DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

Energy Sources and Related Transmission Initiatives

ENVIRONMENTAL MATTERS

EMPLOYEES

Projected Benefit Payments

Types of and Accounting for Derivative Instruments

Cash Flow Hedges

SCHEDULE II

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

Energy Sources and Related Transmission Initiatives

Ratemaking Principles

Capability and Demand

ENVIRONMENTAL MATTERS

EMPLOYEES

Projected Benefit Payments

Types of and Accounting for Derivative Instruments

Cash Flow Hedges

Letters of Credit

SCHEDULE II

COMPANY OVERVIEW

Management’s Discussion and Analysis of Financial Condition and Results of Operation

PUBLIC SERVICE CO. OF COLORADO

PUBLIC SERVICE CO. OF COLORADO

PUBLIC SERVICE CO. OF COLORADO

PUBLIC SERVICE CO. OF COLORADO

COMPANY OVERVIEW

Management’s Discussion and Analysis of Financial Condition and Results of Operation

PUBLIC SERVICE CO. OF COLORADO

PUBLIC SERVICE CO. OF COLORADO

PUBLIC SERVICE CO. OF COLORADO

PUBLIC SERVICE CO. OF COLORADO

SIGNATURES

Natural Gas Margin

Natural Gas Margin

Manufactured Gas Plant Site

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

ý		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
		THE SECURITIES EXCHANGE ACT OF 1934

		For the fiscal year ended December 31, 2004

OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
		THE SECURITIES EXCHANGE ACT OF 1934

		For the transition period from to

COMMISSION FILE NUMBER 001-03280

PUBLIC SERVICE COMPANY OF COLORADO

(Exact name of registrant as specified in its charter)

Colorado		84-0296600
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

1225 17th Street

Denver, Colorado 80202

(Address of principal executive offices)

(Zip Code)

(303) 571-7511

(Registrant’s telephone number, including area code)

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

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

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

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

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

As of Feb. 28, 2005, 100 shares of common stock, par value $0.01 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.

DOCUMENTS INCORPORATED BY REFERENCE: Xcel Energy Inc.’s 2005 Proxy Statement

Public Service Company of Colorado meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).

PART I

Item l — Business

*Xcel Energy Subsidiaries and Affiliates*
NSP-Minnesota		Northern States Power Co., a Minnesota corporation
NSP-Wisconsin		Northern States Power Co., a Wisconsin corporation
PSCo		Public Service Company of Colorado, a Colorado corporation
PSRI		PSR Investments, Inc.
SPS		Southwestern Public Service Co., a New Mexico corporation
Utility Subsidiaries		NSP-Minnesota, NSP-Wisconsin, PSCo, SPS
Xcel Energy		Xcel Energy Inc., a Minnesota corporation

*Federal and State Regulatory Agencies*
ATSB		Atomic Safety and Licensing Board
CPUC		Colorado Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of PSCo’s operations in Colorado. The CPUC also has jurisdiction over the capital structure and issuance of securities by PSCo.
DOE		United States Department of Energy
DOL		United States Department of Labor
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission. The U.S. agency that regulates the rates and services for transportation of electricity and natural gas, and the sale of electricity at wholesale, in interstate commerce, including the sale of electricity at market-based rates.
IRS		Internal Revenue Service
OCC		Colorado Office of Consumer Counsel
SEC		Securities and Exchange Commission

*Fuel, Purchased Gas and Resource Adjustment Clauses*
AQIR		Air-quality improvement rider. 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.
DSM		Demand-side management. Energy conservation and weatherization program for low-income customers.
DSMCA		Demand-side management cost adjustment. A clause permitting PSCo to recover demand side management costs over five years while non-labor incremental expenses and carrying costs associated with deferred DSM costs are recovered on an annual basis. Costs for the low-income energy assistance program are recovered through the DSMCA.
ECA		Electric commodity adjustment. An incentive adjustment mechanism allowing PSCo to compare 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.
GCA		Gas cost adjustment. Allows PSCo to recover its actual costs of purchased natural gas and natural gas transportation. The GCA is revised monthly to coincide with changes in purchased gas costs.
ICA		Incentive cost adjustment. A retail adjustment clause allowing PSCo to

		equally share between 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.
IAC		Interim adjustment clause.A retail adjustment clause allowing PSCo to recover prudently incurred fuel and energy costs not included in electric base rates.This clause expired Dec. 31, 2003.
PCCA		Purchased capacity cost adjustment. Allows PSCo to recover from customers purchased capacity payments to power suppliers under specifically identified power purchase agreements that are not included in the determination of PSCo’s base electric rates or other recovery mechanisms. This clause will expire on Dec. 31, 2006.
QSP		Provides for bill credits to Colorado retail customers if PSCo does not achieve certain operational performance targets.
SCA		Steam cost adjustment. 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 is revised annually to coincide with changes in fuel costs.

*Other Terms and Abbreviations*
AFDC		Allowance for funds used during construction. Defined in regulatory accounts as a non-cash accounting convention that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in property accounts and included in income.
ALJ		Administrative law judge. A judge presiding over regulatory proceedings.
ARO		Asset Retirement Obligation.
COLI		Corporate-owned life insurance.
Deferred energy costs		The amount of fuel costs applicable to service rendered in one accounting period that will not be reflected in billings to customers until a subsequent accounting period.
Derivative instrument		A financial instrument or other contract with all three of the following characteristics: • An underlying and a notional amount or payment provision or both, • Requires no initial investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar response to changes in market factors, and • Terms require or permit a net settlement, can be readily settled net by means outside the contract or provides for delivery of an asset that puts the recipient in a position not substantially different from net settlement
Distribution		The system of lines, transformers, switches and mains that connect electric and natural gas transmission systems to customers.
ERISA		Employee Retirement Income Security Act
FASB		Financial Accounting Standards Board
FTRs		Financial Transmission Rights
GAAP		Generally accepted accounting principles
Generation		The process of transforming other forms of energy, such as nuclear or fossil fuels, into electricity. Also, the amount of electric energy produced, expressed in megawatts (capacity) or megawatt hours (energy).
C20		Derivatives Implementation Group of FASB Implementation Issue No. C20. Clarified the terms clearly and closely related to normal purchases and sales contracts, as included in SFAS No. 133, as amended.
JOA		Joint operating agreement among the Utility Subsidiaries

LDC		Local distribution company. A company or division that obtains the major portion of its revenues from the operations of a retail distribution system for the delivery of electricity or natural gas for ultimate consumption.
LIBOR		London Interbank Offered Rate
LNG		Liquefied natural gas. Natural gas that has been converted to a liquid by cooling it to –260 degrees Fahrenheit.
Mark-to-market		The process whereby an asset or liability is recognized at fair value and the change in the fair value of that asset or liability is recognized in current earnings in the Consolidated Statements of Operations or in Other Comprehensive Income within equity during the current period.
MGP		Manufactured gas plant
MISO		Midwest Independent Transmission System Operator
Native load		The customer demand of retail and wholesale customers whereby a utility has an obligation to serve: e.g., an obligation to provide electric or natural gas service created by statute or long-term contract.
Natural gas		A naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geological formations beneath the earth’s surface, often in association with petroleum. The principal constituent is methane.
Nonutility		All items of revenue, expense and investment not associated, either by direct assignment or by allocation, with providing service to the utility customer.
OMOI		FERC Office of Market Oversight and Investigations
PBRP		Performance-based regulatory plan. An annual electric earnings test, an electric quality of service plan and a natural gas quality of service plan established by the CPUC.
PUHCA		Public Utility Holding Company Act of 1935. Enacted to regulate the corporate structure and financial operations of utility holding companies. Applies to companies that own or control 10% or more of a utility.
QF		Qualifying facility. As defined under the Public Utility Regulatory Policies Act of 1978, a QF sells power to a regulated utility at a price equal to that which it would otherwise pay if it were to build its own power plant or buy power from another source.
Rate base		The investor-owned plant facilities for generation, transmission and distribution and other assets used in supplying utility service to the consumer.
RCR		Renewable Cost Recovery
ROE		Return on equity
RTO		Regional Transmission Organization. An independent entity, which is established to have “functional control” over a utilities’ electric transmission systems, in order to provide non-discriminatory access to transmission of electricity.
SFAS		Statement of Financial Accounting Standards
SMA		Supply margin assessment
SMD		Standard market design
SO2		Sulfur dioxide
TEMT		Transmission and Energy Markets Tariff
TRANSLink		TRANSLink Transmission Co., LLC
Unbilled revenues		Amount of service rendered but not billed at the end of an accounting period. Cycle meter-reading practices result in unbilled consumption between the date of last meter reading and the end of the period.
Underlying		A specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event such as a scheduled payment under a contract.
VaR		Value-at-risk
Wheeling or Transmission		An electric service wherein high voltage transmission facilities of one

PSCo was incorporated in 1924 under the laws of Colorado. PSCo is an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity. PSCo also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas. PSCo serves approximately 1.3 million electric customers and approximately 1.2 million natural gas customers in Colorado.

PSCo owns the following direct subsidiaries: 1480 Welton, Inc., which owns certain real estate interests for PSCo; PSRI, which owns and manages permanent life insurance policies on certain current and former employees; and Green and Clear Lakes Company, which owns water rights. PSCo also holds a controlling interest in several other relatively small ditch and water companies whose capital requirements are not significant. PS Colorado Credit Corp., a finance company that was owned by PSCo and financed certain of PSCo’s current assets, was dissolved in 2002. PSCo owned PSCo Capital Trust I, a special purpose financing trust, for which a certificate of cancellation was filed for dissolution on Dec. 29, 2003. PSCo is a wholly owned subsidiary of Xcel Energy.

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

In 2004, Xcel Energy continuing operations included the activity of four wholly owned utility subsidiaries, including PSCo, that serve electric and natural gas customers in 10 states. The other utility subsidiaries are NSP-Minnesota, NSP-Wisconsin and SPS. These utilities serve customers in portions of Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas and Wisconsin.

ELECTRIC UTILITY OPERATIONS

Overview

Utility Industry Growth — After a decade of cost cutting and efficiency gains in anticipation of industry restructuring and competition, areas of growth for the utility industry are limited. The most significant areas for earnings growth include increasing regulated rates, increased investment in rate base, diversification, acquisition or modification of rate structures to implement performance-based rates. PSCo intends to focus on growing through investments in electric and natural gas rate base to meet growing customer demands and to maintain or increase reliability and quality of service to customers and rate case filings with state and federal regulators to increase rates congruent with increasing costs of operations associated with such investments.

Utility Restructuring and Retail Competition — The structure of the utility industry has been subject to change. Merger and acquisition activity in the past had been significant as utilities combined to capture economies of scale or establish a strategic niche in preparing for the future, although such activity slowed substantially after 2001. All investor-owned utilities were required to provide nondiscriminatory access to the use of their transmission systems in 1996. Beginning in the late 1990s, many states began studying or implementing some form of retail electric utility competition. As a result of the failure of the California power market structure and nonregulated investments of many utilities, as well as other factors, most utility retail market restructuring has ceased. No significant activity has occurred or is expected to occur in any of the retail jurisdictions in which PSCo operates.

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

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electric energy sold at wholesale,

hydro facility licensing, accounting practices and certain other activities of PSCo. State and local agencies have jurisdiction over many of PSCo’s activities, including regulation of retail rates and environmental matters.

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

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

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

As required by the FERC, Xcel Energy filed the required analysis applying the FERC’s two indicative screens on behalf of itself and the Utility Subsidiaries with the FERC on Feb. 7, 2005. This analysis demonstrated that PSCo failed the pivotal supplier analysis in its own control area and all adjacent markets, and the market share analysis in its own control area. It is accordingly expected that the FERC will set the market-rate authorizations for PSCo for investigation and hearing under Section 206 of the Federal Power Act. At that time, the PSCo expects to submit a delivered-price test analysis to support the continuance of market-based rate authority in its control area. PSCo does not expect the mitigation measures imposed, if any, to have a significant financial impact on its commodity marketing operations.

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

Electric Transmission Rate Regulation — The FERC also regulates the rates charged and terms and conditions for electric transmission services. Since 1996, the FERC has required PSCo to provide open access transmission service at rates and tariffs on file with the FERC. In addition, FERC policy encourages utilities to turn over the functional control over their electric transmission assets and the related responsibility for the sale of electric transmission services to an RTO. Each RTO separately files for regional transmission tariff rates for approval by FERC. All members within that RTO are then subjected to those rates. PSCo is currently participating with other utilities in the development of an RTO.

Generation Interconnection Rules — In August 2003, the FERC issued final rules requiring the standardization of generation interconnection procedures and agreements for interconnection of new electric generators of 20 megawatts or more to the transmission systems of all FERC-jurisdictional electric utilities, including PSCo. The FERC also established pricing rules for interconnections and related transmission system upgrades, which allow the transmission-owning utility to require the interconnecting customer to fund the interconnection costs and network upgrades required by the new generator, but require the transmission utility to provide transmission service credits, with interest, for the full amount of prepayment. The FERC required compliance filings for detailing proposed changes to PSCo’s tariff, which will govern most generation interconnections to the PSCo’s transmission system. In October 2004, the FERC accepted proposed tariff changes for PSCo, subject to certain conditions. In November 2004, PSCo submitted a compliance filing. In

December 2004, the FERC issued further modifications to the interconnection rules on rehearing and required PSCO to submit a further compliance filing by February 2005. The required compliance filing was submitted on Feb. 18, 2005.

