the year 1988).

10.08	*	Assignment and Assumption Agreement, dated Aug. 18, 2000 between Northern States Power Co. (a Minnesota corporation) and Xcel Energy Inc. (Exhibit 10.08 to Form 10 (file no. 000-31709) dated Oct. 5, 2000)

10.09	*	Amended agreement for the sale of thermal energy dated Jan. 1, 1983 between NRG Energy (formerly known as Norenco Corp.) and Northern States Power Co. (a Minnesota corporation) and Norenco Corp. (Incorporated by reference to NRG’s Registration on Form S-1, file no. 333-35096).

10.10	*	Restated Interchange Agreement dated Jan. 16, 2001 between Northern States Power Co. (a Wisconsin corporation) and Northern States Power Co. (a Minnesota corporation) (Exhibit 10.01 to NSP-Wisconsin Form S-4 (file no. 333-112033) dated Jan. 21, 2004).

10.11	*	Operations and maintenance agreement dated Nov. 1, 1996 between NRG Energy and Northern States Power Co. (a Minnesota corporation). (Incorporated by reference to NRG’s Registration on Form S-1, File No. 333-35096).

10.12	*	Agreement for the sale of thermal energy and wood byproduct dated Dec. 1, 1986 between Northern States Power Co. (a Minnesota corporation) and Norenco Corp. (Incorporated by reference to NRG’s Registration on Form S-1, File No. 333-35096).

10.13	*	500 megawatt System Participation Power Sale Agreement dated July 30, 2002 between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board (Exhibit 99.01 to NSP-Minnesota Form 8-K (file no. 001-31387) dated March 25, 2003).

12.01	(a)	Computation of Ratio of Consolidated Earnings to Consolidated Fixed Charges.

16.01	*	Letter regarding change in accountant (Exhibit 16.01 to PSCo Form 8-K (file no. 001-03280) dated May 28, 2002)

23.01		Independent Auditors’ Consent.

31.01		Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.02		Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.01		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.01		Statement pursuant to Private Securities Litigation Reform Act of 1995.

99.02	*	Exhibit regarding the use of Arthur Andersen Audit Firm (Exhibit 99.02 to Form 10-K (file no. 001-03034) dated April 1, 2002).

(b) Reports on Form 8-K — The following reports on Form 8-K were filed either during the three months ended Dec. 31, 2003, or between Dec. 31, 2003 and the date of this report.

None

NSP-Wisconsin


(a)	1.			Financial Statements and Schedules


				Page
		Reports of Independent Auditors for the years ended Dec. 31, 2003, 2002 and 2001		51
		Statements of Income for the three years ended Dec. 31, 2003		62
		Statements of Cash Flows for the three years ended Dec. 31, 2003		63
		Balance Sheets, Dec. 31, 2003 and 2002		64
		Notes to Financial Statements		80
		Schedule II —Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2003, 2002 and 2001		135


2.		Exhibits

*		Indicates incorporation by reference.

3.01	*	Amended and restated articles of incorporation of NSP-Wisconsin (Exhibit 3.01 to Form S-4 (file no. 333-112033) Jan. 21, 2004).

129


3.02	*	By-Laws of NSP-Wisconsin as amended Dec. 6, 2001 (Exhibit 3.02 to Form Form S-4 (file no. 333-112033) Jan. 21, 2004).

4.01	*	Trust Indenture, dated April 1, 1947, From NSP-Wisconsin to Firstar Trust Company (formerly First Wisconsin Trust Company). (Exhibit 7.01 to Registration Statement 2-6982)

4.02	*	Supplemental Trust Indenture, dated March 1, 1949. (Exhibit 7.02 to Registration Statement 2-7825)

4.03	*	Supplemental Trust Indenture, dated June 1, 1957. (Exhibit 2.13 to Registration Statement 2-13463)

4.04	*	Supplemental Trust Indenture, dated Aug. 1, 1964. (Exhibit 4.20 to Registration Statement 2-23726)

4.05	*	Supplemental Trust Indenture, dated Dec. 1, 1969. (Exhibit 2.03E to Registration Statement 2-36693).

4.06	*	Supplemental Trust Indenture, dated Sept. 1, 1973. (Exhibit 2.03F to Registration Statement 2-49757).

4.07	*	Supplemental Trust Indenture, dated Feb. 1, 1982. (Exhibit 4.01G to Registration Statement 2-76146).

4.08	*	Supplemental Trust Indenture, dated March 1, 1982. (Exhibit 4.08 to Form 10-K (file no. 001-03140) for the year 1982).

4.09	*	Supplemental Trust Indenture, dated June 1, 1986. (Exhibit 4.09 to Form 10-K (file no. 001-03140) for the year 1986).

4.10	*	Supplemental Trust Indenture, dated March 1, 1988. (Exhibit 4.10 to Form 10-K (file no. 001-03140) for the year 1988).

4.11	*	Supplemental and Restated Trust Indenture, dated March 1, 1991. (Exhibit 4.01K to Registration Statement 33-39831).

4.12	*	Supplemental Trust Indenture, dated April 1, 1991. (Exhibit 4.01 to Form 10-Q (file no. 001-03140) for the quarter ended March 31, 1991).

4.13	*	Supplemental Trust Indenture, dated March 1, 1993. (Exhibit to Form 8-K (file no. 001-03140) dated March 3, 1993).

4.14	*	Supplemental Trust Indenture, dated Oct. 1, 1993. (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Sept. 21, 1993).

4.15	*	Supplemental Trust Indenture, dated Dec. 1, 1996. (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Dec. 12, 1996).

4.16	*	Supplemental Trust Indenture dated Sept. 1, 2003 between Northern States Power Co. (a Wisconsin corporation) and US Bank N.A., supplementing indentures dated April 1, 1947 and March 1, 1991 (Exhibit 4.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated Nov. 13, 2003).

4.17	*	Trust Indenture dated Sept. 1, 2000, between Northern States Power Co. (a Wisconsin corporation) and Firstar Bank, N.A. as Trustee. (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Sept. 25, 2000).

4.18	*	Supplemental Trust Indenture dated Sept. 15, 2000, between Northern States Power Co. (a Wisconsin corporation) and Firstar Bank, N.A. as Trustee, creating $80 million principal amount of 7.64 percent Senior Notes, Series due 2008. (Exhibit 4.02 to Form 8-K (file no 001-03140) dated Sept. 25, 2000).

4.19	*	Exchange and Registration Rights Agreement dated Oct. 2, 2003 among Northern States Power Co. (a Wisconsin corporation) and Goldman, Sachs, & Co. and BNY Capital Markets, Inc. (Exhibit 4.92 to Xcel Energy Form 10-K (file no. 001-03034) dated March 15, 2004).

10.01	*	Restated Interchange Agreement dated Jan. 16, 2001 between Northern States Power Co. (a Wisconsin corporation) and Northern States Power Co. (a Minnesota corporation) (Exhibit 10.01 to Form S-4 (file no. 333-112033) dated Jan. 21, 2004).

12.01	(b)	Computation of Ratio of Consolidated Earnings to Consolidated Fixed Charges.

16.01	*	Letter regarding change in accountant (Exhibit 16.01 to PSCo Form 8-K (file no 001-03280) dated May 28, 2002).

31.03		Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.04		Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.02		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.01		Statement pursuant to Private Securities Litigation Reform Act of 1995.

99.02	*	Exhibit regarding the use of Arthur Andersen Audit Firm (Exhibit 99.02 to Form 10-K (file no. 001-03140) dated April 1, 2002).

(b)

Reports on Form 8-K — The following reports on Form 8-K were filed either during the three months ended Dec. 31, 2003, or between Dec. 31, 2003 and the date of this report.

None

130


	Previous Filing:			Previous Filing:
	Form; Date or	Exhibit		Form; Date or	Exhibit
Dated as of	File No.	No.	Dated as of	File No.	No.
March 14, 1941	10, 1946	B-2	Aug. 1, 1972	8-K, August 1972	2
May 14, 1941	10, 1946	B-3	June 1, 1973	8-K, June 1973	1
April 28, 1942	10, 1946	B-4	March 1, 1974	8-K, April 1974	2
April 14, 1943	10, 1946	B-5	Dec. 1, 1974	8-K, December 1974	1
April 27, 1944	10, 1946	B-6	Oct. 1, 1975	S-7, (2-60082)	2(b)(3)
April 18, 1945	10, 1946	B-7	April 28, 1976	S-7, (2-60082)	2(b)(4)
April 23, 1946	10-K, 1946	B-8	April 28, 1977	S-7, (2-60082)	2(b)(5)
April 9, 1947	10-K, 1946	B-9	Nov. 1, 1977	S-7, (2-62415)	2(b)(3)
June 1, 1947	S-1, (2-7075)	7(b)	April 28, 1978	S-7, (2-62415)	2(b)(4)
April 1, 1948	S-1, (2-7671)	7(b)(1)	Oct. 1, 1978	10-K, 1978	D(1)
May 20, 1948	S-1, (2-7671)	7(b)(2)	Oct. 1, 1979	S-7, (2-66484)	2(b)(3)
Oct. 1, 1948	10-K, 1948	4	March 1, 1980	10-K, 1980	4(c)
April 20, 1949	10-K, 1949	1	April 28, 1981	S-16, (2-74923)	4(c)
April 24, 1950	8-K, April 1950	1	Nov. 1, 1981	S-16, (2-74923)	4(c)
April 18, 1951	8-K, April 1951	1	Dec. 1, 1981	10-K, 1981	4(c)
Oct. 1, 1951	8-K, November 1951	1	April 29, 1982	10-K, 1982	4(c)
April 21, 1952	8-K, April 1952	1	May 1, 1983	10-K, 1983	4(c)
Dec. 1, 1952	S-9, (2-11120)	2(b)(9)	April 30, 1984	S-3, (2-95814)	4(c)
April 15, 1953	8-K, April 1953	2	March 1, 1985	10-K, 1985	4(c)
April 19, 1954	8-K, April 1954	1	Nov. 1, 1986	10-K, 1986	4(c)
Oct. 1, 1954	8-K, October 1954	1	May 1, 1987	10-K, 1987	4(c)
April 18, 1955	8-K, April 1955	1	July 1, 1990	S-3, (33-37431)	4(c)
April 24, 1956	10-K, 1956	1	Dec. 1, 1990	10-K, 1990	4(c)
May 1, 1957	S-9, (2-13260)	2(b)(15)	March 1, 1992	10-K, 1992	4(d)
April 10, 1958	8-K, April 1958	1	April 1, 1993	10-Q, June 30, 1993	4(a)
May 1, 1959	8-K, May 1959	2	June 1, 1993	10-Q, June 30, 1993	4(b)
April 18, 1960	8-K, April 1960	1	Nov. 1, 1993	S-3, (33-51167)	4(a)(3)
April 19, 1961	8-K, April 1961	1	Jan. 1, 1994	10-K, 1993	4(a)(3)
Oct. 1, 1961	8-K, October 1961	2	Sept. 2, 1994	8-K, September 1994	4(a)
March 1, 1962	8-K, March 1962	3(a)	May 1, 1996	10-Q, June 30, 1996	4(a)
June 1, 1964	8-K, June 1964	1	Nov. 1, 1996	10-K, 1996	4(a)(3)
May 1, 1966	8-K, May 1966	2	Feb. 1, 1997	10-Q, March 31, 1997	4(a)
July 1, 1967	8-K, July 1967	2	April 1, 1998	10-Q, March 31, 1998	4(a)
July 1, 1968	8-K, July 1968	2	Aug. 15, 2002	10-Q, Sept. 30, 2002	4.01
April 25, 1969	8-K, April 1969	1	Sept. 15, 2002	10-Q, Sept. 30, 2002	4.02
April 21, 1970	8-K, April 1970	1	Sept. 1, 2002	8-K, Sept. 18, 2002	4.02
Sept. 1, 1970	8-K, September 1970	2	March 1, 2003	S-3 April 14, 2003 (333-104504)	4(a)(3)
Feb. 1, 1971	8-K, February 1971	2	April 1, 2003	10-Q, May 15, 2003 (001-03789)	4.01
			May 1, 2003	S-4, June 11, 2003 (333-106011)	4.4
			Sept. 1, 2003	8-K, Sept. 2, 2003 (001-03280)	4.01
			Sept. 15, 2003	Xcel Energy 10-K March 15, 2004
				(001-03034)	4.99