Ratemaking Principles

Summary of Regulatory Agencies and Areas of Jurisdiction — PSCo is subject to the jurisdiction of the CPUC with respect to its facilities, rates, accounts, services and issuance of securities. PSCo is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce. PSCo has received authorization from the FERC to make wholesale electricity sales at market-based prices.

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

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

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

• Purchased Capacity Cost Adjustment (PCCA) – The PCCA, which became effective June 1, 2004, allows for recovery of purchased capacity payments to certain power suppliers under specifically identified power purchase agreements that are not included in the determination of PSCo’s base electric rates or other recovery mechanisms. The PCCA rider provided recovery of $18 million of capacity costs in 2004 and is expected to provide recovery of $31 million in 2005 and $20 million in 2006. The PCCA will expire on Dec. 31, 2006. Purchased capacity costs both from contracts included within the PCCA and from contracts not included within the PCCA are expected to be eligible for recovery through base rates, when PSCo files its next general rate case.

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

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

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

PSCo recovers fuel and purchased energy costs from its wholesale customers through a fuel cost adjustment clause accepted for filing by the FERC. In February 2004, the FERC approved a revised wholesale fuel adjustment clause for PSCo, which PSCo submitted as part of a settlement agreement with certain of its wholesale customers contesting past charges under PSCo’s prior fuel adjustment clause.

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

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

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

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

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

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

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

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

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

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

• In 2004, PSCo does not anticipate earning a return on equity in excess of 10.75 percent and did not record a refund liability. QSP results will be filed with the CPUC in April 2005. An estimated customer refund obligation under the electric QSP plan was recorded in 2004 related to the electric service unavailability measure. No refund under the natural gas QSP is anticipated.

Pending and Recently Concluded Regulatory Proceedings - FERC

PSCo and SPS FERC Transmission Rate Case — On Sept. 2, 2004, Xcel Energy filed on behalf of PSCo and SPS an application to increase wholesale transmission service and ancillary service rates within the Xcel Energy joint open access transmission tariff. PSCo and SPS are seeking an increase in annual transmission service and ancillary services revenues of $6.1 million. As a result of a settlement with certain PSCo wholesale power customers in 2003, their power sales rates would be reduced by $1.4 million. The net increase in annual revenues proposed is $4.7 million, of which $3.0 million is attributable to PSCo. In December 2004, the FERC suspended the filing and delayed the effective date of the proposed increase to May 20, 2005. The rate increase application also includes PSCo and SPS adopting an annual formula rate for transmission service pricing as previously approved by the FERC for other transmission providers. The case has been set for hearing and settlement procedures.

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

Certain California parties sought rehearing of this decision. Among other things, they asserted that the refund effective date should be set at an earlier date. They have based this request in part on the argument that the use by sellers of certain trading strategies in the California market resulted in unjust and unreasonable rates, thereby justifying an earlier refund effective date. The FERC subsequently

allowed the purchasing parties to request from sellers, including PSCo, additional information regarding the market participants’ use of certain strategies and the effect those strategies may have had on the market. Based on the additional information they obtained, these purchasing entities argued to the FERC that use of these strategies did justify an earlier refund effective date. These California entities have contended that PSCo would owe approximately $17 million in refunds, if the FERC set the earlier refund effective date. In October 2003, the FERC determined that the refund effective date should not be reset to an earlier date, and gave clarification of how refunds should be determined for the previously set refund period. Certain California parties appealed the FERC’s decision not to establish an earlier refund effective date to the United States Court of Appeals for the Ninth Circuit.

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

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

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

FERC OMOI Compliance Audit — On October 28, 2004, the OMOI sent a letter to Xcel Energy stating that OMOI had initiated a routine audit of PSCo compliance with various FERC regulations, including PSCo’s open access transmission tariff, FERC’s Order No. 889 standards of conduct rules and PSCo’s code of conduct for transactions in power and non-power goods with affiliates with market-based rates. Similar compliance audits of other utilities have resulted in compliance orders and, in certain cases, civil penalties.

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

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

Pacific Northwest FERC Refund Proceeding — In July 2001, the FERC ordered a preliminary hearing to determine whether there may have been unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for the period Dec. 25, 2000 through June 20, 2001. PSCo supplied energy to the Pacific Northwest markets during this period and has been an active participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no

refunds should be ordered. Subsequent to the ruling the FERC has allowed the parties to request additional evidence regarding the use of certain strategies and how they may have impacted the markets in the Pacific Northwest markets. For the referenced period, parties have claimed the total amount of transactions with PSCo subject to refund are $34 million.

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

Pending and Recently Concluded Regulatory Proceedings - CPUC

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

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

Quality of Service Plan — The PSCo QSP provides for bill credits to Colorado retail customers, if PSCo does not achieve certain operational performance targets. During the second quarter of 2004, PSCo filed its calendar year 2003 operating performance results for electric service unavailability, phone response time, customer complaints, accurate meter reading and natural gas leak repair time measures. PSCo did not achieve the 2003 performance targets for the electric service unavailability measure or the customer complaint measure. Additionally, PSCo filed revisions to its previously filed 2002 electric QSP results for the service unavailability measure. Based on the revised results, PSCo did not achieve the 2002 performance targets for the electric service unavailability measure, creating a bill credit obligation for 2002 and increasing the maximum bill credit obligation for subsequent years’ performance.

As of Dec. 31, 2003, PSCo had accrued an aggregate estimated bill credit obligation of $6.4 million for the 2002 and 2003 calendar years. Based on the updated information and filings discussed above, during the second quarter of 2004, PSCo increased its estimated bill credit liability for these years to $13.4 million. PSCo posted the bill credits to retail customer accounts in the third quarter of 2004. For calendar year 2004, PSCo has evaluated its performance under the QSP and has recorded a liability of $11 million. Under the electric QSP, the estimated maximum potential bill credit obligation for calendar 2004 performance is approximately $15.2 million, assuming none of the performance targets are met. The maximum potential bill credit obligation for the same period related to permanent natural gas leak repair and natural gas meter reading errors is approximately $1.6 million.

Incentive Cost Adjustment and Interim Adjustment Clause — PSCo’s ICA mechanism was in place for periods prior to 2003. The costs included in the ICA were subject to review by the CPUC. In a CPUC docket reviewing the 2001 ICA, the CPUC approved a settlement that, among other things, provided for a prospective revenue adjustment related to the maximum allowable natural gas hedging costs that would be a part of the electric commodity adjustment for 2004, which reduced 2004 rates by $4.6 million. In 2004, the CPUC approved the 2002 fuel and purchased energy costs reflected in the ICA. PSCo agreed to amortize the 2002 ICA costs over the period of June 2002 through March 2005. In 2003, PSCo’s prudently incurred fuel and purchased energy costs were fully recoverable under the IAC and are still subject to a future review by the CPUC. On Aug. 2, 2004, PSCo applied to the CPUC for approval of its 2003 fuel and purchased energy costs. This application is pending before the CPUC.

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

PSCo, the staff of the CPUC and the OCC reached full settlement of the disputed issues on Sept. 10, 2004. The CPUC approved the settlement on Oct. 5, 2004. The settlement modifies the rules governing trading transactions to provide more specificity as to

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

Capacity and Demand

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

System Peak Demand (in Megawatts)
2002	2003	2004	2005 Forecast

5,872	6,419	6,444	6,557

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

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

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

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

PSCo Resource Plan — PSCo estimates it will purchase approximately 40 percent of its total electric system energy input for 2005. Approximately 48 percent of the total system capacity for the summer 2005 system peak demand for PSCo will be provided by purchased power.

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

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

Among other things, the approved settlement allows for additional emission controls to be installed and associated costs to be collected from customers at Comanche Station’s two existing coal-fired units. The settlement contains a confidential construction cost

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

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

Purchased Transmission Services — PSCo has contractual arrangements with regional transmission service providers to deliver power and energy to the subsidiaries’ native load customers, which are retail and wholesale load obligations with terms of more than one year. Point-to-point transmission services typically include a charge for the specific amount of transmission capacity being reserved, although some agreements may base charges on the amount of metered energy delivered. Network transmission services include a charge for the metered demand at the delivery point at the time of the provider’s monthly transmission system peak, usually calculated as a 12-month rolling average.

Fuel Supply and Costs

The following table shows the delivered cost 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.

	Coal				Natural Gas				Average Fuel
	Cost		Percent		Cost		Percent		Cost

2004	$	0.89	87	%	$	5.61	13	%	$	1.52
2003	$	0.92	86	%	$	4.49	14	%	$	1.42
2002	$	0.91	79	%	$	2.25	21	%	$	1.19

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

PSCo operates the Hayden generating plant in Colorado. All of Hayden’s coal requirements are supplied under a long-term agreement. The Hayden facility is located in close proximity to a coal mine, which has historically provided the coal to fulfill Hayden’s fuel requirements under the long-term agreement. The mine operator has announced that the mine will close near the end of 2005. PSCo is currently investigating a number of alternatives to provide for an uninterrupted, economical fuel supply to the facility. It is anticipated that total fuel costs will increase following the closure of the mine, however, the amount of increased costs, if any, cannot be determined at this time. In addition to Hayden, PSCo has partial ownership in the Craig generating plant in Colorado. Approximately 70 percent of PSCo’s coal requirements for Craig are supplied by two long-term agreements.

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

PSCo has long-term coal supply agreements for the Pawnee and Comanche stations’ projected requirements. Under the long-term agreements, the supplier has dedicated specific coal reserves at the contractually defined mines to meet the contract quantity obligations. In addition, PSCo has a coal supply agreement to supply approximately 94 percent of Arapahoe station’s projected requirements for 2005. Any remaining Arapahoe station requirements will be procured via spot market purchases.

PSCo has a number of coal transportation contracts, which expire over the course of 2005. PSCo is currently in the process of negotiating new transportation agreements. The ability to negotiate for coal transportation is not anticipated to impede the operation

PSCo Electric Operating Statistics

	Year Ended Dec. 31,
	2004			2003			2002
Electric sales (Millions of Kwh):
Residential	8,066			8,251			8,129
Commercial and industrial	17,409			17,307			17,408
Public authorities and other	252			289			277
Total retail	25,727			25,847			25,814
Sales for resale	8,372			6,594			8,701
Total energy sold	34,099			32,441			34,515

Number of customers at end of period:
Residential	1,083,872			1,078,394			1,058,082
Commercial and industrial	144,111			144,991			139,573
Public authorities and other	66,797			68,452			68,601
Total retail	1,294,780			1,291,837			1,266,256
Wholesale	69			70			171
Total customers	1,294,849			1,291,907			1,266,427

Electric revenues (Thousands of dollars):
Residential	$	672,496		$	686,627		$	585,035
Commercial and industrial	1,080,660			1,059,143			866,955
Public authorities and other	36,257			38,775			32,803
Total retail	1,789,413			1,784,545			1,484,793
Wholesale	403,155			315,589			355,713
Other electric revenues	2,060			17,656			37,687
Total electric revenues	$	2,194,628		$	2,117,790		$	1,878,193

Kwh sales per retail customer	19,870			20,008			20,386
Revenue per retail customer	$	1,382.02		$	1,381.40		$	1,172.59
Residential revenue per Kwh	8.34		¢	8.32		¢	7.20		¢
Commercial and industrial revenue per Kwh	6.21		¢	6.12		¢	4.98		¢
Wholesale revenue per Kwh	4.82		¢	4.79		¢	4.09		¢

PSCo Natural Gas Operating Statistics

	Year Ended Dec. 31,
	2004		2003		2002
Natural gas deliveries (Thousands of Dth):
Residential	88,726		91,513		95,882
Commercial and industrial	38,501		41,545		43,449
Total retail	127,227		133,058		139,331
Transportation and other	102,139		104,430		120,626
Total deliveries	229,366		237,488		259,957

Number of customers at end of period:
Residential	1,111,377		1,089,958		1,063,378
Commercial and industrial	94,414		98,066		96,669
Total retail	1,205,791		1,188,024		1,160,047
Transportation and other	3,506		3,264		3,134
Total customers	1,209,297		1,191,288		1,163,181

Natural gas revenues (Thousands of dollars):
Residential	$	742,724	$	599,883	$	510,890
Commercial and industrial	288,002		240,084		192,419
Total retail	1,030,726		839,967		703,309
Transportation and other	43,263		43,085		46,046
Total natural gas revenues	$	1,073,989	$	883,052	$	749,355

Dth sales per retail customer	105.51		112.00		120.11
Revenue per retail customer	$	854.81	$	707.03	$	606.28
Residential revenue per Dth	$	8.37	$	6.56	$	5.33
Commercial and industrial revenue per Dth	$	7.48	$	5.78	$	4.43
Transportation and other revenue per Dth	$	0.42	$	0.41	$	0.38

PSCo’s 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. PSCo has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Company facilities have been designed and constructed to operate in compliance with applicable environmental standards.

PSCo strives to comply with all environmental regulations applicable to its operations. However, it is not possible at this time to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or, generally, what effect future laws or regulations may have upon its operations. For more information on environmental contingencies, see Note 12 to the Consolidated Financial Statements and the matter discussed below.