4.03*		Indenture, dated as of Oct. 1, 1993, providing for the issuance of First Collateral Trust Bonds (Form 10-Q, Sept. 30, 1993 — Exhibit 4(a)).

4.04*		Indentures supplemental to Indenture dated as of Oct. 1, 1993:


	Previous Filing:			Previous Filing:
	Form; Date or	Exhibit		Form; Date or	Exhibit
Dated as of	File No.	No.	Dated as of	File No.	No.
Nov. 1, 1993	S-3, (33-51167)	4(b)(2)	Aug. 15, 2002	10-Q, Sept. 30, 2002	4.03
Jan. 1, 1994	10-K, 1993	4(b)(3)	Sept. 1, 2002	8-K, Sept. 18, 2002	4.01
Sept. 2, 1994	8-K, September 994	4(b)	Sept. 15, 2002	10-Q, Sept. 30, 2002	4.04
May 1, 1996	10-Q, June 30, 1996	4(b)	March 1, 2003	S-3 April 14, 2003 (333-104504)	4(b)(3)
Nov. 1, 1996	10-K, 1996	4(b)(3)	April 1, 2003	10-Q May 15, 2003 (001-03789)	4.02
Feb. 1, 1997	10-Q, March 31, 1997	4(b)	May 1, 2003	S-4, June 11, 2003 (333-106011)	4.9
April 1, 1998	10-Q, March 31, 199	4(b)	Sept 1, 2003	8-K, Sept. 2, 2003 (001-03280)	4.02
			Sept. 15, 2003	Xcel Energy 10-K, March 15,
				2004 (001-03034)	4.100


4.05	*	Indenture dated July 1, 1999, between Public Service Co. of Colorado and The Bank of New York, providing for the issuance of Senior Debt Securities and Supplemental Indenture dated July 15, 1999, between PSCo and The Bank of New York (Exhibits 4.1 and 4.2 to Form 8-K (file no. 001-03280) dated July 13, 1999).

4.06	*	Credit Agreement between Public Service Co. of Colorado, Bank One and Wells Fargo dated May 16, 2003 (Exhibit 4.02 to Form 10-Q (file no. 001-03280) dated Aug. 14, 2003).

132


4.07	*	Registration Rights Agreement dated March 14, 2003 among Public Service Co. of Colorado, Bank One Capital Markets, Inc. and UBS Warburg LLC (Exhibit 4.1 to Form S-4 (file no. 333-106011) dated June 11, 2003).

10.01	*	Amended and Restated Coal Supply Agreement entered into Oct. 1, 1984 but made effective as of Jan. 1, 1976 between Public Service Co. of Colorado and Amax Inc. on behalf of its division, Amax Coal Co. (Form 10-K, Dec. 31, 1984 — Exhibit 10(c)(1)).

10.02	*	First Amendment to Amended and Restated Coal Supply Agreement entered into May 27, 1988 but made effective Jan. 1, 1988 between Public Service Co. of Colorado and Amax Coal Co. (Form 10-K, Dec. 31, 1988 — Exhibit 10(c)(2).

12.01	(c)	Computation of Ratio of Consolidated Earnings to Consolidated Fixed Charges.

16.01	*	Letter regarding change in accountant (Exhibit 16.01 to Form 8-K (file no. 001-03280) dated May 28, 2002).

23.03		Independent Auditors’ Consent.

31.05		Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.06		Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.03		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.01		Statement pursuant to Private Securities Litigation Reform Act of 1995.

99.02	*	Exhibit regarding the use of Arthur Andersen Audit Firm (Exhibit 99.02 to Form 10-K (file no. 001-03280) dated April 1, 2002).

(b) Reports on Form 8-K — The following reports on Form 8-K were filed either during the three months ended Dec. 31, 2003, or between Dec. 31, 2003 and the date of this report.

None

SPS


(a)	1.			Financial Statements and Schedules


				Page
		Reports of Independent Auditors for the years ended Dec. 31, 2003, 2002 and 2001		54
		Statements of Income for the three years ended Dec. 31, 2003		74
		Statements of Cash Flows for the three years ended Dec. 31, 2003		75
		Balance Sheets, Dec. 31, 2003 and 2002		76
		Notes to Financial Statements		80
		Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2003, 2002 and 2001		135


2.		Exhibits

*		indicates incorporation by reference

2.01	*	Agreement and Plan of Reorganization dated Aug. 22, 1995 (Exhibit 2 to Form 8-K (file no. 001-03789) dated Aug. 22, 1995).

3.01	*	Amended and Restated Articles of Incorporation dated Sept. 30, 1997 (Exhibit 3(a)(2) to Form 10-K (file no. 001-03789) dated March 3, 1998).

3.02	*	By-laws dated Sept. 29, 1997 (Exhibit 3(b)(2) to Form 10-K (file no. 001-03789) dated March 3, 1998).

4.01	*	Indenture dated Feb. 1, 1999 between Southwestern Public Service Co. and The Chase Manhattan Bank (Exhibit B to Form 8-K (file no. 001-03789) dated Feb. 25, 1999).

4.02	*	First Supplemental Indenture dated March 1, 1999, between Southwestern Public Service Co. and The Chase Manhattan Bank (Exhibit C to Form 8-K (file no. 001-03789) dated Feb. 25, 1999).

4.03	*	Second Supplemental Indenture dated Oct. 1, 2001, between Southwestern Public Service Co. and The Chase Manhattan Bank (Exhibit 4.01 to Form 8-K (file no. 001-03789) Oct. 23, 2001).

4.04	*	Third Supplemental Indenture dated Oct 1, 2003 to the indenture dated Feb. 1, 1999 between Southwestern Public Service Co. and JPMorgan Chase Bank (Exhibit 4.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated Nov. 13, 2003).

133


4.05	*	Red River Authority for Texas Indenture of Trust dated July 1, 1991 (Form 10-K, Aug. 31, 1991 — Exhibit 4(b)).

4.06	*	Credit Agreement between Southwestern Public Service Co., Bank One National Association, Wells Fargo Bank National Association, Bank of Montreal and The Bank of New York dated Feb. 17, 2004. (Exhibit 4.107 to Xcel Energy Form 10-K (file no. 001-03034) dated March 15, 2004).

4.07	*	Registration Rights Agreement dated Oct. 6, 2003 among Southwestern Public Service Co., Citigroup Global Markets, Inc. and Credit Suisse First Boston LLC (Exhibit 4.108 to Xcel Energy Form 10-K (file no. 001-03034) dated March 15, 2004).

10.01	*	Coal Supply Agreement (Harrington Station) between Southwestern Public Service Co. and TUCO, dated May 1, 1979 (Form 8-K, May 14, 1979 — Exhibit 3).

10.02	*	Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO, dated July 1, 1978 (Form 8-K, May 14, 1979 — Exhibit 5(A)).

10.03	*	Guaranty of Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO (Form 8-K, May 14, 1979 — Exhibit 5(B)).

10.04	*	Coal Supply Agreement (Tolk Station) between Southwestern Public Service Co. and TUCO dated April 30, 1979, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, Feb. 28, 1982 — Exhibit 10(b)).

10.05	*	Master Coal Service Agreement between Wheelabrator Coal Services Co. and TUCO dated Dec. 30, 1981, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, Feb. 28, 1982 — Exhibit 10(c)).

10.06	*	Power Purchase Agreement dated May 23, 1997 between Borger Energy Associates L.P., and Southwestern Public Service Co. (Exhibit 10.48 to Xcel Energy Form 10-K (file no. 001-03034) dated March 15, 2004).

12.01	(d)	Computation of Ratio of Consolidated Earnings to Consolidated Fixed Charges.

16.01	*	Letter regarding change in accountant (Exhibit 16.01 to PSCo Form 8-K (file no. 001-03280) dated May 28, 2002).

31.07		Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.08		Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.04		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.01		Statement pursuant to Private Securities Litigation Reform Act of 1995.

99.02	*	Exhibit regarding the use of Arthur Andersen Audit Firm (Exhibit 99.02 to Form 10-K (file no. 001-03789) dated April 1, 2002).

(b) Reports on Form 8-K — The following report on Form 8-K was filed either during the three months ended Dec. 31, 2003, or between Dec. 31, 2003 and the date of this report.

Oct. 1, 2003 (filed Oct. 3, 2003) – Item 5 and 7, Other Events and Financial Statements and Exhibits – Debt offering memorandum excerpts.

134


	Exact name of Registrant as specified in its charter, State or other jurisdiction
Commission	of incorporation or organization, Address of principal executive offices and	IRS Employer
a File Number	Registrant’s Telephone Number, including area code	Identification No.

000-31387	NORTHERN STATES POWER COMPANY (a Minnesota Corporation)	41-1967505
	414 Nicollet Mall, Minneapolis, Minn. 55401
	Telephone (612) 330-5500
001-03140	NORTHERN STATES POWER COMPANY (a Wisconsin Corporation)	39-0508315
	1414 W. Hamilton Ave., Eau Claire, Wis. 54701
	Telephone (715) 839-2625
001-03280	PUBLIC SERVICE COMPANY OF COLORADO (a Colorado Corporation)	84-0296600
	1225 17th Street, Denver, Colo. 80202
	Telephone (303) 571-7511
001-03789	SOUTHWESTERN PUBLIC SERVICE COMPANY	75-0575400
	(a New Mexico Corporation)
	Tyler at Sixth, Amarillo, Texas 79101
	Telephone (303) 571-7511