The number of full-time PSCo employees on Dec. 31, 2004 was 2,610. Of these full-time employees, 2,177, or 83 percent, are covered under collective bargaining agreements. See Note 8 to the Consolidated Financial Statements for further discussion. Xcel Energy Services Inc. a subsidiary of Xcel Energy, employees provide services to PSCo.

Item 2 — Properties

Virtually all of the utility plant of PSCo is subject to the lien of its first mortgage bond indenture.

Electric utility generating stations:

Station, City and Unit	Fuel	Installed	Summer 2004 Net Dependable 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 - Pumped Storage		1967	210
*Wind:*
Ponnequin — Weld County, Colo		1999 – 2001	—
*Diesel:*
Diesel Generators: Cherokee — Denver, Colo. 2 Units		1967	6
Total			3,847

(a) Based on PSCo’s ownership interest of 9.7 percent.

(b) Based on PSCo’s ownership interest of 75.5 percent of unit 1 and 37.4 percent of unit 2.

The dividends declared during 2004 and 2003 were as follows (thousands of dollars):

Quarter Ended
March 31, 2004		June 30, 2004		Sept. 30, 2004		Dec. 31, 2004
$	61,867	$	60,978	$	61,463	$	62,565

March 31, 2003		June 30, 2003		Sept. 30, 2003		Dec. 31, 2003
$	58,846	$	59,268	$	59,604	$	59,598

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 of Financial Condition and Results of Operations

Discussion of financial condition and liquidity for PSCo is 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 PSCo 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;

• financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the SEC, the FERC and similar entities with regulatory oversight;

• 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 PSCo in reports filed with the SEC, including Exhibit 99.01 to this Annual Report on Form 10-K for the year ended Dec. 31, 2004.

Results Of Operations

PSCo’s net income was approximately $218.0 million for 2004, compared with approximately $227.9 million for 2003.

Electric Utility, Short-Term Wholesale and Commodity Trading Margins — Electric fuel and purchased power expenses 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 energy costs do not significantly affect electric utility margin.

PSCo has two distinct forms of wholesale sales: short-term wholesale and commodity trading. Short-term wholesale refers to energy related purchase and sales activity and the use of certain financial instruments associated with the fuel required for and energy produced from PSCo’s generation assets and energy and capacity purchased to serve native load. Commodity trading is not associated with PSCo’s generation assets or the energy and capacity purchased to serve native load.

Margins from commodity trading activity conducted at PSCo are partially redistributed to NSP-Minnesota and SPS, pursuant to the JOA approved by the FERC. Margins received pursuant to the JOA are reflected as part of Base Electric Utility Revenues. Short-term wholesale and commodity trading margins reflect the impact of regulatory sharing, if applicable. Trading revenues, as discussed in Note 1 to the Consolidated Financial Statements, are reported net of trading costs (i.e., on a margin basis) in the Consolidated Statements of Income. Commodity trading costs include fuel, purchased power, transmission and other related costs. The following table details the revenue and margin for base electric utility, short-term wholesale and commodity trading activities:

(Millions of dollars)	Base Electric Utility						Short-Term Wholesale			Commodity Trading			Consolidated Totals
2004
Electric utility revenue (excluding commodity trading)	$				2,128		$	67		$	—		$	2,195
Electric fuel and purchased power	(1,181					)	(62		)	—			(1,243		)
Commodity trading revenue	—						—			472			472
Commodity trading costs	—						—			(473		)	(473		)
Gross margin before operating expenses	$			947			$	5		$	(1	)	$	951
Margin as a percentage of revenue	44.5					%	7.5		%	(0.2%		)	35.7		%

2003
Electric utility revenue (excluding commodity trading)	$		2,073				$	45		$	—		$	2,118
Electric fuel and purchased power	(1,107					)	(45		)	—			(1,152		)
Commodity trading revenue	—						—			234			234
Commodity trading costs	—						—			(235		)	(235		)
Gross margin before operating expenses	$	966					$	—		$	(1	)	$	965
Margin as a percentage of revenue	46.6					%	—		%	(0.4		)%	41.0		%

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)	2004 vs 2003
Firm wholesale volume	$	45
Estimated impact of weather	(34		)
Sales growth (excluding weather impact)	21
Other rider revenue	18
Fuel cost recovery	12
Service quality adjustment	(12		)
Capacity sales	8
Other	(3		)
Total base electric revenue increase	$	55

Base Electric Margin

(Millions of dollars)	2004 vs 2003
Estimated impact of weather	$	(26	)
Sales growth (excluding weather impact)	15
Service quality adjustment	(12		)
ECA incentive	11
Capacity sales	8
Increased capacity costs	(6		)
Regulatory accruals	(5		)
Financial hedging costs	(4		)
Firm wholesale	4
Other	(4		)
Total base electric margin decrease	$	(19	)

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. PSCo has a GCA mechanism for natural gas sales, which recognizes the majority of the effects of changes in the cost of natural gas purchased for resale and adjusts revenues to reflect such changes in costs upon request by PSCo. Therefore, fluctuations in the cost of natural gas have little effect on natural gas margin.

(Millions of dollars)	2004			2003
Natural gas utility revenue	$	1,074		$	883
Cost of natural gas sold and transported	(785		)	(578		)
Natural gas utility margin	$	289		$	305

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)	2004 vs 2003
Purchased gas adjustment clause recovery	$	207
Rate changes	(15		)
Estimated impact of weather	(3		)
Transportation and other	2
Total natural gas revenue increase	$	191

Natural gas revenue increased primarily due to higher natural gas costs in 2004, which are passed through to customers.

(Millions of dollars)	2004 vs 2003
Rate changes	$	(15	)
Estimated impact of weather	(3		)
Transportation and other	2
Total natural gas margin decrease	$	(16	)

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)	2004 vs 2003
Higher employee benefit costs	$	16.8
Lower compensation costs	(16.5		)
Inventory adjustments in 2003 and 2004	(12.8		)
Higher plant outage related costs	7.6
Higher reliability costs	5.1
Higher information technology costs	4.8
Higher costs offset in revenue	4.6
Higher customer billing system conversion related call center costs	2.1
Higher costs related to Sarbanes-Oxley and audit fees	1.6
Other	0.7
Total non-fuel operating expense decrease	$	14.0

Certain contracts within the scope of these activities qualify for hedge accounting treatment under SFAS No. 133 – “Accounting for Derivative Instruments and Hedging Activities,” as amended, while others are subject to the fair value requirements of this pronouncement.

See Note 10 to the Consolidated Financial Statements for a discussion of the various trading and hedging contracts of PSCo.

PSCo’s short-term wholesale and commodity trading operations 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 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. PSCo utilizes 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 a three-day holding period for both electricity and natural gas. Previously, PSCo calculated VaR using a holding period of five days for electricity and two days for natural gas. However, the methodology was changed to ensure consistency in risk measurement across both commodities. PSCo’s revised holding periods remain consistent with current industry practice. VaR using the current methodology for 2004 and previous methodology for 2003 are as follows:

As of Dec. 31, 2004, the calculated VaRs using the current methodology were:

Current Methodology	Year ended		During 2004
(Millions of dollars)	Dec. 31, 2004		Average		High		Low

Commodity trading (a)	$	0.29	$	0.97	$	2.09	$	0.27

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

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

Previous Methodology	Year ended		During 2003
(Millions of dollars)	Dec. 31, 2003		Average		High		Low

Electric commodity trading (a)	$	0.92	$	0.70	$	1.51	$	0.29

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

Interest Rate Risk — PSCo is subject to the risk of fluctuating interest rates in the normal course of business. PSCo’s risk management 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, subject to regulatory approval when required.

PSCo may engage in hedges of cash flow exposure. The fair value of interest rate swaps designated as cash flow hedges is 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. 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.

At Dec. 31, 2004 and 2003, a 100-basis-point change in the benchmark rate on PSCo’s variable rate debt would impact pretax interest expense by approximately $1.2 million and $0.7 million, respectively.

Credit Risk — In addition to the risks discussed previously, PSCo is exposed to credit risk. Credit risk relates to the risk of loss resulting from the nonperformance by a counterparty of its contractual obligations. PSCo maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.

PSCo conducts standard credit reviews for all counterparties. PSCo employs additional credit risk control mechanisms when

PUBLIC SERVICE CO. OF COLORADO

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended Dec. 31,
	2004			2003			2002
	(Thousands of dollars)
Operating revenues:
Electric utility	$	2,194,628		$	2,117,790		$	1,878,193
Natural gas utility	1,073,989			883,052			749,355
Steam and other	27,825			23,271			24,365
Total operating revenues	3,296,442			3,024,113			2,651,913

Operating expenses:
Electric fuel and purchased power	1,242,684			1,152,365			890,135
Cost of natural gas sold and transported	785,055			578,108			422,442
Cost of sales — steam and other	17,383			13,270			11,069
Operating and maintenance expenses	510,157			496,119			463,389
Depreciation and amortization	223,442			226,785			247,598
Taxes (other than income taxes)	86,671			83,386			77,042
Total operating expenses	2,865,392			2,550,033			2,111,675

Operating income	431,050			474,080			540,238

Other income (expense):
Interest and other income, net of nonoperating expenses (see Note 9)	24			(7,020		)	(4,641		)
Allowance for funds used during construction - equity	9,809			8,380			—
Total other income (expense)	9,833			1,360			(4,641		)

Interest charges and financing costs:
Interest charges — including financing costs of $7,353, $7,822, and $3,780, respectively	157,447			160,914			135,525
Allowance for funds used during construction - debt	(7,425		)	(8,990		)	(8,038		)
Distributions on redeemable preferred securities of subsidiary trust	—			7,372			14,744
Total interest charges and financing costs	150,022			159,296			142,231

Income before income taxes	290,861			316,144			393,366
Income taxes	72,856			88,211			128,686
Net income	$	218,005		$	227,933		$	264,680

See Notes to Consolidated Financial Statements

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended Dec. 31,
	2004			2003			2002
	(Thousands of dollars)
Operating activities:
Net income	$	218,005		$	227,933		$	264,680
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	234,164			233,915			255,712
Deferred income taxes	79,493			86,748			108,721
Amortization of investment tax credits	(4,000		)	(6,531		)	(4,665		)
Allowance for equity funds used during construction	(9,809		)	(8,380		)	24
Change in accounts receivable	(107,652		)	(52,764		)	24,763
Change in accrued unbilled revenues	(17,819		)	48,934			65,198
Change in inventories	(31,781		)	6,703			(18,091		)
Change in recoverable purchased natural gas and electric energy costs	(27,068		)	(90,227		)	(74,077		)
Change in prepayments and other current assets	(3,117		)	(23,843		)	8,881
Change in accounts payable	22,894			70,790			(61,134		)
Change in other current liabilities	(5,222		)	48,166			(56,697		)
Change in other noncurrent assets	33,783			(18,299		)	(1,038		)
Change in other noncurrent liabilities	(44,812		)	12,438			969
Net cash provided by operating activities	337,059			535,583			513,246

Investing activities:
Capital/construction expenditures	(457,365		)	(433,572		)	(443,176		)
Proceeds from disposition of property, plant and equipment	11,682			4,375			17,322
Allowance for equity funds used during construction	9,809			8,380			(24		)
Other investments	(1,691		)	(21,215		)	(2,207		)
Net cash used in investing activities	(437,565		)	(442,032		)	(428,085		)

Financing activities:
Short-term borrowings — net	182,914			(89,715		)	(488,161		)
Proceeds from issuance of long-term debt	—			815,996			593,599
Repayment of long-term debt and trust preferred securities, including reacquisition premiums	(147,000		)	(627,883		)	(18,674		)
Capital contribution from parent	184,123			145,496			62,200
Dividends paid to parent	(243,906		)	(238,268		)	(230,867		)
Net cash provided by (used in) financing activities	(23,869		)	5,626			(81,903		)

Net increase (decrease) in cash and cash equivalents	(124,375		)	99,177			3,258
Cash and cash equivalents at beginning of year	125,101			25,924			22,666
Cash and cash equivalents at end of year	$	726		$	125,101		$	25,924

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	151,424		$	143,799		$	112,179
Cash paid for income taxes (net of refunds received)	$	16,203		$	(17,589	)	$	15,255

See Notes to Consolidated Financial Statements

CONSOLIDATED BALANCE SHEETS

	Dec. 31, 2004			Dec. 31, 2003
	(Thousands of Dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	726		$	125,101
Accounts receivable – net of allowance for bad debts: $14,734 and $12,852, respectively	341,946			260,023
Accounts receivable from affiliates	19,961			6,409
Accrued unbilled revenues	172,854			155,035
Recoverable purchased natural gas and electric energy costs	172,215			167,287
Materials and supplies inventories – at average cost	44,897			41,301
Fuel inventory – at average cost	23,533			25,041
Natural gas inventory – at average cost on Dec. 31, 2004; replacement cost in excess of LIFO: $73,197 on Dec. 31, 2003 (see Note 1)	149,985			87,579
Derivative instruments valuation-at market	54,450			51,007
Prepayments and other	73,896			14,529
Total current assets	1,054,463			933,312