Northern States Power Co.	Common Stock, $0.01 par value	1,000,000 Shares
(a Minnesota Corporation)
Northern States Power Co.	Common Stock, $100 par value	933,000 Shares
(a Wisconsin Corporation)
Public Service Co. of Colorado	Common Stock, $0.01 par value	100 Shares
Southwestern Public Service Co.	Common Stock, $1 par value	100 Shares


	Item l. Business
		COMPANY OVERVIEW
		UTILITY REGULATION
			Ratemaking Principles
			Fuel, Purchased Gas and Resource Adjustment Clauses
			Other Regulatory Mechanisms and Requirements
			Pending Regulatory Matters
		ELECTRIC UTILITY OPERATIONS
			Competition and Industry Restructuring
			Capacity and Demand
			Energy Sources
			Fuel Supply and Costs
			Trading Operations
			Nuclear Power Operations and Waste Disposal
			Electric Operating Statistics (NSP-Minnesota)
		NATURAL GAS UTILITY OPERATIONS
			Competition and Industry Restructuring
			Capability and Demand
			Natural Gas Supply and Costs
			Natural Gas Operating Statistics (NSP-Minnesota)
		ENVIRONMENTAL MATTERS
		EMPLOYEES
	Item 2. Properties
	Item 3. Legal Proceedings
	Item 4. Submission of Matters to a Vote of Security Holders
PART II
	Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
	Item 6. Selected Financial Data
	Item 7. Management’s Discussion and Analysis
	Item 7A. Quantitative and Qualitative Disclosures About Market Risk
	Item 8. Financial Statements and Supplemental Data
INDEPENDENT AUDITORS’ REPORT
	Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)
	Item 9a. Controls and Procedures
PART III
	Item 10. Directors and Executive Officers of the Registrant (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)
	Item 11. Executive Compensation (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)
	Item 12. Security Ownership of Certain Beneficial Owners and Management (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)
	Item 13. Certain Relationships and Related Transactions (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)
	Item 14. Principal Accountants Fees and Services
PART IV
	Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS)
SIGNATURES
Ratio of Earnings to Fixed Charges-NSP-Minnesota
Ratio of Earnings to Fixed Charges-NSP-Wisconsin
Ratio of Earnings to Fixed Charges-PSCo
Ratio of Earnings to Fixed Charges-SPS
Independent Auditors' Consent
Independent Auditors' Consent
Prinicpal Executive Officer's Certification
Prinicpal Financial Officer's Certification
Prinicpal Executive Officer's Certification
Prinicpal Financial Officer's Certification
Prinicpal Executive Officer's Certification
Prinicpal Financial Officer's Certification
Prinicpal Executive Officer's Certification
Prinicpal Financial Officer's Certification
Certification Pursuant to 18 U.S.C. Section 1350
Certification Pursuant to 18 U.S.C. Section 1350
Certification Pursuant to 18 U.S.C. Section 1350
Certification Pursuant to 18 U.S.C. Section 1350
Statement re: Private Securities Litigation Act


Actual Costs as a Percent of Target Costs	ROE

Less than or equal to 75%		11.47	%
Over 75% and up through 85%		11.22	%
Over 85% and up through 95%		11.00	%
Over 95% and up through 105%		10.86	%
Over 105% and up through 115%		10.55	%
Over 115% and up through 125%		10.22	%
Over 125%		9.97	%


	System Peak Demand (in megawatts)

Operating Company	2001		2002		2003		2004 Forecast

NSP System		8,344		8,259		8,289		8,278
PSCo		5,644		5,872		6,419		6,132
SPS		4,080		4,018		4,338		4,497


[X]		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


[ ]		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


			Page
			No.

PART I
Item 1 — Business				3
	COMPANY OVERVIEW
	UTILITY REGULATION
		Ratemaking Principles		4
		Fuel, Purchased Gas and Resource Adjustment Clauses		5
		Other Regulatory Mechanisms and Requirements		7
		Pending Regulatory Matters		9
	ELECTRIC UTILITY OPERATIONS
		Competition and Industry Restructuring	13
		Capacity and Demand	17
		Energy Sources	17
		Fuel Supply and Costs	19
		Trading Operations	21
		Nuclear Power Operations and Waste Disposal	21
		Electric Operating Statistics	23
	NATURAL GAS UTILITY OPERATIONS
		Competition and Industry Restructuring	26
		Capability and Demand	26
		Natural Gas Supply and Costs	27
		Natural Gas Operating Statistics	29
	ENVIRONMENTAL MATTERS		30
	EMPLOYEES		30
Item 2 — Properties			31
Item 3 — Legal Proceedings			35
Item 4 — Submission of Matters to a Vote of Security Holders			36
PART II
Item 5 — Market for Registrant’s Common Equity and Related Stockholder Matters			36
Item 6 — Selected Financial Data			37
Item 7 — Management’s Discussion and Analysis			37
Item 7A — Quantitative and Qualitative Disclosures About Market Risk			46
Item 8 — Financial Statements and Supplementary Data			49
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			125
Item 9a. Controls and Procedures			125
PART III
Item 10 — Directors and Executive Officers of the Registrant			125
Item 11 — Executive Compensation			125
Item 12 — Security Ownership of Certain Beneficial Owners and Management			125
Item 13 — Certain Relationships and Related Transactions			125
Item 14 — Principal Accountants Fees and Services			125
PART IV
Item 15 — Exhibits, Financial Statement Schedules, and Reports on Form 8-K			125
SIGNATURES			136
EXHIBIT (EXCERPT)
Ratio of Earnings to Fixed Charges
Statement Pursuant to Private Securities Litigation Reform Act
Exhibit Regarding the Use of Arthur Andersen Audit Firm