Property, plant and equipment, at cost:
Electric utility plant	6,123,791			5,635,907
Natural gas utility plant	1,691,895			1,556,740
Construction work in progress	200,118			468,241
Other	786,025			653,806
Total property, plant and equipment	8,801,829			8,314,694
Less accumulated depreciation	(2,862,494		)	(2,725,507		)
Net property, plant and equipment	5,939,335			5,589,187

Other assets:
Other investments	35,985			33,998
Regulatory assets	246,564			269,340
Derivative instruments valuation-at market	137,846			200,990
Deferred retail gas costs	—			10,619
Other	38,413			36,415
Total other assets	458,808			551,362
Total assets	$	7,452,606		$	7,073,861

LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	135,854		$	147,131
Short-term debt	186,300			563
Notes payable to affiliate	10,655			12,938
Accounts payable	415,652			369,974
Accounts payable to affiliates	35,865			59,132
Taxes accrued	72,446			77,679
Dividends payable to parent	62,565			59,598
Derivative instruments valuation-at market	60,586			55,845
Accrued interest	41,104			47,974
Other	87,294			94,817
Total current liabilities	1,108,321			925,651

Deferred credits and other liabilities:
Deferred income taxes	744,326			638,182
Deferred investment tax credits	66,955			70,955
Regulatory liabilities	475,136			511,100
Customers advances for construction	284,534			191,800
Minimum pension liability	62,669			54,647
Derivative instruments valuation-at market	157,130			142,557
Benefit obligations and other	87,022			87,567
Total deferred credits and other liabilities	1,877,772			1,696,808

Long-term debt	2,179,961			2,311,434
Common stockholder’s equity:
Common stock – authorized 100 shares of $0.01 par value; outstanding 100 shares	—			—
Premium on common stock	1,981,903			1,797,780
Retained earnings	392,746			421,614
Accumulated comprehensive loss	(88,097		)	(79,426		)
Total common stockholder’s equity	2,286,552			2,139,968
Commitments and contingencies (see Note 12)
Total liabilities and equity	$	7,452,606		$	7,073,861

See Notes to Consolidated Financial Statements

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

AND OTHER COMPREHENSIVE INCOME (LOSS)

									Accumulated
									Other			Total
	Common Stock			Premium on		Retained			Comprehensive			Stockholder’s
	Shares	Amount		Common Stock		Earnings			Income (Loss)			Equity
	(Thousands of dollars, except share information)

Balance at Dec. 31, 2001	100	$	—	$	1,590,084	$	404,347		$	(4,333	)	$	1,990,098
Net income						264,680						264,680
Minimum pension liability adjustment, net of deferred tax of $64,600 (see Note 8)									(105,358		)	(105,358		)
Net derivative instrument fair value changes during the period, net of tax of $3,256									5,311			5,311
Unrealized loss — marketable securities, net of tax of $76									(439		)	(439		)
Comprehensive income for 2002												164,194
Common dividends declared to parent						(238,030		)				(238,030		)
Contribution of capital by parent				62,200								62,200
Balance at Dec. 31, 2002	100	$	—	$	1,652,284	$	430,997		$	(104,819	)	$	1,978,462

Net income						227,933						227,933
Minimum pension liability adjustment, net of deferred tax of $5,467 (see Note 8)									8,917			8,917
Net derivative instrument fair value changes during the period, net of tax of $10,753									16,188			16,188
Unrealized gain — marketable securities, net of tax of $176									288			288
Comprehensive income for 2003												253,326
Common dividends declared to parent						(237,316		)				(237,316		)
Contribution of capital by parent				145,496								145,496
Balance at Dec. 31, 2003	100	$	—	$	1,797,780	$	421,614		$	(79,426	)	$	2,139,968

Net income						218,005						218,005
Minimum pension liability adjustment, net of deferred tax of $(4,202) (see Note 8)									(7,317		)	(7,317		)
Net derivative instrument fair value changes during the period, net of tax of $(947)									(1,475		)	(1,475		)
Unrealized gain — marketable securities, net of tax of $74									121			121
Comprehensive income for 2004												209,334
Common dividends declared to parent						(246,873		)				(246,873		)
Contribution of capital by parent				184,123								184,123
Balance at Dec. 31, 2004	100	$	—	$	1,981,903	$	392,746		$	(88,097	)	$	2,286,552

See Notes to Consolidated Financial Statements

CONSOLIDATED STATEMENTS OF CAPITALIZATION

	Dec. 31,
	2004			2003
	(Thousands of dollars )
Long-Term Debt
First Mortgage Bonds, Series due:
March 1, 2004, 8.125%	$	—		$	100,000
Nov. 1, 2005, 6.375%	134,500			134,500
June 1, 2006, 7.125%	125,000			125,000
April 1, 2008, 5.625%	18,000		(a)	18,000		(a)
Oct. 1, 2008, 4.375%	300,000			300,000
June 1, 2012, 5.5%	50,000		(a)	50,000		(a)
Oct. 1, 2012, 7.875%	600,000			600,000
March 1, 2013, 4.875%	250,000			250,000
April 1, 2014, 5.5%	275,000			275,000
April 1, 2014, 5.875%	61,500		(a)	61,500		(a)
Jan. 1, 2019, 5.1%	48,750		(a)	48,750		(a)
Jan. 1, 2024, 7.25%	110,000			110,000
Unsecured Senior A Notes, due July 15, 2009, 6.875%	200,000			200,000
Secured Medium-Term Notes, due Feb. 2, 2004 - March 5, 2007, 6.9% - 7.11%	100,000			145,000
Unamortized discount	(5,870		)	(6,835		)
Capital lease obligations, 11.2% due in installments through 2028	48,935			47,650
Total	2,315,815			2,458,565
Less current maturities	135,854			147,131
Total PSCo long-term debt	$	2,179,961		$	2,311,434

Common Stockholder’s Equity
Common stock — authorized 100 shares of $0.01 par value; outstanding 100 shares in 2004 and 2003	$	—		$	—
Capital in excess of par value on common stock	1,981,903			1,797,780
Retained earnings	392,746			421,614
Accumulated other comprehensive income (loss)	(88,097		)	(79,426		)
Total common stockholder’s equity	$	2,286,552		$	2,139,968

(a) Pollution control financing.

See Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Business and System of Accounts — PSCo is principally engaged in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. PSCo is subject to the regulatory provisions of the PUHCA and regulation by the FERC and state utility commissions. All of PSCo’s 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 — PSCo has subsidiaries, which have been consolidated and for which all significant intercompany transactions and balances have been eliminated.

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 on 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 estimated.

PSCo has 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, PSCo presents their revenue, net of any excise or other fiduciary-type taxes or fees. A summary of significant rate adjustment mechanisms follows:

• In 2004, PSCo generally recovered all prudently incurred electric fuel and purchased energy costs through an electric commodity adjustment clause. This fuel mechanism also has in place a sharing among customers and shareholders of certain fuel and energy costs, with an $11.25 million maximum on any cost sharing over or under an allowed electric commodity adjustment formula rate and a sharing among shareholders and customers of certain gains and losses on trading margins. In 2003, PSCo’s electric rates permitted recovery of 100 percent of prudently incurred electric fuel and purchased energy expense. In 2002, 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 Colorado, PSCo operates under an electric performance-based regulatory plan, which provides for an annual earnings test. PSCo operates under various service standards, which could require customer refunds if certain criteria are not met. PSCo’s rates include monthly adjustments for the recovery of conservation and energy management program costs, which are reviewed annually.

• PSCo sells firm power and energy in wholesale markets, which are regulated by the FERC. These rates include monthly wholesale fuel cost recovery mechanisms.

Commodity Trading Operations — All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in the Consolidated Statements of Income.

Pursuant to the JOA approved by the FERC, some of the commodity trading margins from PSCo are apportioned to NSP-Minnesota and SPS. Commodity trading activities are not associated with energy produced from PSCo’s generation assets or energy and capacity purchased to serve native load. Commodity trading results are recorded at fair market value in accordance with SFAS 133, as amended. In addition, commodity-trading results include the impacts of any margin-sharing mechanisms. For more information, see Note 10 to the Consolidated Financial Statements.

Derivative Financial Instruments — PSCo utilizes a variety of derivatives, including interest rate swaps and locks and physical and financial based commodity contracts to reduce exposure to commodity price and interest rate risks. These contracts consist mainly of commodity forwards, futures and options, index or fixed price swaps and basis swaps. For further discussion of PSCo’s risk management and derivative activities see Note 10 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 is charged to accumulated depreciation and amortization. Removal costs

associated with non-legal obligations are reclassified from accumulated depreciation and reflected as regulatory liabilities. 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.

PSCo determines 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 PSCo, expressed as a percentage of average depreciable property, for the years ended Dec. 31, 2004, 2003 and 2002 is 2.5 percent, 2.5 percent and 2.5 percent, respectively.

Allowance for Funds Used During Construction (AFDC) — AFDC 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 PSCo’s rate base for establishing utility service rates.

Decommissioning — PSCo 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.

Environmental Costs — Environmental costs are recorded when it is probable PSCo 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, 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 removal expenses, which has the latitude to compensate for final remediation costs. Removal costs recovered in rates are classified as a regulatory liability.

Legal Costs – Litigation settlements are recorded when it is probably PSCo is liable for the costs and the liability can be reasonably estimated. Legal accruals are recorded net of insurance recovery. Legal costs related to settlements are not accrued, but expensed as incurred.

Income Taxes — Xcel Energy and its utility subsidiaries, including PSCo, 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. PSCo defers 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 13 to the Consolidated Financial Statements. For more information on income taxes, see Note 7 to the Consolidated Financial Statements.

Use of Estimates — In recording transactions and balances resulting from business operations, PSCo uses 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 — PSCo considers 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.

Inventory — All inventories are recorded at average cost in 2004. Effective Jan. 1, 2004, PSCo changed its method of accounting for the cost of stored natural gas for its local distribution operations from the last-in-first-out (LIFO) pricing method to the average cost pricing method. This change in accounting was approved by the CPUC and was accounted for as a cumulative effect in accordance with the CPUC authorization. The average cost method has historically been used by PSCo for natural gas stored for use in its electric utility operations.

The cumulative effect of this change in accounting principle resulted in an increase to natural gas storage inventory and a corresponding decrease to the deferred natural gas cost accounts of approximately $36 million as of Jan. 1, 2004. Of this amount, $33 million related to current natural gas storage inventory and $3 million related to long-term natural gas storage inventory. As natural gas costs are 100 percent recoverable for PSCo’s local natural gas distribution operations under PSCo’s natural gas cost adjustment mechanism, the cumulative effect of this change had no impact on net income. Prior period financial statements were not restated since the CPUC authorized this change effective Jan. 1, 2004. Under the natural gas cost adjustment mechanism, the decrease in the cost of natural gas reduced rates to retail natural gas customers in Colorado during 2004.

Regulatory Accounting — PSCo accounts for certain income and expense items in accordance with SFAS No. 71 — “Accounting for the Effects of Certain Types of Regulation.” 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.

If restructuring or other changes in the regulatory environment occur, PSCo may no longer be eligible to apply this accounting treatment, and may be required to eliminate such regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on PSCo’s results of operations in the period the write-off is recorded. See more discussion of regulatory assets and liabilities at Note 13 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. PSCo’s deferred financing costs, net of amortization at Dec. 31, 2004, 2003 and 2002 are $15.1 million, $17.2 million, and $18.9 million, respectively.

Reclassifications - Certain items in the 2002 and 2003 statements of income and the 2003 balance sheet have been reclassified to conform to 2004 presentation.

2. Short-Term Borrowings

Credit Facilities — At Dec. 31, 2004, PSCo had the following credit facility in effect, in millions of dollars. A syndicate of lending banks supports the credit facility in exchange of a negotiated commitment fee.

Maturity	Term	Credit Line		Credit Line Available
May 2005	364 days	$	350	$	153

PSCo’s credit facility is expected to be renewed as a five-year revolving credit facility prior to May 2005 for which borrowings will be classified as a long-term liability on the consolidated balance sheet.

The line of credit provides 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. The borrowing rate under the line of credit is based on either the bank’s prime rate or the applicable London Interbank Offered Rate (LIBOR) plus a borrowing margin.

At Dec. 31, 2004, PSCo had $186 million in notes payable to banks, which was drawn on the line of credit at a weighted average interest rate of 3.40 percent. At Dec. 31, 2003, PSCo had $0.6 million in short-term debt which was not drawn on its line of credit.

Also, as discussed in Note 11 to the Consolidated Financial Statements, $11.3 million of letters of credit were outstanding at Dec. 31, 2004 under the credit facility, which further reduced amounts available under the line.

Money Pool - In 2003, Xcel Energy established a money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. PSCo received approval to participate in the money pool arrangement in 2004. The money pool allows for short-term loans between the utility subsidiaries and from the holding company to the utility subsidiaries at market-based interest rates. The money pool arrangement does not allow loans from the utility subsidiaries to the holding company. PSCo has approval to borrow up to $250 million under the arrangement. PSCo had no borrowings or loans outstanding under the arrangement at Dec. 31, 2004.

3. Long-Term Debt

Except for minor exclusions, all property of PSCo is subject to a first mortgage lien of its 1939 first mortgage indenture. All of PSCo’s electric property is subject to the lien of its 1993 first collateral trust indenture and such lien is junior to the lien of the 1939 first mortgage indenture. Both indentures are contracts between PSCo and its bondholders.