	Coal*					Nuclear
											Average
NSP System Generating Plants	Cost		Percent			Cost		Percent			Fuel Cost

2003	$	0.99		61	%	$	0.43		36	%	$	0.90
2002	$	0.96		59	%	$	0.46		38	%	$	0.81
2001	$	0.96		62	%	$	0.47		35	%	$	0.86


			Summer 2003
			Net Dependable
Station, City and Unit	Fuel	Installed	Capability (Mw)
Sherburne — Becker, Minn.
Unit 1	Coal	1976		705
Unit 2	Coal	1977		698
Unit 3(a)	Coal	1987		507
Prairie Island — Welch, Minn.
Unit 1	Nuclear	1973		541
Unit 2	Nuclear	1974		541
Monticello — Monticello, Minn	Nuclear	1971		583
King — Bayport, Minn	Coal	1968		528
Black Dog — Burnsville, Minn.
2 Units	Coal/Natural Gas	1955 - 1960		276
2 Units	Natural Gas	2002		298
High Bridge — St. Paul, Minn.
2 Units	Coal	1956 - 1959		267
Riverside — Minneapolis, Minn.
2 Units	Coal	1964 - 1987		375
Angus Anson — Sioux Falls, S.D.
2 Units	Natural Gas	1994		226
Inver Hills — Inver Grove Heights, Minn.
6 Units	Natural Gas	1972		350
Blue Lake — Shakopee, Minn.
4 Units	Natural Gas	1974		174
Other	Various	Various		324

Total				6,393



(a)		Based on NSP-Minnesota’s ownership interest of 59 percent.


			Summer 2003 Net
			Dependable
Station, City and Unit	Fuel	Installed	Capability (Mw)
Steam:
Arapahoe — Denver, Colo. 2 Units	Coal	1950 – 1955		156
Cameo — Grand Junction, Colo. 2 Units	Coal	1957 – 1960		73
Cherokee — Denver, Colo. 4 Units	Coal	1957 – 1968		717
Comanche — Pueblo, Colo. 2 Units	Coal	1973 – 1975		660
Craig — Craig, Colo. 2 Units (a)	Coal	1979 – 1980		83
Hayden — Hayden, Colo. 2 Units (b)	Coal	1965 – 1976		237
Pawnee — Brush, Colo	Coal	1981		505
Valmont — Boulder, Colo	Coal	1964		186
Zuni — Denver, Colo. 3 Units	Natural Gas/Oil	1948 – 1954		107
Combustion Turbines:
Fort St. Vrain — Platteville, Colo. 4 Units	Natural Gas	1972 – 2001		690
Various Locations 6 Units	Natural Gas	Various		185
Hydro:
Various Locations 12 Units		Various		32
Cabin Creek — Georgetown, Colo		1967		210
Pumped Storage
Wind:
Ponnequin — Weld County, Colo		1999 - 2001		—
Diesel Generators:
Cherokee — Denver, Colo. 2 Units		1967		6

Total				3,847



(a)		Based on PSCo’s ownership interest of 9.72 percent.



(b)		Based on PSCo’s ownership interest of 75.5 percent of unit 1 and 37.4 percent of unit 2.


Conductor Miles	NSP-Minnesota		NSP-Wisconsin		PSCo		SPS
500 kilovolt (kv)		2,919		—		—		—
345 kv		5,653		1,312		538		2,754
230 kv		1,442		—		10,428		9,224
161 kv		298		1,494		—		—
138 kv		—		—		92		—
115 kv		6,278		1,528		5,033		10,828
Less than 115 kv		78,372		31,076		68,805		21,672


Miles	NSP-Minnesota		NSP-Wisconsin		PSCo		SPS
Transmission		115		—		2,272		—
Distribution		8,702		1,967		18,587		—

	•		maintenance of an equity ratio of 43.74 percent to 53.46 percent;

	•		payment of dividends only from retained earnings; and

	•		debt covenant restrictions under the credit agreement for debt and interest coverage ratios.

	•		maintenance of an equity ratio of 52 percent to 57 percent; and

	•		payment of dividends only from retained earnings.

	•		maintenance of a minimum equity ratio of 30 percent;

	•		payment of dividends only from retained earnings; and

	•		debt covenant restrictions under the credit agreement for debt and interest coverage ratios.

	•		general economic conditions, including the availability of credit and its impact on capital expenditures and the ability to obtain financing on favorable terms;

	•		rating agency actions;

	•		business conditions in the energy industry;

	•		competitive factors including the extent and timing of the entry of additional competition;

	•		unusual weather;

	•		changes in federal or state legislation;

	•		geopolitical events, including war and acts of terrorism;

	•		regulation; and

	•		the other risk factors listed from time to time by the utility subsidiaries of Xcel Energy in reports filed with the SEC, including Exhibit 99.01 to this Annual Report on Form 10-K for the year ended Dec. 31, 2003.


													Accumulated
	Common Stock												Other			Total
					Premium on		Retained			Leveraged			Comprehensive			Stockholder’s
	Shares		Amount		Common Stock		Earnings			ESOP			Income (Loss)			Equity
					(Thousands of dollars, except share information)
Balance at Dec. 31, 2000		1,000,000	$	10	$	479,387	$	952,889		$	(24,617	)	$	—		$	1,407,669
Net income								207,865									207,865
Net derivative instrument fair value changes during the period, net of tax of $83														121			121
Unrealized gain-marketable securities, net of tax of $0														2			2

Comprehensive income for 2001																	207,988
Common dividends declared to parent								(170,319	)								(170,319	)
Contribution of capital by parent						282,768											282,768
Repayment of ESOP loan											6,053						6,053

Balance at Dec. 31, 2001		1,000,000		10		762,155		990,435			(18,564	)		123			1,734,159
Net income								200,222									200,222
Net derivative instrument fair value changes during the period, net of tax of $(83)														(121	)		(121	)
Unrealized loss-marketable securities, net of tax of $6														(11	)		(11	)

Comprehensive income for 2002																	200,090
Common dividends declared to parent								(203,499	)								(203,499	)
Contribution of capital by parent						51,714											51,714
Repayment of ESOP loan											18,564						18,564

Balance at Dec. 31, 2002		1,000,000		10		813,869		987,158			—			(9	)		1,801,028
Net income								192,942									192,942
Unrealized gain-marketable securities, net of tax of $(4)														5			5

Comprehensive income for 2003																	192,947
Common dividends declared to parent								(214,220	)								(214,220	)
Contribution of capital by parent						29,100											29,100

Balance at Dec. 31, 2003		1,000,000	$	10	$	842,969	$	965,880		$	—		$	(4	)	$	1,808,855



										Accumulated
	Common Stock				Premium on Common		Retained			Other Comprehensive			Total Stockholder’s
	Shares		Amount		Stock		Earnings			Income (Loss)			Equity
					(Thousands of dollars, except share information)
Balance at Dec. 31, 2000		933,000	$	93,300	$	33,418	$	263,551		$	—		$	390,269
Net income								36,392						36,392
Unrealized loss -— marketable securities, net of tax of $0											(1	)		(1	)

Comprehensive income for 2001														36,391
Common dividends declared to parent								(43,467	)					(43,467	)
Contribution of capital by parent						26,353								26,353

Balance at Dec. 31, 2001		933,000		93,300		59,771		256,476			(1	)		409,546
Net income								54,373						54,373
Unrealized loss -— marketable securities, net of tax of $0											(1	)		(1	)

Comprehensive income for 2002														54,372
Common dividends declared to parent								(48,390	)					(48,390	)
Contribution of capital by parent						3,210								3,210

Balance at Dec. 31, 2002		933,000		93,300		62,981		262,459			(2	)		418,738
Net income								57,470						57,470
Net derivative instrument fair value changes during the period, net of tax of $751											(1,122	)		(1,122	)
Unrealized gain -— marketable securities, net of tax of $0											2			2

Comprehensive income for 2003														56,350
Common dividends declared to parent								(50,413	)					(50,413	)
Contribution of capital by parent						476								476

Balance at Dec. 31, 2003		933,000	$	93,300	$	63,457	$	269,516		$	(1,122	)	$	425,151


Term of guarantee		Latest expiration 2007.

Triggering events or circumstances requiring performance under the Guarantee		Non-payment by the government entity on the underlying debt.

Current carrying amount of the liability		n/a

Nature of any recourse provisions		None

Any assets held as collateral		Security interest in the underlying loan agreements, contracts and arrangements between NSP-Minnesota and the government entities.

Guarantor		NSP-Minnesota

Guarantee amount		$0.2 million

Exposure under guarantee		$0.0 million

Nature of guarantee		Primarily bonds to guarantee restoration of sites that have been disturbed to access utility equipment.

Term of guarantee		2004 through 2005.

Triggering events or circumstances requiring performance under the guarantee		Failure of NSP-Minnesota to perform under the agreement which is the subject of the relevant bond. In addition, per the indemnity agreement between NSP-Minnesota and the various surety companies, the surety companies have the discretion to demand collateral be posted.

Current carrying amount of the liability		n/a

Nature of any recourse provisions		None

Any assets held as collateral		None

Guarantor		NSP-Wisconsin

Guarantee amount		$0.7 million

Exposure under guarantee		$0.2 million

Nature of guarantee		NSP-Wisconsin guarantees customer loans to encourage business growth and expansion.

Term of guarantee		Latest expiration in 2006.

Triggering events or circumstances requiring performance under the guarantee		Non-timely payment of the obligations or at the time the Debtor becomes the subject of bankruptcy or other insolvency proceedings.

Current carrying amount of the liability		n/a

Nature of any recourse provisions		None

Any assets held as collateral		None


			See		Remaining amortization
(Thousands of dollars)			note		period	2003		2002

Regulatory Assets:
	Net nuclear asset retirement obligations			14	End of licensed life	$	186,989	$	—
	AFDC recorded in plant (a)				Plant lives		85,552		82,697
	Purchase power contract valuation adjustments (g)			12	Term of related contract		78,446		—
	Losses on reacquired debt			1	Term of related debt		36,623		33,817
	Renewable resource costs				To be determined		25,972		26,000
	Conservation programs (a)				Up to five years		25,380		25,259
	Nuclear decommissioning costs (c)				Up to four years		16,750		20,769
	Unrecovered gas costs (b)			1	One to two years		16,008		12,296
	Other				Various		12,304		2,829
	State commission accounting adjustments (a)				Plant lives		4,604		4,732
	Environmental costs			13,14	To be determined		3,863		4,140

		Total regulatory assets				$	492,491	$	212,539

Regulatory Liabilities:
	Pension costs-regulatory differences			9		$	338,926	$	287,615
	Other asset retirement obligations			14			324,637		304,735
	Unrealized gains on decommissioning investments			14			105,518		112,145
	Deferred income tax adjustments						65,749		27,687
	Investment tax credit deferrals						45,698		50,836
	Interest on income tax refunds						6,630		5,966
	Fuel costs, refunds and other						1,994		1,786