PSCo’s 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, 2004, PSCo has no sinking fund requirements for current bonds outstanding.

In February 2005, PSCo redeemed $110 million of its 7.25-percent first collateral trust bonds, originally scheduled to mature in 2024.

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

2005	$	136
2006	126
2007	101
2008	319
2009	202

4. Preferred Stock

PSCo has authorized the issue of preferred shares.

5. Mandatorily Redeemable Preferred Securities of Subsidiary Trusts

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. 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.

6. Joint Plant Ownership

Following are the investments by PSCo in jointly owned plants and the related ownership percentages as of Dec. 31, 2004:

	Plant in Service		Accumulated Depreciation		Construction Work in Progress		Ownership %
	(Thousands of dollars)

Hayden Unit 1	$	85,638	$	42,839	$	—	75.5
Hayden Unit 2	79,979		45,094		443		37.4
Hayden Common Facilities	28,600		4,815		16		53.1
Craig Units 1 and 2	58,604		31,698		33		9.7
Craig Common Facilities, Unit1, 2 and 3	32,553		9,547		18		6.5 – 9.7
Transmission and other facilities, including substations	150,812		41,171		359		11.6 – 73.0
Total PSCo	$	436,186	$	175,164	$	869

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. PSCo is responsible for the issuance of its own securities to finance its portion of the construction costs.

7. Income Taxes

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:

	2004		2003		2002

Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	3.4	%	2.9	%	2.7	%
Life insurance policies	(9.4	)%	(8.1	)%	(6.2	)%
Tax credits recognized	(2.1	)%	(2.1	)%	(3.0	)%
Regulatory differences —utility plant items	1.5	%	2.5	%	2.6	%
Resolution of income tax audits	(4.9	)%	(2.9	)%	—
Other — net	1.5	%	0.6	%	1.6	%
Effective income tax rate	25.0	%	27.9	%	32.7	%

Income taxes comprise the following expense (benefit) items:

	2004			2003			2002
	(Thousands of dollars)
Current federal tax expense (benefit)	$	(2,866	)	$	15,643		$	20,833
Current state tax expense (benefit)	2,229			(7,649		)	2,338
Current tax credits	(2,000		)	(2,498		)	(7,087		)
Deferred federal tax expense	67,700			74,885			103,108
Deferred state tax expense	11,793			11,863			14,159
Deferred investment tax credits	(4,000		)	(4,033		)	(4,665		)
Total income tax expense	$	72,856		$	88,211		$	128,686

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

	2004		2003
	(Thousands of dollars)
Deferred tax expense excluding items below	$	35,191	$	92,351
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	27,050		9,966
Tax expense (benefit) allocated to other comprehensive income and other	17,252		(15,569		)
Deferred tax expense	$	79,493	$	86,748

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

	2004		2003
	(Thousands of dollars)
Deferred tax liabilities:
Differences between book and tax basis of property	$	792,103	$	629,653
Regulatory assets	44,249		40,861
Deferred costs	46,006		74,898
Employee benefits	19,881		56,181
Other	4,002		26,345
Total deferred tax liabilities	$	906,241	$	827,938

Deferred tax assets:
Unbilled revenue	$	57,273	$	56,010
Other comprehensive income		53,776		48,760
Net operating loss carryforward	32,298		11,144
Deferred investment tax credits	25,250		26,968
Regulatory liabilities	12,852		16,447
Other	21,945		954
Total deferred tax assets	$	203,394	$	160,283
Net deferred tax liability	$	702,847	$	667,656

8. Benefit Plans and Other Postretirement Benefits

Xcel Energy offers various benefit plans to its benefit employees, including those of PSCo. Approximately 51 percent of benefit employees are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2004, PSCo had 2,177 bargaining employees covered under a collective-bargaining agreement, which expires in May 2006.

Pension Benefits

Xcel Energy has several noncontributory, defined benefit pension plans that cover almost all employees, including those of PSCo. 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. In 2004, Xcel Energy completed a review of its pension plan asset allocation and adopted revised asset allocation targets. The target range for our pension asset allocation is 60 percent in equity investments, 20 percent in fixed income investments, no cash investments and 20 percent in nontraditional investments, such as real estate, timber ventures, private equity and a diversified commodities index.

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

	2004		2003

Equity securities	69	%	75	%
Debt securities	19		14
Real estate	4		3
Cash	1		—
Nontraditional investments	7		8
	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 were closed out in December 2004.

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 12.8 percent, which is greater than 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 and includes nontraditional investments that can provide a higher-than-average return. 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 2002 were below the assumed level of 9.5 percent, but in 2003 investment returns exceeded the assumed level of 9.25 percent and in 2004 investment returns exceeded the

assumed level of 9.0 percent. Xcel Energy continually reviews its pension assumptions. For 2005, Xcel Energy has changed the investment return assumption to 8.75 percent to reflect its current expectations of investment returns.

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)	2004			2003

Accumulated Benefit Obligation at Dec. 31	$	2,575,317		$	2,512,138

Change in Projected Benefit Obligation
Obligation at Jan. 1	$	2,632,491		$	2,505,576
Service cost	58,150			67,449
Interest cost	165,361			170,731
Plan amendments	—			85,937
Actuarial loss	133,552			82,197
Settlements	(27,627		)	(9,546		)
Curtailment gain	—			(26,407		)
Benefit payments	(229,664		)	(243,446		)
Obligation at Dec. 31	$	2,732,263		$	2,632,491

Change in Fair Value of Plan Assets
Fair value of plan assets at Jan. 1	$	3,024,661		$	2,639,963
Actual return on plan assets	284,600			605,978
Employer contributions	10,046			31,712
Settlements	(27,627		)	(9,546		)
Benefit payments	(229,664		)	(243,446		)
Fair value of plan assets at Dec. 31	$	3,062,016		$	3,024,661

Funded Status of Plans at Dec. 31
Net asset	$	329,753		$	392,170
Unrecognized transition asset	—			(7		)
Unrecognized prior service cost	244,437			273,725
Unrecognized loss	176,957			9,710
Xcel Energy net pension amounts recognized on balance sheet	$	751,147		$	675,598

PSCo intangible asset recorded — prior service costs	$	4,594		$	5,724
PSCo accrued benefit liability recorded	(4,193		)	(3,096		)
PSCo minimum pension liability recorded	(62,669		)	(54,647		)
PSCo accumulated other comprehensive income recorded – pretax	167,093			155,574
PSCo accumulated other comprehensive income recorded – net of tax	103,758			96,441

Measurement Date	Dec. 31, 2004			Dec. 31, 2003

Significant Assumptions Used to Measure Benefit Obligations
Discount rate for year-end valuation	6.00		%	6.25		%
Expected average long-term increase in compensation level	3.50		%	3.50		%

During 2002, one of PSCo’s pension plans became under funded, and at Dec. 31, 2004, had projected benefit obligations of $694.4 million, exceeding plan assets of $590.1 million. PSCo has recorded a minimum pension liability of $62.7 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 $103.8 million at Dec. 31, 2004, 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, 2004.

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 2002 through 2004 for Xcel Energy’s pension plans and is not expected to require cash funding in 2005. PSCo elected to make a voluntary contribution of $30 million to its pension plan for bargaining employees in 2003 and $9 million in 2004.

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

(Thousands of dollars)	2004			2003			2002

Service cost	$	58,150		$	67,449		$	65,649
Interest cost	165,361			170,731			172,377
Expected return on plan assets	(302,958		)	(322,011		)	(339,932		)
Curtailment (gain) loss	—			(17,363		)	—
Settlement (gain) loss	(926		)	(1,135		)	—
Amortization of transition asset	(7		)	(1,996		)	(7,314		)
Amortization of prior service cost	30,009			28,230			22,663
Amortization of net gain	(15,207		)	(44,825		)	(69,264		)
Net periodic pension credit under SFAS No. 87	$	(65,578	)	$	(120,920	)	$	(155,821	)

PSCo
Net periodic pension cost (credit)	$	7,141		$	(4,728	)	$	(14,747	)

Significant Assumptions Used to Measure Costs
Discount rate	6.25		%	6.75		%	7.25		%
Expected average long-term increase in compensation level	3.50		%	4.00		%	4.50		%
Expected average long-term rate of return on assets	9.00		%	9.25		%	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 2005 pension cost calculations will be 8.75 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 contributions for PSCo were approximately $7.2 million in 2004, $4.7 million in 2003 and $5.9 million in 2002.

Postretirement Health Care Benefits

Xcel Energy has a contributory health and welfare benefit plan that provides health care and death benefits to most Xcel Energy retirees. Employees of the former NCE who retired in 2002 continue to receive employer-subsidized health care benefits.

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.

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. PSCo is required to fund SFAS No. 106 costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. In 2004, the investment strategy for the union asset fund was changed to increase the exposure to equity funds. Also, a portion of the assets contributed on behalf of non-bargaining retirees has been funded into a sub-account of the Xcel Energy pension plans. These assets are invested in a manner consistent with the investment strategy for the pension plan.

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

	2004		2003

Fixed income/debt securities	21	%	2	%
Equity and equity mutual fund securities	54		14
Cash equivalents	25		84
	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 and does 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:

(Thousands of dollars)	2004			2003

Change in Benefit Obligation
Obligation at Jan. 1	$	775,230		$	767,975
Service cost	6,100			5,893
Interest cost	52,604			52,426
Acquisitions/(divestitures)	—			(31,584		)
Plan amendments	(1,600		)	(33,304		)
Plan participants’ contributions	9,532			16,577
Actuarial loss	148,341			122,864
Curtailments	—			(249		)
Benefit payments	(61,082		)	(60,754		)
Impact of Medicare Prescription Drug, Improvement and Modernization Act of 2003	—			(64,614		)
Obligation at Dec. 31	$	929,125		$	775,230

Change in Fair Value of Plan Assets
Fair value of plan assets at Jan. 1	$	285,861		$	250,983
Actual return on plan assets	21,950			11,045
Plan participants’ contributions	9,532			16,577
Employer contributions	62,406			68,010
Benefit payments	(61,082		)	(60,754		)
Fair value of plan assets at Dec. 31	$	318,667		$	285,861

Funded Status at Dec. 31
Net obligation	$	610,458		$	489,369
Unrecognized transition asset (obligation)	(117,600		)	(133,778		)
Unrecognized prior service cost	17,914			20,093
Unrecognized gain (loss)	(383,026		)	(255,174		)
Accrued benefit liability recorded	$	127,746		$	120,510

PSCo accrued benefit liability recorded	$	44,620		$	44,455

Significant Assumptions Used to Measure Benefit Obligations
Discount rate for year-end valuation	6.00		%	6.25		%

Effective Dec. 31, 2004, Xcel Energy raised its initial medical trend assumption from 6.5 percent to 9.0 percent and lowered the ultimate trend assumption from 5.5 percent to 5.0 percent. The period until the ultimate rate is reached was also increased from two years to six years. This trend assumption was used to value the actuarial benefit obligations at year-end 2004, and will be used in 2005 retiree medical cost determinations. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by Xcel Energy’s retiree medical plan.

A 1-percent change in the assumed health care cost trend rate would have the following effects on PSCo:

(Millions of dollars)

1-percent increase in APBO components at Dec. 31, 2004	$	62.3
1-percent decrease in APBO components at Dec. 31, 2004	(51.6		)
1-percent increase in service and interest components of the net periodic cost	4.9
1-percent decrease in service and interest components of the net periodic cost	(3.9		)

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 $73 million during 2005.

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

(Thousands of dollars)	2004			2003			2002

Service cost	$	6,100		$	5,893		$	5,967
Interest cost	52,604			52,426			48,304
Expected return on plan assets	(23,066		)	(22,185		)	(21,011		)
Curtailment (gain) loss	—			(2,128		)	—
Settlement (gain) loss	—			(916		)	—
Amortization of transition obligation	14,578			15,426			16,771
Amortization of prior service cost (credit)	(2,179		)	(1,533		)	(1,130		)
Amortization of net loss (gain)	21,651			15,409			5,380
Net periodic postretirement benefit cost (credit) under SFAS No. 106	69,688			62,392			54,281

PSCo
Net periodic postretirement benefit cost recognized – SFAS No. 106	42,248			37,146			30,619
Additional cost recognized due to effects of regulation	3,891			3,883			3,890
Net cost recognized for financial reporting	$	46,139		$	41,029		$	34,509

Significant assumptions used to measure costs (income)
Discount rate	6.25		%	6.75		%	7.25		%
Expected average long-term rate of return on assets (before tax)	5.5%-8.5		%	8.0%-9.0		%	9.0		%

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.

As of Dec. 31, 2003, Xcel Energy had 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, the annual net periodic postretirement benefit cost was reduced by approximately $10 million as a result of the expected sharing of the cost of the program by Medicare, with similar savings expected in subsequent 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.

The following table lists Xcel Energy’s projected benefit payments for the pension and postretirement benefit plans.

(Thousands of dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2005	$	199,117	$	59,642	$	—	$	59,642
2006	211,830		61,652		4,297		57,355
2007	217,582		63,640		4,591		59,049
2008	225,050		65,393		4,821		60,572
2009	231,704		67,036		5,008		62,028
2010-2014	1,202,161		352,308		27,192		325,116

9. Detail of Interest and Other Income, Net of Nonoperating Expenses

Interest and other income, net of nonoperating expenses, for the years ended Dec. 31 comprises the following:

(Thousands of dollars)	2004			2003			2002

Interest income	$	9,194		$	3,240		$	1,575
Other nonoperating income	1,322			1,970			581
Gain on disposal of assets	6,583			1,765			4,622
Interest expense on corporate-owned life insurance and other employee-related insurance policies	(17,075		)	(13,995		)	(11,301		)
Other nonoperating expense	—			—			(118		)
Total interest and other income, net of nonoperating expenses	$	24		$	(7,020	)	$	(4,641	)

10. Derivative Instruments

In the normal course of business, PSCo is exposed to a variety of market risks. Market risk is the potential loss that may occur as a result of changes in the market or fair value of a particular instrument or commodity. PSCo utilizes, in accordance with approved risk management policies, a variety of derivative instruments to mitigate market risk and to enhance our operations. The use of these derivative instruments is discussed in further detail below.

Utility Commodity Price Risk — PSCo is exposed to commodity price risk in its generation and retail distribution operations. Commodity price risk is managed by entering into both long- and short-term physical purchase and sales contracts for electric power, natural gas, coal and fuel oil. Commodity risk also is managed through the use of financial derivative instruments. PSCo utilizes these derivative instruments to reduce the volatility in the cost of commodities acquired on behalf of its retail customers even though regulatory jurisdiction may provide for a dollar-for-dollar recovery of actual costs. In these instances, the use of derivative instruments is done consistently with the local jurisdictional cost recovery mechanism. PSCo’s risk management policy allows it to manage market price risk within each rate-regulated operation to the extent such exposure exists.

Short-Term Wholesale and Commodity Trading Risk — PSCo conducts various marketing and commodity trading activities, including the purchase and sale of electric capacity and energy and other energy related instruments. These activities are primarily focused on specific regions where market knowledge and experience have been obtained and are generally less than one year in length. PSCo’s risk management policy allows management to conduct the marketing activity within approved guideline and limitations as approved by our risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

PSCo uses a number of different derivative instruments in connection with its utility commodity price, interest rate, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not designated or those not qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133, as amended, are recorded at fair value. The classification of the fair value for these derivative instruments is dependent on the designation of a qualifying hedging relationship. The fair value of derivative instruments not designated in a qualifying hedging relationship is reflected in current earnings. This includes certain instruments used to mitigate market risk for PSCo and all instruments related to the commodity trading operations. The designation of a cash flow hedge permits the classification of fair value to be recorded within Other Comprehensive Income, to the extent effective. The designation of a fair value hedge permits a derivative instrument’s gains or losses to offset the related results of the hedged item in the Consolidated Statements of Income, to the extent effective.

SFAS No. 133, as amended, requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting. PSCo formally documents hedging 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. PSCo also formally assesses, both at inception and on a regular basis, if required, whether the derivative instruments being used are highly effective in offsetting changes in either the fair value or cash flows of the hedged items.

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 natural gas purchased for resale are recorded as a component of natural gas costs and hedging transactions for interest rate swaps and lock agreements are recorded as a component of interest expense. PSCo is allowed to recover in electric or natural gas rates the costs of certain financial instruments acquired to reduce commodity cost volatility.

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

The effective portion of the change in the fair value of a derivative instrument qualifying as a cash flow hedge is recognized in Other Comprehensive Income, and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. The ineffective portion of a derivative instrument’s change in fair value is recognized in current earnings.

Commodity Cash Flow Hedges — PSCo enters 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. At Dec. 31, 2004, PSCo had various commodity-related contracts classified as cash flow hedges extending through 2009. Amounts deferred from current earnings are recorded in earnings as the hedged purchase or sales transaction is settled. This could include the purchase or sale of energy and energy-related products, the use of natural gas to generate electric energy or natural gas purchased for resale.

As of Dec. 31, 2004, PSCo had no amounts accumulated in Other Comprehensive Income that are expected to be recognized in earnings during the next 12 months as the hedged transactions settle.

PSCo had no ineffectiveness related to commodity cash flow hedges during the years ended Dec. 31, 2004 and 2003, respectively.

Interest Rate Cash Flow Hedges — PSCo enters into interest rate lock agreements, including treasury-rate locks and forward starting swaps, 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.

As of Dec. 31, 2004, PSCo had net gains of approximately $1.5 million accumulated in Other Comprehensive Income that it expects to recognize in earnings during the next 12 months.

PSCo had no ineffectiveness related to interest rate cash flow hedges during the years ended Dec. 31, 2004 and 2003, respectively.

Financial Impacts of Qualifying Cash Flow Hedges — The impact of qualifying cash flow hedges on PSCo’s Other Comprehensive Income, included in the Consolidated Statements of Stockholder’s Equity, are detailed in the following table:

(Millions of dollars)

Accumulated other comprehensive loss related to hedges at Dec. 31, 2001	$	(4.3	)
After-tax net unrealized gains related to derivatives accounted for as hedges	10.3
After-tax net realized gains on derivative transactions reclassified into earnings	(5.0		)
Accumulated other comprehensive income related hedges at Dec. 31, 2002	$	1.0

After-tax net unrealized gains related to derivative accounted for as hedges	18.0
After-tax net realized gains on derivative transactions reclassified into earnings	(1.8		)
Accumulated other comprehensive income related to hedges at Dec. 31, 2003	$	17.2

After-tax net unrealized gains related to derivatives accounted for as hedges	8.6
After-tax net realized gains on derivative transactions reclassified into earnings	(10.1		)
Accumulated other comprehensive income related to hedges at Dec. 31, 2004	$	15.7

Fair Value Hedges

The effective portion of the change in the fair value of a derivative instrument qualifying as a fair value hedge is offset against the change in the fair value of the underlying asset, liability or firm commitment being hedged. That is, fair value hedge accounting allows the gains or losses of a derivative instrument to offset, in the same period, the gains and losses of the hedged item. The ineffective portion of a derivative instrument’s change in fair value is recognized in current earnings.

At Dec. 31, 2004, PSCo had no fair value hedges.

Normal Purchases or Normal Sales Contracts

PSCo enters into contracts for the purchase and sale of various commodities for use in its business operations. SFAS No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the

definition of a derivative may be exempted from SFAS No. 133, as amended, 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 purchases and normal sales contracts must have a price based on an underlying that is clearly and closely related to the asset being purchased or sold. An underlying is a specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event, such as a scheduled payment under a contract.

Contracts that meet the requirements of normal are documented and exempted from the accounting and reporting requirements of SFAS No. 133. In June 2003, C20 clarified the terms clearly and closely related to normal purchases and sales contracts, as included in SFAS No. 133, as amended. PSCo’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 liability and related regulatory asset will be amortized over the respective lives of the contracts. See Note 13 to the Consolidated Financial Statements.

PSCo evaluates all of its contracts when such contracts are entered to determine if they are derivatives and, if so, if they qualify to meet the normal designation requirements under SFAS No. 133. None of the contracts entered into within the commodity trading operations qualify for a normal designation.

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

The fair value of qualifying hedges is presented as a component of Other Comprehensive Income in the Consolidated Statements of Stockholder’s Equity. At Dec. 31, 2004 and 2003, the fair value of these contracts was $(16.4) million and $(10.6) million, respectively.

The fair value of the trading contracts as of Dec. 31, 2004 and 2003 was $(0.9) million and $0.7 million, respectively.

For a further discussion of other financial instruments at PSCo, see Note 11 to the Consolidated Financial Statements.

11. Financial Instruments

The estimated Dec. 31 fair values of PSCo’s recorded financial instruments are as follows:

	2004		2003
(Thousands of dollars)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Long—term investments	28,908	28,908	27,630	27,630
Long—term debt, including current portion	2,315,815	2,464,979	2,458,565	2,599,808

The fair value of cash and cash equivalents, notes and accounts receivable and notes and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments or because the stated rates approximate market rates. The fair values of PSCo's long-term investments are estimated based on quoted market prices for those or similar investments. The fair value of PSCo's long-term debt is 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, 2004 and 2003. 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.

PSCo provides a guarantee that guarantees payment or performance under a specified agreement. As a result, PSCo’s exposure under the guarantee is based upon the net liability under the specified agreement. The guarantee issued by PSCo limits the exposure of PSCo to a maximum amount stated in the guarantee. The guarantee requires no liability to be recorded, contains no recourse provisions and requires no collateral. On Dec. 31, 2004, PSCo had the following guarantee and exposure related to that guarantee:

(Millions of dollars)
Nature of Guarantee

Guarantor

Guarantee
Amount

Current
Exposure

Term or Expiration Date

Triggering
Event
Requiring
Performance

Assets Held as
Collateral

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

PSCo

0.5

0.0

2005

(a)

N/A

(a) 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.

Expected operating lease expenses are:

2005		2006		2007		2008		2009
(Millions of dollars)
$	14.5	$	18.6	$	19.2	$	19.7	$	21.5

Future commitments under PSCo’s two capital leases are:

	(Millions of dollars)
2005	$	7
2006	6
2007	6
2008	6
2009	6
Thereafter	74
Total minimum obligation	105
Interest	(56		)
Present value of minimum obligation	$	49

Fuel Contracts — PSCo has contracts providing for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2005 and 2025. In addition, PSCo is required to pay additional amounts depending on actual quantities shipped under these agreements. The potential risk of loss for PSCo, 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 estimated minimum purchase for PSCo under these contracts as of Dec. 31, 2004, is as follows:

Coal		Natural Gas Supply		Gas Storage & Transportation
(Millions of dollars)
$	425	$	949	$	553

Purchased Power Agreements — PSCo has 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. PSCo has various pay-for-performance contracts with expiration dates through the year 2019. 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. Certain contractual payment obligations are adjusted based on indexes. However, the effect of these price adjustments are mitigated through cost-of-energy adjustment mechanisms.

At Dec. 31, 2004, the estimated future payments for capacity that PSCo is obligated to purchase, subject to availability, are as follows (Thousands of dollars):


2005	$	423,874
2006	415,535
2007	427,790
2008	421,404
2009	389,425
2010 and thereafter	1,467,375
Total	$	3,545,403

Plant Removal Costs - PSCo records a regulatory liability for plant removal costs for generation, transmission and distribution facilities. The recording of the obligation has no income statement impact due to the deferral of adjustments, through the establishment of a regulatory asset pursuant to SFAS No. 71. Generally, the accrual of future non-legal removal obligations is not required. However, 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, PSCo has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Removal costs as of Dec. 31, 2004 and 2003 are $383 million and $351 million, respectively.

in 1998 and costs incurred by the EPA. The EPA is also expected to seek recovery from PSCo of its ongoing oversight costs. PSCo has deferred the costs recorded to date as a regulatory asset and believes that they will be recovered through future rates. Any costs that are not recoverable from customers will be expensed.

Third Party and Other Environmental Site Remediation

Asbestos Removal — Some of our facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. 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.

Federal Clean Water Act – The federal Clean Water Act addresses the environmental impacts of cooling water intakes. In July 2004, the EPA published phase II of the rule that applies to existing cooling water intakes at steam-electric power plants. The rule will require PSCo to perform additional environmental studies at 3 power plants in Colorado to determine the impact the facilities may be having on aquatic organisms vulnerable to injury. If the studies determine the plants are not meeting the new performance standards established by the phase II rule, physical and/or operational changes may be required at these plants. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the many uncertainties involved. Based on the limited information available, total capital costs to PSCo are estimated at approximately $3 million. Actual costs may be significantly higher or lower depending on issues such as the resolution of outstanding third-party legal challenges to the rule.

Industrial Boiler Maximum Achievable Control Technology Standards - On Sept. 13, 2004, the EPA published final maximum achievable control technology (MACT) standards for hazardous air pollutants from industrial boilers. The rule regulates hydrogen chloride, particulate matter, mercury and opacity. The MACT standards may apply to some generating units at PSCo, however evaluation of the potential impact is in a preliminary stage.

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 (COGCC) 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, 2004, PSCo has incurred approximately $4.8 million of costs associated with engineering buffer studies, damage claims paid to landowners and other initial closure costs. PSCo has accrued an additional $1.3 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.

In December 2003, a homeowners association petitioned the EPA to assess the threat of a natural gas release from the Leyden facility pursuant to Section 105(d) of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, (CERCLA) 42 U.S.C. section 9605. The EPA completed its review in October 2004 and concluded that the risk to nearby residents is relatively low. The EPA referred the matter to its Resource Conservation and Recovery Act program. On Nov. 24, 2004, the EPA sent a letter to the COGCC requesting that the COGCC contact Xcel Energy and request certain information concerning the closure. To date no formal request has been received by PSCo.

PSCo Notice of Violation — On Nov. 3, 1999, the U.S. Department of Justice filed suit against a number of electric utilities for alleged violations of the federal Clean Air Act’s New Source Review (NSR) requirements. The suit is related to alleged modifications of electric generating plants 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 PSCo, seeking to determine whether these utilities engaged in activities that may have been in violation of the NSR requirements. In 2001, PSCo responded to the EPA’s initial information requests.