		Total regulatory liabilities				$	889,152	$	790,770


		Regulated		Regulated
		Electric		Natural		All			Reconciling			Consolidated
		Utility		Gas Utility		Other			Eliminations			Total

		(Thousands of dollars)
2003
Operating revenues from external customers		$	2,485,022	$	667,285	$	17,180		$	—		$	3,169,487
Intersegment revenues			720		7,245		—			—			7,965

	Total revenues		2,485,742		674,530		17,180			—			3,177,452
Depreciation and amortization			318,801		31,420		3,120			—			353,341
Financing costs, mainly interest expense			117,332		18,004		10,180			(9,876	)		135,640
Income tax expense			67,104		8,965		455			—			76,524
Segment net income (loss)		$	177,333	$	17,852	$	(2,243	)	$	—		$	192,942


											Accounts
											Receivable
	NSP-		NSP-						Other		from
	Minnesota		Wisconsin		PSCo		SPS		Subsidiaries		Affiliates
(Thousands of dollars)
NSP-Minnesota	$	—	$	23,710	$	20	$	—	$	48,796	$	72,526
NSP-Wisconsin		329		—		883		—		177		1,389
PSCo		714		—		—		—		5,695		6,409
SPS		4,297		36		10,948		—		1,406		16,687
Other subsidiaries of Xcel Energy Inc.		27,544		6,874		47,281		18,893

	$	32,884	$	30,620	$	59,132	$	18,893
Accounts Payable to Affiliates	$	32,884	$	6,910	$	59,132	$	18,893
Notes Payable to Affiliates		—		23,710		—		—

	$	32,884	$	30,620	$	59,132	$	18,893


	Quarter Ended

	March 31, 2002(a)		June 30, 2002		Sept. 30, 2002		Dec. 31, 2002

			(Thousands of dollars)
Revenue	$	735,251	$	656,973	$	752,136	$	738,759
Operating income		67,370		86,279		169,418		74,917
Net income		33,033		42,424		82,992		41,773


			Additions
	Balance at		Charged		Charged		Deductions		Balance
	beginning		to costs &		to other		from		at end
	of period		expenses		accounts		reserves(1)		of period
			(Thousands of dollars)
NSP-Minnesota
Reserve deducted from related assets:
Provision for uncollectible accounts:
2003	$	5,812	$	11,762	$	4,066	$	14,059	$	7,581

2002	$	5,452	$	8,028	$	4,197	$	11,865	$	5,812

2001	$	4,952	$	6,664	$	3,697	$	9,861	$	5,452

NSP-Wisconsin
Reserve deducted from related assets:
Provision for uncollectible accounts:
2003	$	1,373	$	2,227	$	724	$	3,112	$	1,212

2002	$	969	$	2,036	$	1,083	$	2,715	$	1,373

2001	$	798	$	1,710	$	3,321	$	4,860	$	969

PSCo
Reserve deducted from related assets:
Provision for uncollectible accounts:
2003	$	13,685	$	10,447	$	8,914	$	20,194	$	12,852

2002	$	14,510	$	10,736	$	3,608	$	15,169	$	13,685

2001	$	11,352	$	12,749	$	37	$	9,628	$	14,510

SPS
Reserve deducted from related assets:
Provision for uncollectible accounts:
2003	$	1,559	$	2,712	$	852	$	3,401	$	1,722

2002	$	1,785	$	2,576	$	802	$	3,604	$	1,559

2001	$	845	$	3,057	$	—	$	2,117	$	1,785


	NSP-MINNESOTA
	/s/ BENJAMIN G.S. FOWKE III
	Benjamin G.S. Fowke III
	Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)


/s/ WAYNE H. BRUNETTI		/s/ GARY R. JOHNSON

Wayne H. Brunetti		Gary R. Johnson
Chairman and Chief Executive Officer		Vice President and General Counsel
(Principal Executive Officer)

/s/ TERESA S. MADDEN		/s/ RICHARD C. KELLY

Teresa S. Madden		Richard C. Kelly
Vice President and Controller		President and Chief Operating Officer
(Principal Accounting Officer)		(Principal Operating Officer)


/s/ MICHAEL L. SWENSON				/s/ WAYNE H. BRUNETTI

Michael L. Swenson				Wayne H. Brunetti
President and Chief Executive Officer				Chairman
(Principal Executive Officer)

/s/ TERESA S. MADDEN				/s/ GARY R. JOHNSON

Teresa S. Madden				Gary R. Johnson
Vice President and Controller				Vice President and General Counsel
(Principal Accounting Officer)

/s/ RICHARD C. KELLY

Richard C. Kelly
Vice President
(Principal Operating Officer)


				PUBLIC SERVICE COMPANY OF COLORADO

				/s/ BENJAMIN G.S. FOWKE III

				Benjamin G.S. Fowke III
				Vice President, Chief Financial Officer and Treasurer
				(Principal Financial Officer)


/s/ GARY L. GIBSON				/s/ WAYNE H. BRUNETTI

Gary L. Gibson				Wayne H. Brunetti
President and Chief Executive Officer				Chairman
(Principal Executive Officer)

/s/ TERESA S. MADDEN				/s/ GARY R. JOHNSON

Teresa S. Madden				Gary R. Johnson
Vice President and Controller				Vice President and General Counsel
(Principal Accounting Officer)

/s/ RICHARD C. KELLY

Richard C. Kelly
Vice President (Principal Operating Officer)