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 plants in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process. PSCo believes it has acted in full compliance with the 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 plants 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.

Legal Contingencies

In the normal course of business, PSCo is party to routine claims and litigation arising from prior and current operations. PSCo is actively defending these matters and has recorded an estimate of the probable cost of settlement or other disposition.

Carbon Dioxide Emissions Lawsuit - On July 21, 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against five utilities, including Xcel Energy, to force reductions in carbon dioxide (CO₂) emissions. Although PSCo is not named as a party to this litigation, the requested relief that Xcel Energy cap and reduce its CO2 emissions could have a material adverse effect on PSCo. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. CO₂ is emitted whenever fossil fuel is combusted, such as in automobiles, industrial operations and coal- or gas-fired power plants. The lawsuits allege that CO₂ emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO₂ emissions. In October 2004, Xcel Energy and four other utility companies filed a motion to dismiss the lawsuit contending that the lawsuit is an attempt to usurp the policy-setting role in the U.S. Congress and the president. The ultimate financial impact of these lawsuits, if any, is not determinable at this time.

The issue of global climate change is receiving increased attention. Debate continues in the scientific community concerning the extent to which the earth’s climate is warming, the causes of climate variations that have been observed, and the ultimate impacts that might result from a changing climate. There is also considerable debate regarding public policy for the approach that the U.S. should follow to address the issue. The United Nations-sponsored Kyoto Protocol, which establishes greenhouse gas reduction targets for developed nations, entered into force on Feb. 16, 2005. President Bush has declared that the U.S. will not ratify the protocol and is opposed to legislative mandates, preferring a program based on voluntary efforts and research on new technologies. PSCo is closely monitoring the issue from both scientific and policy perspectives. While it is not possible to know the eventual outcome, PSCo believes the issue merits close attention and is taking actions it believes are prudent to be best positioned for a variety of possible future outcomes. Xcel Energy, including PSCo, is participating in a voluntary carbon management program and has established goals to reduce its volume of carbon dioxide emissions by 12 million tons by 2009 and to reduce carbon intensity by 7 percent by 2012. PSCo’s evaluation process for future generating resources incorporates the risk of future carbon limits through the use of a carbon cost adder. PSCo is also involved in other projects to improve available methods for managing carbon.

Hill, et al., vs. PSCo, et al. - 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. On Jan. 14, 2004, an action against PSCo relating to the fire in Boulder County was filed in Boulder County District Court. There are now 46 plaintiffs, including individuals and insurance companies, and three co-defendants, including PSCo. The plaintiffs assert that they are seeking in excess of $35 million in damages. PSCo believes it has insurance coverage to mitigate the liability in this matter. The ultimate financial impact to PSCo is not determinable at this time.

13. Regulatory Assets and Liabilities

PSCo’s financial statements are prepared in accordance with the provisions of SFAS No. 71, as discussed in Note 1 to the Consolidated Financial Statements. Under SFAS No. 71, regulatory assets and liabilities can be created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates. Any portion of the business that is not rate regulated cannot use SFAS No. 71 accounting. The components of unamortized regulatory assets and liabilities on the balance sheets of PSCo are:

(Thousands of dollars)	See note	Remaining amortization period	2004		2003

Regulatory Assets:
Purchase power contract valuation adjustments (c)	10	Term of related contract	$	83,981	$	75,815
Employees’ postretirement benefits other than pension	8	Three years	31,125		35,015
AFDC recorded in plant (a)		Plant lives	42,236		32,916
Conservation programs (a)		Five years	44,923		32,843
Losses on reacquired debt	1	Term of related debt	22,495		24,555
Nuclear decommissioning costs (d)		One year	7,884		20,904
Plant asset recovery (Pawnee II and Metro Ash)		2.5 years	12,258		17,162
Deferred income tax adjustments	1	Typically plant lives	—		14,205
Unrecovered electric production costs (b)		3 months	—		13,779
Other		Various	1,662		2,146
Total regulatory assets			$	246,564	$	269,340
Regulatory Liabilities:
Plant removals costs	12		$	383,035	$	350,682
Investment tax credit deferrals			40,663		43,266
Purchase power contract valuation adjustments (c)	10		26,670		117,152
Deferred income tax adjustments			24,768		—
Total regulatory liabilities			$	475,136	$	511,100

(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 recovered within the next 12 months of $16.1 million and $55.8 million for 2004 and 2003, respectively

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

14. Segment and Related Information

PSCo has two reportable segments, Regulated Electric Utility and Regulated Natural Gas Utility.

• PSCo’s Regulated Electric Utility generates, transmits and distributes electricity in Colorado. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated Electric Utility also includes PSCo’s commodity trading operations.

• PSCo’s Regulated Natural Gas Utility transports, stores and distributes natural gas in portions of 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, appliance repair services and nonutility real estate activities.

To report net income for Regulated Electric and Regulated Natural Gas Utility segments, PSCo 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.

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

	Regulated Electric Utility		Regulated Natural Gas Utility		All Other			Reconciling Eliminations			Consolidated Total
	(Thousands of dollars)
2004
Operating revenues from external customers	$	2,194,628	$	1,073,989	$	27,825		$	—		$	3,296,442
Intersegment revenues	180		69		—			(249		)	—
Total revenues	2,194,808		1,074,058		27,825			(249		)	3,296,442
Depreciation and amortization	170,337		47,167		5,938			—			223,442
Financing costs, mainly interest expense	116,686		32,033		2,409			(1,106		)	150,022
Income tax expense (benefit)	80,578		19,437		(27,159		)	—			72,856
Segment net income	$	152,870	$	58,513	$	6,622		$	—		$	218,005

2003
Operating revenues from external customers	$	2,117,790	$	883,052	$	23,271		$	—		$	3,024,113
Intersegment revenues	251		51		—			(302		)	—
Total revenues	2,118,041		883,103		23,271			(302		)	3,024,113
Depreciation and amortization	178,243		43,048		5,494			—			226,785
Financing costs, mainly interest expense	123,246		35,827		8,769			(8,546		)	159,296
Income tax expense (benefit)	95,384		20,500		(27,673		)	—			88,211
Segment net income	$	148,001	$	70,497	$	9,435		$	—		$	227,933

2002
Operating revenues from external customers	$	1,878,193	$	749,355	$	24,365		$	—		$	2,651,913
Intersegment revenues	219		41		—			(260		)	—
Total revenues	1,878,412		749,396		24,365			(260		)	2,651,913
Depreciation and amortization	192,202		53,044		2,352			—			247,598
Financing costs, mainly interest expense	109,658		32,800		15,822			(16,049		)	142,231
Income tax expense (benefit)	119,520		36,189		(27,023		)	—			128,686
Segment net income	$	184,013	$	66,874	$	13,793		$	—		$	264,680

15. Related Party Transactions

In 2003, Xcel Energy established a money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. PSCo received approval to participate in the money pool arrangement in 2004. The money pool allows for short-term loans between the utility subsidiaries and from the holding company to the utility subsidiaries at market-based interest rates. The money pool arrangement does not allow loans from the utility subsidiaries to the holding company. PSCo has approval to borrow up to $250 million under the arrangement. PSCo had no borrowings or loans outstanding under the arrangement at Dec. 31, 2004.

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy, including PSCo. 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.

Utility Engineering Corp., an Xcel Energy subsidiary, provides construction services to PSCo, for which it was paid $12.9 million in 2004, $30.1 million in 2003 and $70.8 million in 2002.

Cheyenne Light, Fuel and Power (Cheyenne), an Xcel Energy subsidiary, purchased all of its electricity requirements from PSCo. During 2004, Xcel Energy reached an agreement to sell Cheyenne. The sale was completed in January 2005.

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

(Thousands of dollars)	2004		2003		2002
Operating revenues:
Electric utility	$	48,666	$	55,855	$	57,464
Natural gas utility	—		150		311
Operating expenses:
Other operations – paid to Xcel Energy Services Inc.	298,124		259,788		208,402
Interest expense	886		1,103		1,648

Accounts receivable and payable with affiliates at Dec. 31, was:

	2004				2003
(Thousands of dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable

NSP—Minnesota	$	12,197	$	72	$	714	$	20
NSP—Wisconsin	54		—		—		883
SPS	334		1		—		10,948
Other subsidiaries of Xcel Energy Inc.	7,376		35,792		5,695		47,281
	$	19,961	$	35,865	$	6,409	$	59,132

1480 Welton, Inc., a PSCo subsidiary, had notes payable outstanding as of Dec. 31, 2004 to Xcel Energy, in the amount of $10.7 million.

16. Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
	March 31, 2004		June 30, 2004			Sept. 30, 2004				Dec. 31, 2004 (a)
	(Thousands of dollars)
Revenue	$	911,920		$	673,232		$	733,544	$		977,746
Operating income	119,004			65,965			119,992		126,089
Net income	55,166			27,932			59,105		75,802

	Quarter Ended
	March 31, 2003		June 30, 2003		Sept. 30, 2003		Dec. 31, 2003
	(Thousands of dollars)
Revenue	$	755,763	$	661,179	$	703,588		$	903,583
Operating income	147,771		85,414		122,595			118,300
Net income	70,087		33,654		57,483			66,709

(a) Fourth quarter 2004 results were increased by $13.6 million of income tax benefits related to the successful resolution of various IRS audit issues and other adjustments to current and deferred taxes related to prior years.

Item 9 — Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

During 2003 and 2004, and through the date of this report, there were no disagreements with the independent public accountants for PSCo on accounting principles or practices, financial disclosures or audit scope or procedures.

Item 9A — Controls and Procedures

Disclosure Controls and Procedures

PSCo maintains 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 PSCo’s 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.

Internal Control Over Financial Reporting

No change in PSCo’s internal control over financial reporting has occurred during PSCo’s most recent fiscal quarter that has materially affected, or is reasonably likely to affect, PSCo’s internal control over financial reporting.

Item 9B — Other Information

None

PART III

Items 10, 11, 12 and 13 of Part III of Form 10-K have been omitted from this report for PSCo 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

Item 11 — Executive Compensation

Item 12 — Security Ownership of Certain Beneficial Owners and Management

Item 13 — Certain Relationships and Related Transactions

Item 14 — Principal Accounting Fees and Services

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 2005 Annual Meeting of Shareholders, which is incorporated by reference.

PART IV

Item 15 — Exhibits, Financial Statement Schedules

1. Consolidated Financial Statements:

Reports of Independent Registered Public Accounting Firm — For the years ended Dec. 31, 2004, 2003 and 2002.

Consolidated Statements of Income — For the three years ended Dec. 31, 2004, 2003 and 2002.

Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2004, 2003 and 2002.

Consolidated Balance Sheets — As of Dec. 31, 2004 and 2003.

2. Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2004, 2003 and 2002.

3. Exhibits

*Indicates incorporation by reference

+Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors

2.01*		Merger Agreement and Plan of Reorganization dated Aug. 22, 1995 (Form 8-K, dated Aug. 22, 1995, File No. 1-3280 — Exhibit 2).
3.01*		Amended and Restated Articles of Incorporation dated July 15, 1998 (Form 10-K, Dec. 31, 1998, Exhibit 3(a)(1)).
3.02*		By-laws dated Nov. 20, 1997 (Form 10-K, Dec. 31, 1997, Exhibit 3(b)(1)).
4.01*		Indenture, dated as of Dec. 1, 1939, providing for the issuance of First Mortgage Bonds (Form 10 for 1946-Exhibit (B-1)).
4.02*		Indentures supplemental to Indenture dated as of Dec. 1, 1939:

Dated as of	Previous Filing: Form; Date or File No.	Exhibit No.		Dated as of	Previous Filing: Form; Date or File No.	Exhibit No.

March 14, 1941	10, 1946	B-2		March 1, 1974	8-K, April 1974	2
May 14, 1941	10, 1946	B-3		Dec. 1, 1974	8-K, December 1974	1
April 28, 1942	10, 1946	B-4		Oct. 1, 1975	S-7, (2-60082)	2	(b)(3)
April 14, 1943	10, 1946	B-5		April 28, 1976	S-7, (2-60082)	2	(b)(4)
April 27, 1944	10, 1946	B-6		April 28, 1977	S-7, (2-60082)	2	(b)(5)
April 18, 1945	10, 1946	B-7		Nov. 1, 1977	S-7, (2-62415)	2	(b)(3)
April 23, 1946	10-K, 1946	B-8		April 28, 1978	S-7, (2-62415)	2	(b)(4)
April 9, 1947	10-K, 1946	B-9		Oct. 1, 1978	10-K, 1978	D	(1)
June 1, 1947	S-1, (2-7075)	7	(b)	Oct. 1, 1979	S-7, (2-66484)	2	(b)(3)
April 1, 1948	S-1, (2-7671)	7	(b)(1)	March 1, 1980	10-K, 1980	4	(c)
May 20, 1948	S-1, (2-7671)	7	(b)(2)	April 28, 1981	S-16, (2-74923)	4	(c)
Oct. 1, 1948	10-K, 1948	4		Nov. 1, 1981	S-16, (2-74923)	4	(c)
April 20, 1949	10-K, 1949	1		Dec. 1, 1981	10-K, 1981	4	(c)
April 24, 1950	8-K, April 1950	1		April 29, 1982	10-K, 1982	4	(c)
April 18, 1951	8-K, April 1951	1		May 1, 1983	10-K, 1983	4	(c)
Oct. 1, 1951	8-K, November 1951	1		April 30, 1984	S-3, (2-95814)	4	(c)
April 21, 1952	8-K, April 1952	1		March 1, 1985	10-K, 1985	4	(c)
Dec. 1, 1952	S-9, (2-11120)	2	(b)(9)	Nov. 1, 1986	10-K, 1986	4	(c)
April 15, 1953	8-K, April 1953	2		May 1, 1987	10-K, 1987	4	(c)
April 19, 1954	8-K, April 1954	1		July 1, 1990	S-3, (33-37431)	4	(c)
Oct. 1, 1954	8-K, October 1954	1		Dec. 1, 1990	10-K, 1990	4	(c)
April 18, 1955	8-K, April 1955	1		March 1, 1992	10-K, 1992	4	(d)
April 24, 1956	10-K, 1956	1		April 1, 1993	10-Q, June 30, 1993	4	(a)
May 1, 1957	S-9, (2-13260)	2	(b)(15)	June 1, 1993	10-Q, June 30, 1993	4	(b)
April 10, 1958	8-K, April 1958	1		Nov. 1, 1993	S-3, (33-51167)	4	(a)(3)

May 1, 1959	8-K, May 1959	2		Jan. 1, 1994	10-K, 1993	4	(a)(3)
April 18, 1960	8-K, April 1960	1		Sept. 2, 1994	8-K, September 1994	4	(a)
April 19, 1961	8-K, April 1961	1		May 1, 1996	10-Q, June 30, 1996	4	(a)
Oct. 1, 1961	8-K, October 1961	2		Nov. 1, 1996	10-K, 1996	4	(a)(3)
March 1, 1962	8-K, March 1962	3	(a)	Feb. 1, 1997	10-Q, March 31, 1997	4	(a)
June 1, 1964	8-K, June 1964	1		April 1, 1998	10-Q, March 31, 1998	4	(a)
May 1, 1966	8-K, May 1966	2		Aug. 15, 2002	10-Q, Sept. 30, 2002	4.01
July 1, 1967	8-K, July 1967	2		Sept. 15, 2002	10-Q, Sept. 30, 2002	4.02
July 1, 1968	8-K, July 1968	2		Sept. 1, 2002	8-K, Sept. 18, 2002	4.02
April 25, 1969	8-K, April 1969	1		March 1, 2003	S-3 April 14, 2003 (333-104504)	4	(a)(3)
April 21, 1970	8-K, April 1970	1		April 1, 2003	10-Q, May 15, 2003 (001-03034)	4.01
Sept. 1, 1970	8-K, September 1970	2		May 1, 2003	S-4, June 11, 2003 (333-106011)	4.4
Feb. 1, 1971	8-K, February 1971	2		Sept. 1, 2003	8-K, Sept. 2, 2003 (001-03280)	4.01
Aug. 1, 1972	8-K, August 1972	2		Sept. 15, 2003	Xcel Energy 10-K Mar. 15, 2004 (001-03034)	4.99
June 1, 1973	8-K, June 1973	1

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:

Dated as of	Previous Filing: Form; Date or File No.	Exhibit No.		Dated as of	Previous Filing: Form; Date or File No.	Exhibit 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, 20024.01	4.01
Sept. 2, 1994	8-K, September 1994	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 (001-03034)	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, 1998	4	(b)	Sept 1, 2003	8-K, Sept. 2, 2003 (001-03280)	4.02
				Sept. 15, 2003	Xcel Energy 10-K, Mar. 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*		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).
4.07*		Credit Agreement between Public Service Co. of Colorado, Bank One NA, Wells Fargo Bank Minnesota NA and other financial institutions dated May 14, 2004 (Exhibit 4.01 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2004).
10.01*+		Xcel Energy Omnibus Incentive Plan (Exhibit A to Xcel Energy Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
10.02*+		Xcel Energy Executive Annual Incentive Award Plan (Exhibit B to Xcel Energy Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
10.03*+		Employment Agreement dated March 24, 1999, among Northern States Power Co. (a Minnesota corporation), New Century Energies, Inc. and Wayne H. Brunetti (Exhibit 10(b) to New Century Energies, Inc. Form 10-Q, (file no. 001-12927) dated March 31, 1999).
10.04*+		Amended and Restated Executive Long-Term Incentive Award Stock Plan. (Exhibit 10.02 to NSP-Minnesota Form 10-Q (file no. 001-03034) for the quarter ended March 31, 1998).
10.05*+		Stock Equivalent Plan for Non-Employee Directors of Xcel Energy As Amended and Restated Effective Oct. 1, 1997. (Exhibit 10.15 to NSP-Minnesota Form 10-K (file no. 001-03034) for the year 1997).
10.06*+		Senior Executive Severance Policy, effective March 24, 1999, between New Century Energies, Inc. and Senior Executives (Exhibit 10(a)(2) to New Century Energies, Inc. Form 10-Q, (File no. 001-12927) dated March 31, 1999).
10.07*+		New Century Energies Omnibus Incentive Plan (Exhibit A to New Century Energies, Inc. Form DEF 14A (file no. 001-12927) filed March 26, 1998).

10.08*+		Directors’ Voluntary Deferral Plan (Exhibit 10(d) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).
10.09*+		Supplemental Executive Retirement Plan (Exhibit 10(e) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).
10.10*+		Salary Deferral and Supplemental Savings Plan for Executive Officers (Exhibit 10(f) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).
10.11*+		Salary Deferral and Supplemental Savings Plan for Key Managers (Exhibit 10(g) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).
10.12*+		Supplemental Executive Retirement Plan for Key Management Employees, as amended and restated March 26, 1991 (Exhibit 10(e)(2) to PSCo Form 10-K (File no. 001-3280) dated Dec. 31, 1991).
10.13*+		Form of Key Executive Severance Agreement, as amended on Aug. 22, and Nov. 27, 1995. (Exhibit 10(e)(4) to PSCo Form 10-K (File no. 001-3280) dated Dec. 31, 1995).
10.14*+		Supplemental Retirement Income Plan as amended July 23, 1991 (Exhibit 10(d) to SPS Form 10-K, (File no. 001-03789) dated Aug. 31, 1996).
10.15*+		Xcel Energy Senior Executive Severance and Change-in Control Policy dated Oct. 22, 2003 (Exhibit 10.10 to SPS Form S-4, (file no. 333-112032) dated Jan. 21, 2004).
10.16*+		Stock Equivalent Plan for Non-employee Directors of Xcel Energy as amended and restated Jan. 1, 2004 (Exhibit B to Xcel Energy Form DEF-14A (file no. 001-03034) dated Apr. 9, 2004).
10.17*+		Xcel Energy Nonqualified Deferred Compensation Plan (2002 restatement) (Exhibit 10.23 to Xcel Energy Form 10-K (file no. 001-03034) dated March 15, 2004).
10.18*+		Xcel Energy Inc. Non-employee Directors’ Deferred Compensation Plan (Exhibit 10.24 to Xcel Energy Form 10-K (file no. 001-03034) dated March 15, 2004).
10.19*+		Xcel Energy 401(k) Savings Plan, amended and restated as of Jan. 1, 2002 (Exhibit 10.19 to SPS Form S-4 (file no. 333-112032) dated Jan. 21, 2004).
10.20*+		New Century Energies, Inc. Employee Investment Plan for Bargaining Unit Employees and Former Non-bargaining Unit Employees, as amended and restated effective Jan. 1, 2002 but with certain retroactive amendments (Exhibit 10.20 to SPS Form S-4 (file no 333-112032) dated Jan. 21, 2004).
10.21*		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).
10.22*		Securities Litigation Settlement Agreement as of Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit 10.01 to Xcel Energy Form 8-K (file no. 001-03034) dated Jan. 14, 2005).
10.23*		ERISA Actions Settlement Agreement as of Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit 10.02 to Xcel Energy Form 8-K (file no. 001-03034) dated Jan. 14, 2005).
10.24*		Shareholder Derivative Action Settlement Agreement as of Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit 10.03 to Xcel Energy Form 8-K (file no. 001-03034) dated Jan. 14, 2005).
10.25*+		Employment Agreement, effective Dec. 15, 1997, between company and Mr. Paul J. Bonavia, as amended (Exhibit 10.25 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3, 2005).
10.26*+		Compensation and reimbursement practices for Xcel Energy non-employee directors (Exhibit 10.26 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3, 2005).
10.27*+		Xcel Energy executive officer salaries, annual bonus targets and long-term compensation awards for 2005 (Exhibit 10.27 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3, 2005).
10.28*+		Amended Schedule of Participants for Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.28 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3, 2005).
10.29*+		Xcel Energy Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.29 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3, 2005).
10.30*+		Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.30 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3, 2005).
10.31*+		Xcel Energy Omnibus Incentive Plan Form of Performance Share Agreement (Exhibit 10.31 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3, 2005).
10.32*+		Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.32 to Xcel Energy Form 10-K (file no. 001-03034) dated March 3, 2005).
10.33*		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)).
10.34*		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		Statement of Computation of Ratio of Earnings to Fixed Charges.
23.01		Consent of Independent Registered Public Accounting Firm.
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.

PUBLIC SERVICE COMPANY OF COLORADO

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

Years Ended Dec. 31, 2004, 2003 and 2002

			Additions
	Balance at beginning of period		Charged to costs & expenses		Charged to other accounts		Deductions from reserves (1)		Balance at end of period
	(Thousands of dollars)
Reserve deducted from related assets:
Provision for uncollectible accounts:
2004	$	12,852	$	12,823	$	4,742	$	15,683	$	14,734
2003	$	13,685	$	10,447	$	8,914	$	20,194	$	12,852
2002	$	14,510	$	10,736	$	3,608	$	15,169	$	13,685

(1) Uncollectible accounts written off or transferred to other parties.

Supplemental information to be furnished with reports filed pursuant to Section 15(d) of the Act by Registrants which have not registered securities in pursuant to Section 12 of the Act.

PSCo has not sent, and does not expect to send, an annual report or proxy statement to its security holder.


PART I
Item 1 — Business
DEFINITIONS
COMPANY OVERVIEW
ELECTRIC UTILITY OPERATIONS
Summary of Recent Regulatory Developments
General Electric Utility Pending Regulatory Matters
Ratemaking Principles
Capacity and Demand
Energy Sources
Fuel Supply and Costs
Trading Operations
Electric Operating Statistics
NATURAL GAS UTILITY OPERATIONS
Summary of Recent Regulatory Developments
Ratemaking Principles
Capability and Demand
Natural Gas Supply and Costs
Natural Gas Operating Statistics
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 and Related Stockholder Matters
Item 6 — Selected Financial Data
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A — Quantitative and Qualitative Disclosures About Market Risk
Item 8 — Financial Statements and Supplementary Data
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A — Controls and Procedures
Item 9B — Other Information

PART III
Item 10 — Directors and Executive Officers of the Registrant
Item 11 — Executive Compensation
Item 12 — Security Ownership of Certain Beneficial Owners and Management
Item 13 — Certain Relationships and Related Transactions
Item 14 — Principal Accounting Fees and Services

PART IV
Item 15 — Exhibits, Financial Statement Schedules

SIGNATURES

		utility system are used to transmit power generated within or purchased from another system.
Working capital		Funds necessary to meet operating expenses

*Measurements*
Btu		British thermal unit. A standard unit for measuring thermal energy or heat commonly used as a gauge for the energy content of natural gas and other fuels.
Bcf		Billion cubic feet
Dth		Dekatherm (one Dth is equal to one MMBtu)
KV		Kilovolts
KW		Kilowatts
Kwh		Kilowatt hours
MMBtu		One million BTUs
MW		Megawatts (one MW equals one thousand KW)
Mwh		Megawatt hour. One Mwh equals one thousand Kwh.
Watt		A measure of power production or usage equal to the kinetic energy of an object with a mass of 2 kilograms moving with a velocity of one meter per second for one second.

Conductor Miles
345 KV		538
230 KV		10,406
138 KV		92
115 KV		5,024
Less than 115 KV		70,034

Miles
Transmission		2,287
Distribution		19,027

Preferred Shares
Authorized

Par Value

Preferred Shares
Outstanding

/S/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
March 3, 2005

		PUBLIC SERVICE COMPANY OF COLORADO

		/s/ BENJAMIN G.S. FOWKE III
		Benjamin G.S. Fowke III
		Vice President and Chief Financial Officer
		(Principal Financial Officer)

/s/ WAYNE H. BRUNETTI			/s/ GARY R. JOHNSON
Wayne H. Brunetti			Gary R. Johnson
Chief Executive Officer, Chairman and Director			Vice President, General Counsel and Director
(Principal Executive Officer)

/s/ TERESA S. MADDEN			/s/ RICHARD C. KELLY
Teresa S. Madden			Richard C. Kelly
Vice President and Controller			President, Chief Operating Officer and Director
(Principal Accounting Officer)			(Principal Operating Officer)

/s/ BENJAMIN G.S. FOWKE III
Benjamin G.S. Fowke III
Vice President and Chief Financial Officer
(Principal Financial Officer)

2004	$	6.30
2003	$	4.94
2002	$	3.17